Part II

As Enacted ( Federal Register)

Cited authorities 115

Cited in

Federal Register: October 30, 2009 (Volume 74, Number 209)

Rules and Regulations

Page 56259-56519

From the Federal Register Online via GPO Access [wais.access.gpo.gov]

DOCID:fr30oc09-16

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Part II

Environmental Protection Agency

40 CFR Parts 86, 87, 89 et al.

Mandatory Reporting of Greenhouse Gases; Final Rule

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ENVIRONMENTAL PROTECTION AGENCY 40 CFR Parts 86, 87, 89, 90, 94, 98, 1033, 1039, 1042, 1045, 1048, 1051, 1054, 1065

EPA-HQ-OAR-2008-0508; FRL-8963-5

RIN 2060-A079

Mandatory Reporting of Greenhouse Gases

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

SUMMARY: EPA is promulgating a regulation to require reporting of greenhouse gas emissions from all sectors of the economy. The final rule applies to fossil fuel suppliers and industrial gas suppliers, direct greenhouse gas emitters and manufacturers of heavy-duty and off- road vehicles and engines. The rule does not require control of greenhouse gases, rather it requires only that sources above certain threshold levels monitor and report emissions.

DATES: The final rule is effective on December 29, 2009. The incorporation by reference of certain publications listed in the rule is approved by the Director of the Federal Register as of December 29, 2009.

ADDRESSES: EPA has established a docket for this action under Docket ID

No. EPA-HQ-OAR-2008-0508. All documents in the docket are listed on the www.regulations.gov Web site. Although listed in the index, some information is not publicly available, e.g., confidential business information (CBI) or other information whose disclosure is restricted by statute. Certain other material, such as copyrighted material, is not placed on the Internet and will be publicly available only in hard copy form. Publicly available docket materials are available either electronically through www.regulations.gov or in hard copy at EPA's

Docket Center, Public Reading Room, EPA West Building, Room 3334, 1301

Constitution Avenue, NW., Washington, DC 20004. This Docket Facility is open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding legal holidays. The telephone number for the Public Reading Room is

(202) 566-1744, and the telephone number for the Air Docket is (202) 566-1742.

FOR FURTHER INFORMATION CONTACT: Carole Cook, Climate Change Division,

Office of Atmospheric Programs (MC-6207J), Environmental Protection

Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460; telephone number: (202) 343-9263; fax number: (202) 343-2342; e-mail address:

GHGReportingRule@epa.gov. For technical information and implementation materials, please go to the Web site www.epa.gov/climatechange/ emissions/ghgrulemaking.html. You may also contact the Greenhouse Gas

Reporting Rule Hotline at telephone number: (877) 444-1188; or e-mail: ghgmrr@epa.gov.

SUPPLEMENTARY INFORMATION:

Regulated Entities. The Administrator determined that this action is subject to the provisions of Clean Air Act (CAA) section 307(d). See

CAA section 307(d)(1)(V) (the provisions of section 307(d) apply to

``such other actions as the Administrator may determine.''). The final rule affects fuel and chemicals suppliers, direct emitters of greenhouse gases (GHGs) and manufacturers of mobile sources and engines. Regulated categories and entities include those listed in

Table 1 of this preamble:

Table 1--Examples of Affected Entities by Category

Examples of affected

Categories

A. Overview

Once a reporter has determined that its facility or supply operation meets any of the reporting rule applicability criteria in 40

CFR 98.2(a), the reporter must calculate and report GHG emissions or alternate information as required (e.g., suppliers report quantities supplied and the quantity of CO2e that could be emitted when the products they supply are combusted or used). The applicability threshold determination is separately assessed for suppliers (fossil fuel suppliers and industrial GHG suppliers) and downstream source categories (facilities with direct GHG emissions).

The required GHG information must be reported for all source categories at the facility for which there are measurement methods provided. For suppliers (facilities or corporations) that trigger only the applicability criteria for upstream fossil fuel or industrial GHG supply (40 CFR part 98, subparts KK through PP), reporters need only follow the methods and report the information specified in those respective subparts. For downstream facilities that contain exclusively direct emitting source categories covered in 40 CFR part 98, subparts C through JJ, and are not suppliers, reporters must monitor and report

GHG emissions the methods presented in each applicable subpart. Some reporters will need to report under multiple subparts because multiple source categories are collocated at their facility. For example, a facility with petrochemical production processes (described in Section

III.X of the preamble), should also review Sections III.C (general stationary fuel combustion), III.G (ammonia manufacturing) and III.Y

(petroleum refineries) of this preamble. In some cases, such as petroleum refineries that supply petroleum products and also meet applicability criteria for direct emissions from the refinery, reporters will have to report on both supply operations and direct facility emissions.

Table 2 of this preamble (in the SUPPLEMENTARY INFORMATION section of this preamble) provides a cross walk to aid facilities and suppliers in identifying potentially relevant source categories. The cross-walk table should only be seen as a guide as to the types of source categories that may be present in any given facility and therefore the methodological guidance in Section III of this preamble that should be reviewed. Additional source categories (beyond those listed in Table 2 of this preamble) may be relevant to a given reporter. Similarly, not all listed source categories will be relevant to all reporters.

Consistent with the requirements in the 40 CFR part 98, subpart A, reporters must report GHG emissions from all source categories located at their facility including stationary combustion 40 CFR part 98, subpart C) and process emissions (e.g., from adipic acid production, iron and steel production, and other source categories in 40 CFR subparts C through JJ), as well as the required data for any supplier source categories (KK through PP). The methods presented typically account for normal operating conditions, as well as startup, shutdown, or malfunction (SSM), where significant (e.g., HCFC-22 production and oil and gas systems). Although SSM is not specifically addressed for many source categories, emissions calculation methodologies relying on

CEMS or mass balance approaches would capture these different operating conditions.

For many facilities, calculating facility-wide emissions will simply involve adding GHG emissions from combustion sources calculated under Section III.C of this preamble (General Stationary Fuel

Combustion Sources) and process GHG emissions calculated under the applicable the source category subpart(s). The rule also clarifies reporting for more complex situations, such as where combustion and process emissions are comingled. See Section II.L of this preamble for a response to comments on the general monitoring and reporting approach for facilities with both combustion and process emissions. See sections

III.C through PP of this preamble for discussion of the specific monitoring and reporting requirements for each source category.

B. Electricity Purchases 1. Summary of the Final Rule

The final rule does not require facilities to report their electricity purchases or indirect emissions from electricity consumption. 2. Summary of Major Changes Since Proposal

There have been no changes since proposal. The proposed rule did not require reporting of electricity purchases and neither does the final rule. 3. Summary of Comments and Responses

The proposal preamble (74 FR 16479, April 10, 2009) requested comments on the value of collecting information on electricity purchases under this rule. It also outlined three options for reporting and requested comments on these options:

Option 1: Do not require any reporting on electricity purchases or associated indirect emissions from purchased electricity as part of this rule.

Option 2: Require reporting of purchased electricity from all facilities that are already required to report their GHG emissions under this rule.

Option 3: Require reporting of indirect emissions from purchased electricity for facilities that exceed a prescribed total facility emission threshold (including indirect emissions from the purchased electricity). Reporting under this option could be either in terms of electricity purchases or calculated CO2e emission based on purchased electricity.

While EPA is not including reporting requirements for electricity purchases in the final rule at this time, below we have provided a brief summary of major comments and our initial responses. As EPA considers next steps, we will be reviewing the public comments and other relevant information.

In Favor of Collecting Data on Electricity Purchases

Comment: Commenters in favor of collecting data on purchased electricity stated that collection of this data, in conjunction with data on direct emissions from facilities, will present a more comprehensive picture of emissions nationwide. They argued that collection of this data will also serve to spur investment in energy efficiency and renewable energy since companies will want to improve their emissions numbers once the information is made public. Several commenters noted that while this reporting should occur, it should happen at the corporate level,

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rather than at the facility level. Others stated that the collection should begin at a later time, perhaps in a second phase of this rule.

Response: While EPA is not collecting data on electricity purchases in this rule, we understand that acquiring such data may be important in the future. Therefore, we are exploring options for possible future data collection on electricity purchases and indirect emissions, and the uses of such data. Such a future data collection on indirect emissions would complement EPA's interest in spurring investment in energy efficiency and renewable energy. Energy efficiency is a low cost, vital first step toward reducing GHG emissions. To this end, EPA has in place several programs in which corporations and individual facilities can participate to reduce their contribution to GHG emissions through increased energy efficiency of buildings and industry. These include EPA's ENERGY STAR and Climate Leaders programs.

EPA has been working for more than a decade through the ENERGY STAR program to help companies reduce their energy use through cost- effective energy efficiency investments and practices. ENERGY STAR provides nonresidential building owners and operators and energy intensive industries with a wide variety of tools and resources to assist in their efforts to reduce building energy use. These include an online energy benchmarking and tracking tool called Portfolio Manager,

Guidelines for Energy Management, technical resources to assist in assessing building upgrades, and many others.

Through the Climate Leaders Program, EPA works corporate-wide with companies to develop comprehensive climate change strategies. Partner companies commit to reducing their impact on the global environment by completing a corporate-wide inventory of their GHG emissions based on a quality management system, setting aggressive reduction goals to be achieved over 5 to 10 years, and annually reporting their progress to

EPA. Through program participation, companies create a credible record or audit of their accomplishments and receive EPA recognition as corporate environmental leaders.

In addition to these programs that support GHG emissions reductions in both the private and public sectors, EPA's Climate and Energy State and Local Program assists governments in their clean energy efforts by providing technical assistance, analytical tools, and outreach support.

While EPA assists States in this way, we also have much to learn from their efforts. Throughout the country, States are engaged in activities on energy efficiency, energy auditing, and some collect data on electricity purchases for use in inventories and in energy efficiency programming.

Since the goal of today's rule is to collect data on emissions from downstream direct emitters and upstream production, the collection of indirect emissions will not be included at this time. In exploring the possibility of collecting data on electricity purchases nationwide, EPA will be looking to the States as examples. While facility level collection is a possibility, collection from other sources, such as load serving entities will also be explored. Moreover, the collection of indirect emissions data from the types of facilities covered by this rule (e.g., facilities and suppliers with emissions over 25,000 metric tons of CO2e) would not provide the complete picture or focus on the types of facilities that likely have large indirect emissions. Reports from additional facilities could be required in any future data collection.

Against Collecting Data on Electricity Purchases

Comment: Many commenters were against the collection of data on purchased electricity for several reasons. Primarily they felt it would constitute double counting if electricity data are collected from electric utilities and EPA also collects the same data from facilities and adds it together. Others stated that collecting information on electricity purchases was outside the scope of the rule, that it is not useful information in attempting to quantify emissions, that it would be burdensome for facilities, and that it is CBI that companies are not able to share with EPA. Those commenters suggested instead the data should come from utilities, as EPA proposed.

Response: The final rule does not require facilities to report their electricity purchases or indirect emissions from electricity consumption. While EPA is not collecting data on electricity purchases in this rule, we understand that acquiring such data may be important in the future. Therefore, we are exploring options for possible future data collection on electricity purchases and indirect emissions, and the uses of such data. In the event that a future data collection effort is pursued, EPA will consider the issues raised by these commenters with regard to the most effective source for this data, and methods to reduce burden on reporting entities.

With regard to, double reporting and/or double counting of the same data, the data collected under this rule is consistent with the appropriations language, and provides valuable information to EPA and stakeholders in the development of climate change policy and programs.

Policies such as low carbon fuel standards can only be applied upstream, whereas end use emission standards can only be applied downstream. Data from upstream and downstream sources would be necessary to formulate and assess the impacts of such potential policies. Eliminating reporting by either upstream or downstream sources would not satisfy EPA's data needs and policy objectives of this rule. Any future rule makings to collect data on electricity purchases and indirect emissions will follow a similar approach in order to inform policy decisions.

With regard to CBI, EPA recognizes the importance of this issue to both reporters and the public. EPA's public information regulations contain a definition of ``emissions data'' at 40 CFR 2.301, and EPA has discussed in an earlier Federal Register notice what data elements constitute emissions data that cannot be considered CBI (56 FR 7042- 7043, February 21, 1991).

As explained in Section II.R. of this preamble, EPA intends to undertake a similar effort regarding the data elements collected in this rule, and any subsequent rules. Through a notice and comment process, we will establish those data elements that are ``emissions data'' and therefore will not be afforded the protections of CBI.

C. General Stationary Fuel Combustion Sources 1. Summary of the Final Rule

Source Category Definition. Stationary fuel combustion sources are devices that combust any solid, liquid, or gaseous fuel to:

Produce electricity, steam, useful heat, or energy for industrial, commercial, or institutional use; or

Reduce the volume of waste by removing combustible matter.

These devices include, but are not limited to, boilers, combustion turbines, engines, incinerators, and process heaters.

Portable equipment, emergency generators, and emergency equipment are excluded from this source category. Stationary combustion devices that combust hazardous waste must report emissions only from the co- firing of any fuels that are covered by 40 CFR part 98, subpart C.

Flares are also excluded from subpart 40 CFR part 98, subpart C. Flare emissions must be reported only if

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required by the provisions of another subpart of part 98.

Reporters must submit annual GHG reports for stationary fuel combustion units if the facility meets the applicability criteria in the General Provisions (40 CFR 98.2) as summarized in Section II.A of this preamble.

EGUs that are subject to the ARP and other EGUs that are required to monitor and report to EPA CO2mass emissions year-round according to 40 CFR part 75, are covered under 40 CFR part 98, subpart

D (Electricity Generation).

GHGs to Report. For stationary fuel combustion, report:

CO2, CH4, and N2O emissions from each stationary fuel combustion unit. For each unit,

CO2, CH4, and N2O emissions must be reported for each fuel combusted (including biomass). Reporters can aggregate emissions from multiple units in certain cases.

Facility-level CO2emissions from combustion of biomass (in addition to unit-level reporting).

GHG Emissions Calculation and Monitoring. Reporters must use the following methodologies to calculate emissions:

Calculating CO2Emissions from Combustion:

Calculate CO2emissions using one of four methodological tiers, subject to certain restrictions based on unit size, type of fuel burned, and other factors. For each Tier, CO2mass emissions are determined as follows:

--Tier 1: Use annual fuel consumption (from company records) together with fuel-specific default high heat values and default CO2 emission factors.

--Tier 2: Use annual fuel consumption (from company records) together with measured fuel-specific high heat values and default CO2 emission factors.

--Tier 3: Use annual fuel consumption, either from company records (for solid fuels) or directly measured with fuel flow meters (for liquid and gaseous fuels) together with periodic measurements of fuel carbon content.

--Tier 4: Use CEMS. Use Tier 4 only for combustion units that have certain types of existing CEMS in place and that meet several other specific criteria, such as fuel type and hours of operation. Sources that have all of the necessary CEMS installed and certified by January 1, 2010 are required to use Tier 4 in 2010. However, for sources that need additional time to upgrade their CEMS, the use of CEMS can begin on January 1, 2011; and a lower tier calculation methodology may be used in 2010.

--As an alternative to any of the four tier methods, the rule provides that units that report to EPA year-round heat input data under 40 CRF part 75 can calculate CO2mass emissions using part 75 calculation methods.

Calculating CO2 Emissions From Sorbent Use. For fluidized bed boilers that use sorbent injection and units equipped with wet flue gas desulfurization systems, calculate CO2emissions from sorbent use using methods provided in the rule, except when

CO2emissions are measured with CEMS.

Calculating CO2 Emissions From Biomass Fuel Combustion.

Calculate CO2emissions from biomass combustion for only the specific types of biomass that are listed in the rule. The approach used for most units is to use a default high heat value and default

CO2emission factor to estimate emissions. For determining the biomass fraction of CO2emissions from units that burn

MSW or mixed fuels, and from units that co-fire biomass with fossil fuels and measure CO2emissions using CEMS, use the specific methods provided in the rule.

Calculating N2O and CH4 Emissions From Combustion.

Calculate N2O and CH4emissions only for units that are required to report CO2emissions under this subpart and only for fuels for which default emission factors are provided in 40 CFR part 98, subpart C.

Fuel Sampling and Analysis. The Tier 2 and Tier 3 calculation methodologies require periodic measurements of fuel heating value and carbon content. The minimum required frequency of these measurements is daily, weekly, monthly, quarterly, or semiannually, depending on the type of fuel combusted and other factors.

Data Reporting. In addition to the information required to be reported by the General Provisions (40 CFR 98.3(c)) and summarized in

Section II.A of this preamble, reporters must submit additional data that are needed for EPA verification of the reported GHG emissions from stationary combustion. The specific data to be reported are found in 40

CFR part 98, subpart C.

Recordkeeping. In addition to the records required by the General

Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this preamble, reporters must keep records of additional data used to calculate GHG emissions. These records are described in 40 CFR part 98, subpart C. 2. Summary of Major Changes Since Proposal

The major changes since proposal are identified in the following list. The rationale for these and any other significant changes can be found below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's

Response to Public Comments, Subpart C: General Stationary Fuel

Combustion Sources.''

Exemptions to GHG emissions reporting have been added for unconventional types of fuel. Reporters are required to calculate GHG emissions only for fuels that are listed in Table C-1 of subpart C, except that units larger than 250 mmBtu/hr, also must calculate GHG emissions for any other fuels that provide, on average, at least 10 percent of the annual heat input to the unit.

The use of the Tier 2 calculation method for

CO2emissions has been expanded to include units greater than 250 mmBtu/hr that combust only pipeline natural gas and/or distillate oil.

Two new alternative methods have been added, allowing sources that monitor and report heat input according to 40 CFR part 75, but are not required to report CO2mass emissions, to use established Part 75 CO2emissions calculation methods to meet the 40 CFR part 98 reporting requirements.

A definition of ``company records'', as it pertains to quantifying fuel consumption in Tiers 1, 2, and 3, has been added to 40

CFR 98.6.

The required fuel sampling frequency in Tiers 2 and 3 has been reduced for many fuels, particularly those that are homogeneous or that are delivered in shipments or lots.

Averaging of fuel sampling results is allowed for many fuels when the frequency of sampling and analysis is less than the minimum monthly frequency.

The rule has been clarified to affirm that the use of fuel sampling results provided by the fuel supplier is permissible, and that the use of fuel billing records to quantify fuel consumption is also allowed.

Additional deadline extensions for calibrating the fuel flow meters are provided in certain situations.

The use of Tier 4 has been clarified; i.e., all of the conditions listed in 40 CFR 98.33(b)(4)(ii) and all of the conditions listed in 40 CFR 98.33(b)(4)(iii) must be met before Tier 4 is required.

Units that must upgrade their existing CEMS to meet Tier 4 requirements may use either Tier 2 or Tier 3 in 2010.

The methods for calculating CH4and

N2O emissions have been clarified.

An expanded list of default emission factors are provided for certain solid, gaseous, and liquid biomass fuels.

The use of steam production and combustion unit efficiency to calculate CO2emissions is extended to other solid fuels in addition to MSW. These

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parameters may also be used to quantify the amount of biomass combusted in a unit.

The use of American Society for Testing and Materials

(ASTM) Methods D7459-08 and D6866-06a to determine CO2 emissions from combustion of mixed biomass fuels has been expanded to include the combustion of other biomass fuels in addition to those mixed with MSW.

The missing data provisions have been made more flexible.

The limit of 250 mmBtu/hr total heat input for aggregating units into groups for reporting purposes has been lifted.

The reporting of combined units served by a common supply line, or common pipe configuration, has been clarified.

The amount of required unit-level data and emissions verification information has been reduced for some of the measurement

Tiers. 3. Summary of Comments and Responses

This section contains a brief summary of major comments and responses. Many comments on general stationary fuel combustion were received covering numerous topics. Responses to significant comments received can be found in ``Mandatory Greenhouse Gas Reporting Rule:

EPA's Response to Public Comments, Subpart C: General Stationary Fuel

Combustion Sources.''

Definition of Source Category

Comment: Several commenters asked EPA to clarify whether sources such as flares, hazardous waste incinerators, thermal oxidizers, pollution control devices, fume incinerators, burnout furnaces, and small equipment such as stoves and space heaters are included in the stationary combustion source category. Others suggested that EPA should consider requiring that only the GHG emissions from combustion of traditional fossil fuels (if any) in these types of sources be reported.

Comments were also received on the proposed language for excluding emergency generators and the associated definitions.

Response: The final rule retains the broad definition of a stationary fuel combustion source, which is any device that combusts fuel. Fuel is defined very broadly to mean any combustible material.

However, in evaluating public comments, we agree that in some cases the reporting of GHG emissions is unreasonable given the cost of monitoring and the relative level of GHG emissions. Monitoring can be particularly burdensome for vents with highly variable gas characteristics (e.g., carbon content and heat value). Accordingly, the final rule expands the list of combustion sources and fuels that are exempted from GHG emissions reporting under 40 CFR part 98, subpart C, as summarized below:

Flares are exempted from 40 CFR part 98, subpart C.

However, flares at some facilities might be covered by other subparts of the rule.

Stationary combustion units that combust hazardous waste, as defined in 40 CFR 261.3, are also exempted. These units would report only the emissions from combustion of any fuels covered by subpart C that are co-fired with hazardous wastes.

For calculations at the unit level, units less than 250 mmBtu/hour heat input are required to report GHG emissions only for fuels for which EPA has provided default emission factors in the rule.

Units larger than 250 mmBtu/hour heat input GHG that combust miscellaneous, non-traditional fuels such as refinery gas, process gas, vent gases, waste liquids, and others must report only if

CEMS are used or if these fuels contribute 10 percent or more of the annual unit heat input to the unit. With this exclusion, we have concluded that devices such as thermal oxidizers, pollution control devices, fume incinerators, burnout furnaces, and other such equipment would report only GHG emissions from the firing of supplemental fossil fuels.

In response to comments on the exclusion of emergency generators,

EPA removed proposed language that would have required emergency generators to be identified as such in the facility's State or local air permit in order to qualify for an exemption. We also added language to exclude other emergency equipment. See Section III.D of this preamble for the response to the comments on exclusion of emergency generators from 40 CFR part 98, subparts C and D. See ``Mandatory

Greenhouse Gas Reporting Rule: EPA's Response to Public Comments,

Subpart A: Definitions, Incorporation by Reference, and Other Subpart A

Comments'' for responses to comments on definitions, including changes to the emergency generator definition and the addition of a definition for emergency equipment.

Comment: Multiple commenters asked EPA to institute a ``de minimis'' provision in the rule to exclude stationary combustion sources other than the largest units at a facility.

Response: The final rule contains no de minimis exclusions.

However, to simplify reporting, the rule allows small units to be aggregated and reported as a single emissions value, if certain conditions apply. The final rule has expanded the availability of this provision. The proposed rule limited the aggregation of any one group to a combined maximum capacity of 250 mmBtu/hour heat input. The final rule removes this limit and allows grouping of any units that individually are less than 250 mmBtu/hour heat input. EPA has also clarified the use of the common pipe metering option, so that all stationary combustion units at a facility using the same fuel that is metered through a common supply line may report a single emissions value under this rule. In addition, the changes listed above in Section

III.C.2 of this preamble will simplify emissions calculations for many combustion units.

Method for Calculating GHG Emissions

Comment: EPA received numerous comments on the proposed GHG calculation methods for stationary combustion sources. Most of the comments centered on the use of the four-tiered approach for calculating CO2emissions. Several commenters requested that

EPA remove the 250 mmBtu/hr unit size restriction on the use of Tier 1 and 2 calculation methods, especially for the combustion of relatively homogeneous fuels such as natural gas and fuel oil. Objections were raised to the specified frequency of fuel sampling under Tiers 2 and 3, as being excessive and unnecessary. Two commenters recommended that annual sampling be allowed for natural gas and fuel oil. A number of commenters asked the Agency to allow averaging of fuel sampling results

(to simplify the CO2emissions calculations) and to affirm that the use of fuel sampling results provided by the fuel supplier is permissible. Others sought confirmation that fuel billing meters could be used to quantify fuel usage. Multiple commenters asked EPA to clarify who must use the Tier 4 calculation method, which requires the use of continuous emission monitoring systems (CEMS) to measure stack gas flow rate and CO2concentration. A number of comments were received requesting that sources currently monitoring and reporting heat input data under 40 CFR Part 75, but not reporting

CO2mass emissions, be allowed to implement established Part 75 CO2emissions calculation methods in lieu of using Tiers 1 through 4. Finally, EPA received diverse comments on the proposed calculation method for CH4and N2O emissions.

Several commenters recommended that these emissions either not be reported at all, or that emissions reporting should be

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excluded for certain fuel types. Others asked for flexibility in determining the appropriate emission factors for CH4and

N2O. Some suggested that the use of operator-defined emission factors or factors from other GHG registries should be allowed.

Response: The final rule significantly expands the use of Tier 1 and Tier 2 calculation methodologies. All units rated at 250 mmBtu/hr or less are allowed to use the Tier 1 or Tier 2 calculation methodologies, depending on fuel sampling provisions at either the facility or by the supplier of the fuel. In addition, units rated at over 250 mmBtu/hr that combust pipeline quality natural gas and distillate oil are allowed to use the Tier 2 calculation methodology, because of the homogeneous nature and low variability in the characteristics of these fuels. However, the 250 mmBtu/hr unit size cutoff remains for units that combust residual oil, other gaseous fuels, and solid fossil fuel.

The mandatory monthly fuel sampling and analysis requirements for traditional fossil fuels have been dropped from Tiers 2 and 3. EPA agrees with the commenters that for a homogeneous fuel such as pipeline natural gas, monthly sampling is not necessary. Therefore, 40 CFR 98.34 has been revised to require that natural gas be sampled semiannually.

For other fuels such as oil and coal, which are delivered in shipments or lots, requiring monthly sampling may be impractical, because new fuel lots or deliveries may not be received on a monthly basis. For fuel oil and coal, a representative sample is required for each fuel lot, i.e., for each shipment or delivery. For other liquid fuels and biogas, quarterly sampling is required. For solid fuels other than coal, excluding MSW, weekly composite sampling with monthly analysis is required. For gaseous fuels other than natural gas and biogas, the daily sampling requirement has been retained, but only for facilities with existing equipment in place that is capable of providing the data.

Otherwise, weekly sampling is required if such equipment for daily sampling is not installed.

The final rule clarifies that fuel sampling and analysis data provided by the supplier may be used in the emission calculations, and that fuel billing meters may be used to quantify fuel consumption. To simplify the emission calculations in Tiers 2 and 3, arithmetic averaging of higher heating value and carbon content data over the reporting year is permitted if these data are collected less frequently than monthly (see Equation C-2b in 40 CFR 98.33). However, regardless of the sampling frequency required by the rule, reporters must use the results of all available valid fuel analyses in the emissions calculations.

Today's rule clarifies the applicability of the Tier 4 methodology.

Many commenters were unsure whether only one or all six of the conditions listed in proposed 40 CFR 98.33(b)(4)(ii) and all three of the conditions listed in proposed 40 CFR 98.33(b)(4)(iii) must be met to trigger the requirement to use CEMS. EPA's intent has always been that a source must meet all conditions listed in those sections to require the use of Tier 4. This has been made clear in the final rule text.

The final rule adds two methods that can be used as alternatives to any of the four tier calculation methods. These alternative methods apply to sources that are currently required to monitor and report heat input data according to 40 CFR part 75, but are not required to report

CO2mass emissions. Many units subject to the Clean Air

Interstate Regulation (CAIR) are in this category. These alternative methods allow these sources to use their 40 CFR part 75 heat input data together with one of the CO2emissions calculation methodologies in part 75 to meet 40 CFR part 98 CO2 emissions reporting requirements. For instance, sources monitoring hourly heat input according to Appendix D of 40 CFR part 75 may use

Equation G-4 in Appendix G of 40 CFR part 75 to calculate

CO2emissions. Similarly, low mass emitting sources monitoring heat input under 40 CFR 75.19 may use Equation LM-11 in 40

CFR 75.19 to calculate CO2emissions. Sources using 40 CFR part 75 flow rate and CO2CEMS to continuously monitor heat input may use the CEMS measurements together with an appropriate equation from Appendix F of 40 CFR part 75 to determine CO2 mass emissions.

The methodology for calculating CH4and N2O emissions has been clarified in the final rule. Reporting of these emissions is required only for the fuels listed in Table C-2 of 40 CFR part 98, subpart C. Further, reporting of CH4and

N2O emissions is required only for units that are required to report CO2emissions under 40 CFR part 98, subpart C and only for fuels for which default emission factors are provided in subpart C. The emission factors in Table C-2 of 40 CFR part 98, subpart

C are both fuel-specific and heat input-based. Therefore, when more than one type of fuel is combusted in a unit, direct measurements or engineering estimates of the annual heat input from each fuel are needed to calculate the CH4and N2O emissions.

Consequently, when CEMS (which are not fuel-specific) are used to monitor the CO2emissions and heat input for a multi-fuel unit, the total heat input measured by the CEMS must be apportioned to each fuel type. The owner or operator should use the best available information (e.g., fuel feed rates, high heat values) to do the necessary heat input apportionment. To provide greater consistency in reporting, EPA has chosen to retain the requirements for using the default factors in Table C-2 of 40 CFR part 98, subpart C, rather than allow reporters to select their own emission factors.

Procedures for Estimating Missing Data

Comment: EPA received several requests to modify the proposed missing data substitution procedures in 40 CFR part 98, subpart C. One commenter recommended that a minimum data capture requirement should be specified rather than requiring the use of substitute data to fill in missing data gaps. Another commenter suggested that only the ``before'' value be used for data substitution, rather than the average of the quality-assured values before and after the missing data period. Others favored using emission factors or the ``best available estimates'' for all parameters, rather than following a prescriptive missing data algorithm. Finally, several commenters asserted that 40 CFO part 75 missing data procedures for CO2are too conservative (i.e., may overestimate emissions significantly) and seem to be contrary to the objectives of 40 CFR part 98.

Response: The final rule provides additional flexibility to the missing data provisions of 40 CFR part 98, subpart C. The rule requires the use of ``before and after'' average values for only three parameters (fuel HHV, carbon content, and molecular weight). If the

``after'' value is not yet available when the GHG emissions report is due, the ``before'' value may be used for missing data substitution.

For all other parameters, the reporter can substitute data values that are based on the best available estimates, based on all available process information.

EPA does not agree with the commenters who believe that the 40 CFR part 75 CO2missing data procedures are too conservative and contrary to 40 CFR part 98 program objectives. Nearly all 40 CFR part 75 sources maintain very high monitor data availability (95 percent or better) and use very little substitute data. Only when the data availability drops below 80 percent (which very seldom occurs) are the substitute data values significantly higher than the true

CO2concentrations. Therefore, sources that

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monitor CO2emissions according to 40 CFR part 75 should continue to use the standard part 75 missing data provisions, and no adjustments to those substitute data values are deemed necessary for 40

CFR part 98 reporting purposes.

Data Reporting Requirements

Comment: A number of commenters objected to the amount of unit- level data and emissions verification information that is required to be reported electronically under 40 CFR 98.36 as ``burdensome'',

``unnecessary,'' and ``excessive.'' The commenters recommended that the auxiliary information should instead be kept on file and made available to EPA upon request. Several commenters recommended that EPA remove the 250 mmBtu/hr limit on the cumulative heat input capacity of units that can be aggregated into groups for reporting purposes. Other commenters asserted that EPA should consider the 40 CFR part 75 emissions data submitted under the ARP to be sufficient to satisfy 40 CFR part 98 requirements, and that there is no need to submit the same data twice.

Response: EPA does not agree with the assertion that the amount of unit-level data to be reported is excessive, burdensome, or unnecessary. For this mandatory GHG emissions reporting rule, two approaches to emissions data verification were considered, EPA verification and third-party verification. The Agency decided on EPA emissions verification. To verify GHG emissions estimates, EPA needs supporting data that are reported at the same level as the emissions are calculated. Because the rule requires that emissions be calculated at the unit level, it is imperative for EPA to obtain unit level verification data, particularly given the variety of requirements for estimating fuel combustion emissions under 40 CFR part 98, subpart C.

Subpart C provides four different methods of estimating CO2 emissions. The four methods require measurement of different parameters to estimate emissions, and the use of the methods is conditioned on a variety of operating factors. In addition, facilities use fuel combustion units of a variety of different sizes, types, and fuel firing scenarios. Under these circumstances, EPA could not verify that the correct methods were selected or applied correctly without unit- level data. If unit-level data were not submitted or were aggregated at a gross level, EPA could not reasonably verify the accuracy of reported facility-wide GHG emissions data, because EPA could not evaluate the relationship between unit capacity, fuel characteristics, fuel consumption, and emissions. However, as explained below, in the final rule EPA has made a number of significant adjustments to the data reporting requirements to clarify requirements and to reduce the reporting burden.

First, for units that use Tiers 1, 2 and 3 to calculate

CO2mass emissions, the cumulative 250 mmBtu/hr heat input capacity limit on the aggregation of units into groups has been dropped. Rather, the 250 mmBtu/hr restriction applies only to the individual units in a group. Therefore, for reporting purposes, individual units with maximum rated heat input capacities of 250 mmBtu/ hr or less may be aggregated without limit into a single group, provided that the Tier 4 methodology is not required for any of the units, and all units in the group use the same calculation methodology for any common fuels that they combust. Units with maximum rated heat inputs greater than 250 mmBtu/hr using Tiers 1, 2, and 3 must report as individual units, unless they burn the same type of fuel and the fuel is provided by a common pipe or supply line. In that case, the owner or operator may opt to aggregate emission for all units fed by the common fuel line. Units using Tier 4 must report as individual units unless they share a monitored common stack.

Second, the rule requires minimal data to be reported for units that monitor and report emissions and heat input data according to 40

CFR part 75. Units that meet these criteria include units that are subject to the ARP, and potentially units that are subject to CAIR, and other programs. The final rule clarifies that 40 CFR part 75 sources must report 40 CFR part 98 GHG emissions data under the exact same unit, stack, or pipe ID numbers that are used for electronic reporting in the part 75 programs (e.g., 1, 2, CT5, CS001, MS1A, CP001, etc.).

Even though most 40 CFR part 75 sources report CO2mass emissions data to EPA year-round, these data alone are not sufficient to satisfy the Part 98 reporting requirements for the following reasons. The emissions reports required under 40 CFR part 98 are facility-wide reports that require GHG emissions from all stationary combustion units at the facility, whether or not the units are subject to a 40 CFR part 75 program. Many electricity generating facilities have both ARP units and non-ARP units on site. Further, the

CO2emissions data reported under 40 CFR part 75 are in units of short tons; Part 98 requires reporting in metric tons.

Finally, 40 CFR part 98 also requires CH4and N2O emissions to be reported, neither of which are reported under any 40

CFR part 75 program.

Third, the required verification data have been clarified and, in some cases, differ substantively from the proposed rule. No additional verification information is required for sources that monitor and report emissions and heat input data using 40 CFR part 75. This includes sources that elect to use the new alternative calculation methodologies for units monitoring heat input year round according to 40 CFR part 75 programs. For sources using Tiers 1, 2, 3, and 4, the final rule streamlines some of the reporting. Sources using Tier 3 are required to report only monthly averages of fuel carbon content and molecular weight rather than the proposed requirement to submit the results of each individual determination. Sources that use Tier 4 are required to report quarterly cumulative CO2mass emissions, rather than daily CO2emissions, as proposed. Also, to address concerns raised by some of the commenters, certain data elements need only be retained on file and provided to EPA upon request. These data elements include the methods used for fuel sampling and analysis, the methods used to calibrate fuel flow meters, the dates and results of fuel flow meter calibrations, and the dates and results of CEMS certification tests and on-going QA tests of the CEMS.

D. Electricity Generation 1. Summary of the Final Rule

Source Category Definition. This source category consists of EGUs that are subject to the ARP and any other EGUs that are required to monitor and report to EPA CO2mass emissions year-round according to 40 CFR part 75. All other EGUs are part of the general stationary fuel combustion source category and report under 40 CFR part 98 subpart C, if the facility meets the reporting rule applicability criteria. This source category excludes portable equipment, emergency generators, and emergency equipment.

Reporters must submit annual GHG reports for facilities that meet the applicability criteria in the General Provisions (40 CFR 98.2) summarized in Section II.A of this preamble.

GHGs to Report. Report annual CO2, N2O, and

CH4mass emissions from each EGU.

GHG Emissions Calculation and Monitoring. For EGUs subject to the

ARP and other EGUs that are required to monitor and report to EPA

CO2mass emissions year-round according to 40

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CFR part 75, the reporter must continue to monitor CO2 emissions according to 40 CFR part 75. The cumulative CO2 mass emissions reported in the fourth quarter electronic data reports must be converted from short tons to metric tons, for 40 CFR part 98 reporting purposes. The N2O and CH4emissions must be calculated using fuel-specific default emission factors and heat input measurements in accordance with 40 CFR 98.33(c) in subpart C

(General Stationary Fuel Combustion Sources).

Data Reporting. In addition to the information required to be reported by the General Provisions (40 CFR 98.3(c)) and summarized in

Section II.A of this preamble, reporters must submit unit-level data and other information that are used to verify the reported GHG emissions. The additional data and information to be reported for this source category are specified in 40 CFR 98.46.

Recordkeeping. In addition to the records required by the General

Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this preamble, reporters must keep records of additional data used to calculate GHG emissions. The specific records that must be retained for this source category are identified in 40 CFR 98.47. 2. Summary of Major Changes Since Proposal

Response to Public Comments, Subpart D: Electricity Generation.''

The source category has been more precisely defined and includes only EGUs subject to the ARP and any other EGUs that are required to monitor and report to EPA CO2mass emissions year-round according to 40 CFR part 75.

The proposed emergency generator exclusion language no longer requires that emergency generators be identified as such in

State or local air permits.

A CO2calculation methology was provided for units that are not in the ARP, but report CO2mass emissions year-round using 40 CFR part 75 methodologies. 3. Summary of Comments and Responses

Definition of Source Category

Comment: Several commenters were concerned that covering non-ARP

EGUs in both subparts C and D of proposed 40 CFR part 98 was confusing and repetitive. Several commenters stated that the definition of an EGU is too inclusive and recommended that EPA revise it. The commenters were concerned that any unit, regardless of electrical output, could be identified as an EGU and place a facility in the electricity generation source category. One commenter suggested that a 25 megawatts (MW) threshold should be added to the EGU definition in 40 CFR 98.6 and to 40 CFR part 98, subpart D. A multitude of commenters objected to the language in proposed 40 CFR 98.40 requiring emergency generators to be designated as such in a State or local air permit, in order for the generators to be exempted from GHG emissions reporting. Many of these same commenters recommended changes to the definition of ``emergency generator'' in 40 CFR 98.6, suggesting that the term ``generator'' should be replaced with the term ``reciprocating internal combustion engine (RICE)'', to be consistent with 40 CFR 63.6675, subpart ZZZZ.

Others recommended that EPA should also exempt emergency equipment such as fire pumps, fans, etc. from GHG emissions reporting.

Response: The electricity generation source category definition in subpart D (40 CFR 98.40) has been modified based on the comments received. The final rule limits the source category to EGUs that are subject to ARP and to other EGUs that monitor and report to EPA

CO2mass emissions year-round according to 40 CFR part 75.

The final subpart D does not cover any other EGUs. The GHG emissions from other EGUs are covered under subpart C (General Stationary Fuel

Combustion).

The definition of an ``emergency generator'' in 40 CFR 98.6, the final rule has been changed to clarify that it includes both RICE and turbines. EPA has also added a definition of ``emergency equipment'' to 40 CFR 98.6, and exempts such equipment from GHG emissions reporting under both 40 CFR part 98, subparts C and D.

The proposed requirements in 40 CFR part 98, subparts C and D for emergency generators to be identified as such in State and local air permits in order to be exempt from GHG emissions reporting has been revised. There is considerable variation from State to State regarding the regulation of emergency generators, including whether or not permits are required. Some States specifically exempt emergency generators from permitting requirements. Other States use a permit by rule approach for emergency units. In view of this, the Agency has revised the wording of the exclusion for emergency generators to allow for situations where they are not specifically identified in a facility's permit.

Method for Calculating GHG Emissions

Comment: Several commenters suggested that for units that are not in the ARP but are required by other regulatory programs to report part 75 emissions and heat input data, EPA should expand the four-tiered calculation method for CO2mass emissions in 40 CFR 98.33(a) to allow the use of CO2emissions calculation methods based on Appendices D and G of part 75.

Response: The electricity generation source category definition has been narrowed to only include EGUs that are subject to ARP and to other

EGUs that monitor and report to EPA CO2mass emissions year- round according to 40 CFR part 75 (e.g., RGGI units). The final subpart

D provides a CO2calculation methodology for such EGUs that are not in the ARP, but report to EPA CO2mass emissions year-round using part 75 methodologies. For the purposes of part 98, the CO2emissions from these units are calculated and reported using the same methods as part 75.

Other units that are not in the ARP but report data under part 75, subpart C are now covered by 40 CFR part 98, subpart C instead of subpart D, and subpart C has been revised to allow the use of part 75 calculation methodologies. The response to the comment on these units is contained in Section III.C of this preamble (General Stationary Fuel

Combustion Sources).

E. Adipic Acid Production 1. Summary of the Final Rule

Source Category Definition. The adipic acid production source category consists of all processes that use oxidation to produce adipic acid.

Reporters must submit annual GHG reports for facilities that meet the applicability criteria in the General Provisions (40 CFR 98.2) summarized in Section II.A of this preamble.

GHGs to Report. Report N2O process emissions from adipic acid production.

In addition, report GHG emissions for other source categories at the facility for which calculation methods are provided in the rule, as applicable. For example, report CO2, N2O, and

CH4emissions from each stationary combustion unit on site under 40 CFR part 98, subpart C (General Stationary Fuel Combustion

Sources).

GHG Emissions Calculation and Monitoring. Unless an alternative method of determining N2O emissions is requested, calculate

N2O process emissions from adipic acid production

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by multiplying a facility-specific emission factor by the annual adipic acid production level. Determine the facility-specific emission factor by an annual performance test to measure N2O emissions from the waste gas stream of each oxidation process and the production rate recorded during the test.

When N2O abatement devices (such as nonselective catalytic reduction) are used, adjust the N2O process emissions for the amount of N2O removed using the destruction efficiency for the control device and the fraction of annual production for which the control device is operating. The destruction efficiency can be specified by the abatement device manufacturer or can be determined using process knowledge or another performance test.

Data Reporting. In addition to the information required to be reported by the General Provisions (40 CFR 98.3(c)) and summarized in

Section II.A of this preamble, reporters must submit additional data that are used to calculate GHG emissions. A list of the specific data to be reported for this source category is contained in 40 CFR part 98, subpart E.

Recordkeeping. In addition to the records required by the General

Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this preamble, reporters must keep records of additional data used to calculate GHG emissions. A list of specific records that must be retained for this source category is included in 40 CFR part 98, subpart E. 2. Summary of Major Changes Since Proposal

The major changes since proposal are identified in the following list. The rationale for these and any other significant changes can be found in this section or ``Mandatory Greenhouse Gas Reporting Rule:

EPA's Response to Public Comments, Subpart E: Adipic Acid Production.''

The re-testing trigger was changed. Performance testing to determine the N2O emissions factor is required annually, whenever the ratio of cyclohexanone to cyclohexanol is changed, and when new abatement equipment is installed.

Equation E-2 was edited to correct a calculation error and to allow multiple types of abatement technologies. 40 CFR 98.56 was reorganized and updated to improve the data reporting requirements as needed for the emissions verification process. Some data elements were moved from 40 CFR 98.57 to 40 CFR 98.56, and some data elements that a reporter must already use to calculate GHGs as specified in 40 CFR 98.53 were added to 40 CFR 98.56 for clarity. 3. Summary of Comments and Responses

This section contains a brief summary of major comments and responses. Several comments on adipic acid production were received covering numerous topics. Responses to significant comments received can be found in ``Mandatory Greenhouse Gas Reporting Rule: EPA's

Response to Public Comments, Subpart E: Adipic Acid Production.''

GHGs To Report

Comment: Multiple commenters asked that the language in 40 CFR 98.52(b) be clarified to include emissions under 40 CFR part 98, subpart E only from units that are 100 percent dedicated to adipic acid production to avoid double counting of combustion emissions.

Response: We reviewed this issue but decided not to make any changes to 40 CFR part 98, subpart E. We do not foresee a potential for double counting of combustion emissions at the facility because all combustion unit emissions at adipic acid facilities are to be reported under 40 CFR part 98, subpart C. 40 CFR part 98, subpart E provides methods for reporting only the process N2O emissions. Also see Section III.C of this preamble for responses to comments related to 40 CFR part 98, subpart C (General Stationary Combustion).

Selection of Proposed GHG Emissions Calculations and Monitoring Methods

Comment: One commenter stated that emissions of N2O do not correlate with the production of adipic acid at their facility. A portion of the process off gas, which contains N2O, is sold to an offsite facility via dedicated piping. The amount sold depends on customer needs and the amount is metered. The commenter asked that the language in the final rule address this issue.

Response: We agree that N2O emitted from the production of adipic acid that is sold or transferred offsite is not covered in the proposed rule. The final rule has been changed to require this amount of N2O to be reported. Allowing for this additional reporting requirement ensures that the reported N2O emissions attributed to the adipic acid facility are accurate.

Reporting of the N2O sold or transferred offsite will help

EPA improve methodologies for reporting of GHG emissions.

Method for Calculating GHG Emissions

Comment: Multiple commenters asked that the requirement to repeat the annual performance test be removed. In the proposal, re-testing was triggered whenever the adipic acid production rate changed by more than 10 percent. Commenters asserted that production depends on demand for adipic acid and often varies by 15 percent.

Response: Upon review, we decided to eliminate re-testing. We believe that annual determination of the N2O emissions factor is sufficient to accurately calculate N2O emissions as long as the production equipment remains consistent over the year- long period (i.e. no new abatement technology).

Comment: Multiple commenters asked that alternative methods be allowed for calculating N2O emissions from adipic acid production. Specifically the commenters asked that EPA allow the use of

N2O and flow CEMS to directly measure N2O emissions and use the performance test to evaluate the CEMS accuracy.

The commenters also asked that EPA allow the use of existing process flow meters and process N2O analyzers to determine the amount of N2O sent to control devices and use the performance test to measure control device destruction efficiency.

Response: We agree that there are other means of determining site- specific N2O emissions. The final rule has been changed to allow alternative test methods. Any alternative must be approved by the

Administrator before being used to comply with this rule. An implementation plan that details how the alternative method will be implemented must be included in the request for the alternative method.

Until the method is approved facilities must use the alternatives proposed in the rule for a performance test. As one commenter noted, at minimum the performance test will help to QA/QC alternative methods currently used to monitor N2O emissions (such as

N2O CEMS).

EPA understands the need to further evaluate and establish alternative comparable methods for sources to use in accurately calculating N2O emissions from adipic production and will address in future rulemakings or amendments to rulemaking.

The final rule does allow the use of existing process flow meters and process knowledge in the determination of the destruction factor of

N2O abatement technologies. This parameter is often based on site-specific knowledge and operations. We believe

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that using existing methods can also reduce the potential cost impacts of this rulemaking and that it is in the best interest of the facilities that process parameters be accurately measured.

Comment: One commenter asked that Equation E-2 be edited to follow the summation format used in the IPCC Tier 2 methodology. The current format does not allow for multiple abatement technologies (including no abatement).

Response: We agree with the commenter. The equation in the proposed rule contained an error and did not allow for multiple abatement technologies. The final rule contains a corrected version of the equation.

F. Aluminum Production 1. Summary of the Final Rule

Source Category Definition. The aluminum production source category consists of facilities that manufacture primary aluminum using the

Hall-H[eacute]roult manufacturing process. The primary aluminum manufacturing process consists of the following operations:

Electrolysis in prebake and S[oslash]derberg cells.

Anode baking for prebake cells.

Reporters must submit annual GHG reports for facilities that meet the applicability criteria in the General Provisions (40 CFR 98.2) summarized in Section II.A of this preamble.

GHGs to Report. For aluminum production, report:

Perfluoromethane (CF4) emissions and perfluoroethane (C2F6) emissions from anode effects in all prebake and S[oslash]derberg electrolysis cells combined.

CO2emissions from anode consumption during electrolysis in all prebake and S[oslash]derberg cells.

All CO2emissions from anode baking.

In addition, report GHG emissions for other source categories at the facility for which calculation methods are provided in the rule, as applicable. For example, report CO2, N2O, and

CH4emissions from each stationary combustion unit on site under 40 CFR part 98, subpart C (General Stationary Fuel Combustion

Sources).

GHG Emissions Calculation and Monitoring. Reporters must calculate process emissions using the following methods:

CF4 from anode effects: Calculate annual CF4 emissions based on the frequency and duration of anode effects in the aluminum electrolytic reduction process for each prebake and

S[oslash]derberg electrolysis cell using the following parameters:

--Anode effect minutes (AEM) per cell-day calculated monthly.

--Aluminum metal production calculated monthly.

--A slope coefficient relating CF4emissions to anode effect minutes per cell-day and aluminum production. The slope coefficient is specific to each smelter and must be measured in accordance with the protocol specified in the rule at least once every 10 years.

--Facilities are allowed to use historic smelter-specific slope coefficients for the first three years of reporting under the rule.

Historic measurements include all those made under EPA's Voluntary

Aluminum Industry Partnership or at facilities owned or operated by companies participating in the Voluntary Aluminum Industry Partnership.

Facilities without historic measurements are required to complete measurements by the end of first year of reporting.

--Facilities which operate at less than 0.2 anode effect minutes per cell day or, when overvoltage is recorded, operate with less than 1.4mV overvoltage, can use either smelter-specific measured slope coefficients or the technology-specific (Tier 2) default coefficients from Volume III, Chapter 4, Section 4.4 Metal Industry Emissions of the 2006 IPCC Guidelines for National Greenhouse Gas Inventories as specified in the rule.

C2F6 from anode effects: Calculate annual

C2F6emissions from anode effects from each prebake and S[oslash]derberg electrolysis cell using the calculated

CF4emissions and the mass ratio of

C2F6to CF4emissions, as determined during the same test during which the slope coefficient is determined.

Process CO2 emissions--general approaches. Most reporters can elect to calculate and report process CO2emissions from anode consumption during electrolysis and from anode baking by either

(1) installing and operating CEMS and following the Tier 4 methodology

(in 40 CFR part 98, subpart C) or (2) using the calculation procedures specified below.

However, if process CO2 emissions from anode consumption during electrolysis or anode baking are emitted through the same stack as a combustion unit or process equipment that uses a CEMS and follows

Tier 4 methodology to report CO2emissions, then the CEMS must be used to measure and report combined CO2emissions from that stack, instead of using the calculation procedures specified below.

CO2 emissions from anode consumption in prebake cells:

Calculate annual CO2emissions at the facility level using a mass balance equation based on measurements of the following parameters:

--Net prebaked anode consumption rate per metric ton of aluminum metal produced.

--Ash and sulfur contents of the anodes.

--Total mass of aluminum metal produced per year for all prebake cells.

CO2 emissions from S[oslash]derberg cells: Calculate

CO2emissions from paste consumption in S[oslash]derberg cells using a mass balance equation at the facility level based on the following parameters:

--Paste consumption rate per metric ton of aluminum metal produced and the total mass of aluminum metal produced per year for all

S[oslash]derberg cells.

--Emissions of cyclohexane-soluble matter per metric ton of aluminum produced.

--Binder content of the anode paste.

--Sulfur, ash, and hydrogen contents of the coal tar pitch used as the binder in the anode paste.

--Sulfur and ash contents of the calcined coke used in the anode paste.

--Carbon in the skimmed dust from the cell, per metric ton of aluminum produced.

CO2 emissions from anode baking of prebake cells:

Calculate CO2emissions at the facility level separately for pitch volatiles combustion and for bake furnace packing material.

To calculate CO2emissions from the pitch volatiles, use a mass balance equation based on the following parameters:

--Initial weight of the green anodes.

--Mass of hydrogen in the green anodes.

--Mass of the baked anodes.

--Mass of waste tar collected.

To calculate CO2emissions from bake furnace packing material, use a mass balance equation based on the following parameters:

--Packing coke consumption rate per metric ton of baked anode production.

--Sulfur and ash contents of the packing coke.

The variables used to calculate CO2emissions from anode and paste consumption (e.g., sulfur, ash, and hydrogen contents) can be determined for each facility, or the source can use default values from the 2006 IPCC Guidelines for National Greenhouse

Gas Inventories as specified in 40 CFR 98.64.

Data Reporting. In addition to the information required to be reported by the General Provisions (40 CFR 98.3(c)) and summarized in

Section II.A of this preamble, reporters must submit

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additional data that are used to calculate GHG emissions. A list of the specific data to be reported for this source category is contained in 40 CFR part 98, subpart F.

Recordkeeping. In addition to the records required by the General

Response to Public Comments, Subpart F: Aluminum Production.''

A new subsection was added in 40 CFR 98.63 providing a new equation (Eq. F-1) to sum monthly PFC emission values into annual PFC emission value.

The equation for CO2emissions from

S[oslash]derberg cells (paste consumption) was corrected.

Language was updated to request reporting of all

CO2emissions from on-site anode baking.

Language was updated to request reporting of smelter- specific slope coefficients (plural).

A new equation was added in 40 CFR 98.63 (Eq. F-3) to calculate CF4emissions from overvoltage; and updated language in subsequent sections to accommodate the overvoltage method.

Language was added to permit facilities that operate with low anode effect minutes or low overvoltages to use IPCC Tier 2 default slope factors. 3. Summary of Comments and Responses

This section contains a brief summary of major comments and responses. Three comments on aluminum production were received covering numerous topics. Responses to significant comments received can be found in ``Mandatory Greenhouse Gas Reporting Rule: EPA's Response to

Public Comments, Subpart F: Aluminum Production.''

Comment: Several commenters suggested that smelters should be permitted to use International Aluminum Institute default slope coefficients which are based on global technology-specific averages to calculate PFC emissions, especially at high performance facilities.

Response: The use of smelter-specific slope coefficients as required in the rule leads to significantly more precise PFC emission calculations than the use of default slope coefficients (95 percent confidence interval of 15 compared to 50 percent). For a typical U.S. smelter emitting 175,000 metric tons of

CO2-eq in PFCs, these errors result in absolute uncertainties of 88,000 MTCO2e and 26,000 MTCO2e, respectively. The reduction in uncertainty associated with moving from default to smelter-specific slope coefficients, 62,000 MTCO2e, is as large as the emissions from many of the sources that would be subject to the rule.

However, for ``high performance'' facilities, which are defined by the 2006 IPCC Guidelines as those at or below 0.2 anode effect minutes per cell day or less than 1.4 mV overvoltage, the IPCC analysis indicates that impact of moving from a Tier 2 to a Tier 3 slope coefficient would not result in a significant improvement in PFC emissions. Therefore,

EPA agrees that high performance facilities should be allowed to use technology specific (Tier 2) default values from Volume III, Chapter 4,

Section 4.4 Metal Industry Emissions of the 2006 IPCC Guidelines for

National Greenhouse Gas Inventories. These values are identical to the

``Aluminum Sector Greenhouse Gas Protocol (Addendum to the WRI/WBCSD

Greenhouse Gas Protocol),'' October 2006 default coefficients.

Comment: Several commenters argued the requirement to re-measure smelter-specific slope coefficients every three years is expensive and unnecessary.

Response: While the cost to require smelter-specific slope coefficients is significantly greater than the cost to use default slope coefficients, the benefit of reduced uncertainty is considerable, as noted above. The costs that would be incurred by smelters measuring slope factors are discussed in the Regulatory Impact Analysis (RIA) for the proposed rulemaking (EPA-HQ-OAR-2008-0508-002).

Of the currently operating U.S. smelters, all but one has measured a smelter specific coefficient at least once; and at least three used the 2003 EPA/IAI protocol for measuring smelter-specific slope coefficients.

The USEPA/IAI Protocol for Measurement of Tetrafluoromethane and

Hexafluoroethane from Primary Aluminum Production establishes guidelines to ensure that measurements of smelter-specific slope- coefficients are consistent and accurate (e.g., representative of typical smelter operating conditions and emission rates). The Protocol currently recommends that smelter operators re-measure their slope coefficients at least every three years, and more frequently if they adopt changes to process control algorithms or observe changes to typical anode effect duration. Specifically, the Protocol recommends that operators repeat measurements of slope coefficients for

CF4and C2F6if one or more of the following apply: (1) Thirty-six months have passed since the last measurements (i.e., triennial measurements are recommended); (2) a change occurs in the control algorithm that affects the mix of types of anode effects or the nature of the anode effect termination routine; and, (3) changes occur in the distribution of duration of anode effects

(e.g. when the percentage of manual kills changes or if, over time, the number of anode effects decreases and results in a fewer number of longer anode effects).

Changes to process control algorithms or to the typical duration of anode effects can change the relationship between anode effect minutes, production, and emissions, that is, they can change slope coefficients.

In addition, more subtle changes can also change slope coefficients over time. According to industry experts, the rate of these more subtle changes has not been sufficiently studied to specify a frequency for re-measurement nor have there been a sufficient number of facilities that have been measured repeatedly to document the benefit of the additional incremental cost of measurement once every three years.

During the past few years, multiple U.S. smelters have adopted changes to their production process which are likely to have changed their slope coefficients. These include the adoption of slotted anodes and improvements to process control algorithms. Although some U.S. smelters have recently updated their measurements of smelter-specific coefficients, others may not have.

In view of these recent process changes, EPA is requiring smelters that have not already measured their slope factors under the ``2008

USEPA/IAI Protocol for Measurement of Tetrafluoromethane and

Hexafluoroethane from Primary Aluminum Production,'' to do so in time for the 2013 reporting year. EPA believes that this will ensure that slope factors are appropriately updated while providing sufficient lead-time for smelters to perform the measurements without encountering excessive costs or logistical barriers. However, after this initial update, EPA agrees that every three years is burdensome, therefore,

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further updates are required only every ten years unless there are major technological or process changes at a facility such as changes to the control algorithm that affect the mix of types of anode effects or the nature of the anode effect termination routine; or changes occur in the distribution of duration of anode effects (e.g. when the percentage of manual kills changes or if, over time, the number of anode effects decreases and results in a fewer number of longer anode effects).

Comment: Several commenters suggested that the rule should include the overvoltage measurement method, which is specific to use with

Pechiney technology, in case one or more U.S. smelters decide to adopt this technology in the future.

Response: The Overvoltage Method relates PFC emissions to an overvoltage coefficient, anode effect overvoltage, current efficiency, and aluminum production. The overvoltage method was developed for smelters using the Pechiney technology. While it is EPA's understanding that no U.S. smelters have used the Pechiney technology for at least a decade, if one or more U.S. smelters decide to adopt this internationally accepted technology in the future they would be expected to use the overvoltage method which follow the established guidelines in the ``USEPA/IAI Protocol for Measurement of

Tetrafluoromethane and Hexafluoroethane from Primary Aluminum

Production.''

G. Ammonia Manufacturing 1. Summary of the Final Rule

Source Category Definition. The ammonia manufacturing source category consists of process units in which ammonia is manufactured from a fossil-based feedstock via steam reforming of the hydrocarbon.

It also includes ammonia manufacturing processes in which ammonia is manufactured through the gasification of solid and liquid raw material.

Reporters must submit annual GHG reports for facilities that meet the applicability criteria in the General Provisions (40 CFR 98.2) summarized in Section II.A of this preamble.

GHGs to Report. For ammonia manufacturing, report the following emissions:

CO2process emissions from steam reforming of a hydrocarbon or the gasification of solid and liquid raw material, reported for each ammonia manufacturing process unit following the requirements of this part.

CO2, CH4, and N2O emissions from each stationary combustion unit. Report these emissions under 40 CFR 98, subpart C (General Stationary Fuel Combustion Sources) by following the requirements of 40 CFR part 98, subpart C.

For CO2collected and transferred off site, report these emissions under 40 CFR part 98, subpart PP (Suppliers of

CO2) following the requirements of 40 CFR part 98, subpart

PP.

In addition, report GHG emissions for any other source categories at the facility for which calculation methods are provided in other subparts of the rule, as applicable.

GHG Emissions Calculation and Monitoring. Reporters must use one of two methods to calculate CO2process emissions, as appropriate:

Most reporters can elect to calculate and report process

CO2emissions from each ammonia manufacturing process unit by either (1) installing and operating CEMS and following the Tier 4 methodology (in 40 CFR part 98, subpart C) or (2) using the calculation procedures contained in the rule and summarized below.

However, if process CO2emissions from an ammonia manufacturing process unit are emitted through the same stack as CO2emissions from a combustion unit or process equipment that uses a CEMS and follows Tier 4 methodology to report

CO2emissions, then the CEMS must be used to measure and report combined emissions from that stack, instead of using the calculation procedures described below.

To calculate process CO2emissions, use the equations provided in 40 CFR part 98, subpart G for solid, liquid, and gaseous feedstock and the following measurements:

--Continuous measurement of gaseous or liquid feedstock consumed using a flowmeter, or monthly aggregate of solid feedstock consumed.

--Carbon content of the feedstock (required to be measured monthly using supplier data or analysis using the appropriate test methods). If supplier data are used, facilities must QA/QC the supplier analysis on an annual basis using the appropriate test methods.

Data Reporting. In addition to the information required to be reported by the General Provisions (40 CFR 98.3(c)) and summarized in

Recordkeeping. In addition to the records required by the General

Response to Public Comments, Subpart G: Ammonia Manufacturing.''

Monitoring and QA/QC requirements were revised to allow for obtaining carbon content of feedstock used in ammonia manufacturing from the feedstock supplier. Facilities that obtain monthly carbon content information from their supplier are required to QA/QC supplier information through annual sampling and analysis of the feedstock.

Missing data procedures were added under 40 CFR 98.75 for parameters that facilities must measure such as feedstock consumption, the quantity of the waste recycle stream, and the monthly carbon content of both the feedstock consumption and waste recycle stream quantity.

Reporting requirements were added for the quantity of urea produced and the emissions associated with waste recycle streams commonly found at ammonia manufacturing facilities. 40 CFR 98.76 was reorganized and updated to improve the emissions data verification process. Some data elements were moved from 40 CFR 98.77 to 40 CFR 98.76, and some data elements that a reporter must already use to calculate GHGs as specified in 40 CFR 98.73 were added to 40 CFR 98.76 for clarity. 3. Summary of Comments and Responses

This section contains a brief summary of major comments and responses. Several comments on ammonia manufacturing were received covering numerous topics. Several of these comments were directed at the requirements for 40 CFR part 98, subpart C (General Stationary Fuel

Combustion Sources), and responses to those comments are provided in

Section III.C of this preamble. Responses to significant comments received can be found in ``Mandatory Greenhouse Gas Reporting Rule:

EPA's Response to

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Public Comments, Subpart G: Ammonia Manufacturing.''

Method for Calculating GHG Emissions

Comment: Several commenters asked EPA to clarify that ammonia production units must use Tier 4 calculation only if all of the conditions under proposed 40 CFR 98.33(b)(5)(ii)(A) through (F) apply to the unit and only where the ammonia manufacturing unit already has installed a stack gas volumetric flow rate monitor and a CO2 concentration monitor.

Response: We agree with the comment and have modified the text under 40 CFR 98.73(a) and (b) to state that if a facility operates and maintains CEMS that meet the requirements of 40 CFR 98.33(b)(4)(ii) or

(iii), then process or combined process and combustion CO2 emissions shall be calculated and reported under this subpart by following the Tier 4 Calculation Methodology specified in 40 CFR 98.33(a)(4) and all associated requirements for Tier 4 in 40 CFR part 98, subpart C (General Stationary Fuel Combustion Sources). If CEMS are not used to determine CO2emissions from ammonia processing units, then facilities must calculate and report process CO2 emissions under this subpart by using equations provided in 40 CFR 98.73(b)(1) through (b)(4). CO2combustion emissions from ammonia processing units must be reported under 40 CFR part 98, subpart

C (General Stationary Fuel Combustion Sources). For additional clarification on the requirements on use of CEMS see 40 CFR part 98, subpart C (General Stationary Fuel Combustion Sources), and Section

III.C of this preamble.

Comment: One commenter noted that most ammonia facilities utilize natural gas combustion combined with approximately five percent recycle flow of gas containing methane from the process. The carbon content of the recycle stream is already accounted for when measuring the feedstock flow rate and carbon content to the process. EPA should allow ammonia manufacturers to exclude this recycle stream in calculating combustion emissions, as the carbon in the recycle stream would be double counted.

Response: We agreed with commenters that it is important to account for use of the waste process stream in the case that it is recycled since carbon in the recycle stream is not actually emitted. In response to this comment we have added reporting requirements for quantifying emissions associated with the recycle stream. This will help EPA improve methodologies for calculating emissions from ammonia manufacturing in the future.

Monitoring and QA/QC Requirements

Comment: Several commenters stated that monthly carbon content sampling and analysis requirement is overly burdensome. Some commenters asked that EPA allow the use of a default value for carbon content while one commenter suggested use of carbon content data generated by the feedstock supplier.

Response: We agreed with commenters that flexibility should be added to the rule to allow for use of supplier data. This information is readily available from the feedstock supplier in most cases. The most common feedstock for ammonia production is pipeline quality natural gas. Supplier data on carbon contents of feedstock will have sufficient or comparable accuracy for the purposes of calculating

CO2emissions. We modified the monitoring and QA/QC procedures in the rule to allow use of carbon content data obtained from the feedstock supplier(s). Facilities that obtain monthly carbon content information from their supplier are required to QA/QC supplier information through annual sampling and analysis of the feedstocks consumed.

Procedures for Missing Data

Comment: Two commenters suggested that the proposed procedures for calculating emissions in the event of missing feedstock data would yield significant overstatements of GHG emissions. As proposed, if feedstock supply rate data are missing for a specific day or days

(e.g., if a meter malfunctions during unit operation), the reporting entity must use the lesser of the maximum supply rate that the production unit is capable of processing or the maximum supply rate that the meter can measure. If this substitution is applied to the feedstock for reformers used in ammonia production, either of these proposed approaches would likely result in significant over reporting of carbon emissions. The commenter proposed two alternatives that a reporting facility could use: Either (1) substitute an estimated value for feedstock supply rate, based on the arithmetic average of the previous thirty days of available feedstock supply rate data; or (2) utilize missing data estimating procedures similar to the procedure under 40 CFR 98.35(b)(2), based upon all available process data. These approaches would result in much more accurate estimates of emissions derived from the true historical operation of a specific ammonia manufacturing source.

Response: We agreed with commenters that the proposed missing data procedures would overestimate emissions when applied. While some of feedstock should be readily available and collected as a part of normal business practices, circumstances could arise where data could be missing. We added procedures consistent with the commenter's second recommendation, referencing the missing data procedures in 98.35(b)(2).

Ammonia facilities with missing data on feedstock supply rate must provide the best available estimate from all available process data.

Facilities must document and keep records of missing data procedures applied. We find that these revised procedures will provide accurate information for the purposes of this rulemaking.

Data To Be Reported

Comment: One commenter noted that the CO2produced through ammonia manufacturing can be utilized and that much of it is in the manufacture of urea. The commenter stated that EPA makes unsubstantiated assumptions that all CO2in urea will be released into the atmosphere. The commenter asked EPA not to tie emissions from applied urea, or emissions that result from urea once the product has been sold, to the producing industry.

Response: We added reporting requirements for annual urea production under 40 CFR 98.76. Information on urea production will help us improve our understanding of the quantity of CO2consumed from ammonia production that is used in the manufacture of urea. We know from the US GHG inventory and subsequent conversations with ammonia producers that on average it takes 0.733 tons of CO2 to produce one ton of urea. We have also requested that producers report, if known, the uses of the urea sold. Collecting information on urea production and its uses will help EPA to improve methodologies for calculating emissions from ammonia manufacturing, urea production, and urea consumption in the future.

H. Cement Production 1. Summary of the Final Rule

Source Category Definition. The cement production source category consists of each kiln and each inline kiln/raw mill at any Portland cement manufacturing facility, including alkali bypasses and kilns and inline kilns/raw mills that burn hazardous waste.

Reporters must submit annual GHG reports for facilities that meet the applicability criteria in the General Provisions (40 CFR 98.2) summarized in Section II.A of this preamble.

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GHGs to Report. For cement production, report the following emissions:

CO2process emissions from calcination, reported for each kiln.

CO2combustion emissions from each kiln.

N2O and CH4emissions from fuel combustion at each kiln under 40 CFR part 98, subpart C (General

Stationary Fuel Combustion Sources) using the methodologies in subpart

CO2, N2O, and CH4 emissions from each stationary combustion unit other than kilns under 40 CFR part 98, subpart C (General Stationary Fuel Combustion Sources).

In addition, report GHG emissions for any other source categories for which calculation methods are provided in other subparts of the rule, as applicable.

GHG Emissions Calculation and Monitoring. For CO2 emissions from kilns, reporters must select one of two methods, as appropriate:

For kilns with certain types of CEMS in place, reporters must use the CEMS and follow the Tier 4 methodology (in 40 CFR part 98, subpart C) to measure and report under the Cement Production subpart

(40 CFR part 98, subpart H) combined calcination and fuel combustion

CO2emissions.

For other kilns, the reporter can elect to either (1) install or operate a CEMS and follow the Tier 4 methodology to measure and report combined calcination and fuel combustion CO2 emissions or (2) calculate process CO2emissions as the sum of clinker emissions and emissions from raw materials. If using approach (2):

--Calculate clinker emissions monthly from each kiln using monthly clinker production (required to be measured); a kiln-specific, monthly clinker emission factor calculated from the monthly CaO and MgO content of the clinker (required to be measured); quarterly cement kiln dust not recycled to the kiln (required to be measured); and a quarterly kiln-specific factor of calcined material in the cement kiln dust not recycled to the kiln (measured or default values can be used).

--Calculate raw material emissions annually from the annual consumption of raw materials and the organic carbon content in the raw material

(measured annually for each type of raw material, or a default value of 0.2 percent may be used).

--Report process CO2emissions from each kiln under 40 CFR part 98, subpart H (Cement Production), and report combustion

CO2emissions from each kiln under 40 CFR part 98, subpart C

(General Stationary Fuel Combustion Sources).

Data Reporting. In addition to the information required to be reported by the General Provisions (40 CFR 98.3(c)) and summarized in

Subpart H (Cement Production).

Recordkeeping. In addition to the records required by the General

Response to Public Comments, Subpart H: Cement Production.''

The CO2calculation equations in 40 CFR 98.83 were revised to account for non-carbonate sources of calcium and magnesium in the kiln feed and uncalcined carbonates in the product.

Methods for monitoring CaO and MgO in clinker and CKD were changed from XRF to ASTM c114-07, Standard Test Methods for Chemical

Analysis of Hydraulic Cement. 40 CFR 98.84 was revised to clarify required monitoring frequency and to allow for alternative monitoring methods for raw materials and CKD.

Missing data procedures were added to 40 CFR 98.85 for parameters reporters must measure, clinker, CKD not recycled to the kiln, raw material consumption, carbonate contents of clinker CKD, non- calcined content of clinker and CKD, and organic carbon content of raw materials.

Requirements in 40 CFR 98.81 through 40 CFR 98.87 were revised to clarify which requirements apply to reporters who elect to report CO2emissions using CEMS. 40 CFR 98.86 was reorganized and updated to improve the emissions verification process. Some data elements were moved from 40

CFR 98.87 to 40 CFR 98.86, and some data elements that a reporter must already use to calculate GHGs as specified in 40 CFR 98.83 were added to 40 CFR 98.86 for clarity. 3. Summary of Comments and Responses

This section contains a brief summary of major comments and responses. We received several comments on cement production covering a number of topics. Many of these comments were directed at the requirements for 40 CFR part 98, subpart C (General Stationary Fuel

Combustion Sources), and responses to those comments are provided in

Section III.C of this preamble dealing with that source category. Also see Section II.N of this preamble for the response to comments on the emissions verification approach.

Responses to significant comments received related to process emissions from cement production can be found in ``Mandatory Greenhouse

Gas Reporting Rule: EPA's Response to Public Comments, Subpart H:

Cement Production.''

Selection of Threshold

Comment: One commenter suggested that EPA could reduce the burden presented by the Proposed Rule by reducing the number of facilities required to report (i.e., raise the reporting thresholds). The commenter further noted that by requiring GHG reporting for all cement plants, regardless of the magnitude of the plant's emissions, EPA removes an incentive for those plants to reduce GHG emissions to get below a threshold in order to avoid the burden of monitoring and reporting.

Response: In considering the comment, we acknowledge the potential benefit of a reporting threshold providing cement plants with incentive to reduce their GHG emissions. The ``once in, always in'' provision has been removed. The final rule now contains provisions to cease reporting if annual reports demonstrate emissions less than specified levels for multiple years. These provisions apply to all reporting facilities. See

Section II.H of this preamble for the response on provisions to cease reporting. See Section II.D of this preamble for the response on selection of source categories to report.

In developing the Proposed Rule, we considered emission-based thresholds of 1,000 metric tons CO2e, 10,000 metric tons

CO2e, 25,000 metric tons CO2e, and 100,000 metric tons CO2e. All of these emission thresholds covered more than 99.9 percent of CO2e emissions from cement facilities.

Only one plant out of 107 in the dataset would be excluded by the highest considered thresholds of 100,000 metric tons CO2e.

Therefore, we

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determined that it was appropriate to include all cement production facilities in the reporting requirements.

Method for Calculating GHG Emissions

Comment: Two commenters stated that the cement industry already has an established, proven protocol for calculating and reporting GHG emissions, and requested that EPA use the existing Cement

CO2Protocol as the basis for the Proposed Rule. Commenters further stated that the Cement CO2Protocol already provides many of the benefits that EPA ascribes to the Proposed Rule, including uniformity of reported data from one facility to another; availability of verifiable data to provide to the public, investors, and others; and other suggested benefits.

Both commenters stated that EPA needs to revise its clinker-based calculation to account for any non-carbonated CaO or MgO in the raw materials.

Response: In developing the proposed Rule, we considered many domestic and international GHG monitoring guidelines and protocols, including the Cement Sustainability Initiative Protocol referenced in the cement industry's comments. We combined elements of the Cement

CO2Protocol with elements of other protocols including the 2006 IPCC Guidelines, U.S. Inventory, DOE 1605(b), CARB mandatory GHG emissions reporting program, EPA's Climate Leaders program, and the EU

Emissions Trading System to develop two proposed methods for quantifying GHG emissions from cement manufacturing. These proposed methods include the use of CEMS to directly measure emissions and the use of calculation methods to determine emissions.

While finalizing today's rule, we revisited the Cement

CO2Protocol and compared its requirements to our requirements. We feel that the rule closely mirrors the GHG calculation methods and requirements of the Cement CO2Protocol with some minor differences. For example, our rule requires cement plants to use plant-specific emission factors to calculate CO2 emissions and does not allow the use of default emission factors. As stated in the proposal, we have determined that applying default emission factors to clinker production is more appropriate for national-level emissions estimates than facility-specific estimates, where data are readily available to develop site-specific emission factors. Default approaches would not provide site-specific calculation of emissions that reflect differences in inputs, operating conditions, fuel combustion efficiency, variability in fuels, and other differences among facilities. Further, it is our understanding that facilities analyze data relevant for site-specific determinations such as the carbonate contents of their raw materials to the kiln and products on a frequent basis, either on a daily basis or every time there is a change in the raw material mix. Using data from direct measurements will provide a more accurate representation of site specific emissions rates.

We also note that the Cement CO2Protocol does not specify measurement methods. Our rule specifies methods for measuring

CaO, MgO, and clinker weight. We selected these methods to be consistent with measurement techniques that are common within the cement industry. Prescribing standardized measurement procedures ensures the uniformity and consistency in the results and quality of data reported that the commenters agree is important for comparability of emissions.

We also used the Cement CO2Protocol as a model for revising our equations in 40 CFR 98.83 to account for non-carbonate sources of calcium and magnesium that may be present in the kiln feed.

Monitoring and QA/QC Requirements

Comment: One commenter expressed concern that 40 CFR 98.84(e) and

(f) seem to require continuous, direct weight measurement of CKD discarded and raw materials used, by category of material. The commenter stated that most cement plants do not have that capability, and that the proposed rule does not clearly state whether installation of additional measurement equipment will be required if not already installed.

One industry representative further recommended that EPA add truck weight scales as an acceptable option for raw material weight measurement to address certain limited cases in which this method may be more appropriate to use. In addition, the commenter recommended that

EPA allow CKD samples to be taken either as CKD exits the kiln or from bulk storage.

Response: We revised the text in 40 CFR 98.84(e) and (f) to more clearly state that CKD quantities are required to be measured on a quarterly basis and raw material quantities are required to be measured on a monthly basis. Furthermore, the Proposed Rule was never intended to require installation of new monitoring equipment for this purpose.

We agree with the commenter that continuous, direct weight measurement of these materials and installation of additional measurement equipment would be unnecessary. The proposed rule clearly stated that the quantity of CKD produced and raw materials consumed must be determined using the same plant instruments that the cement plant currently uses for accounting purposes. Moreover, because the quantities of raw materials and CKD do not greatly impact the CO2calculation, we added further clarification to this section to allow cement plants to use potentially less accurate, but commonly used, methods of measurement, such as truck weigh scales, to determine quantities of CKD and raw materials. We also added clarification to 40 CFR 98.84 to allow facilities to collect CKD samples either as CKD exits the kiln or from bulk storage.

Data Reporting Requirements

Comment: Two commenters asserted that EPA needs to provide clarifying language within 40 CFR part 98, subpart H (Cement

Production) to define which requirements apply to facilities using CEMS to monitor CO2emissions. One commenter noted that the

Proposed Rule, as written, appears to require cement plants using CEMS to collect maintain, and report process data related to calculating

CO2process emissions for kilns pursuant to proposed 40 CFR 98.84 through 98.87. This commenter claimed that requiring plants to collect and report such process data are redundant if the facility is continuously monitoring CO2emissions. Another commenter recommended that EPA state within 40 CFR part 98, subpart H (Cement

Production) that all of the requirements detailed in the subpart do not apply to cement kilns using Tier 4 (CEMS) method.

Response: We agree with the comment that reporters who are using

CEMS to monitor CO2do not need to collect, report, and maintain all of the process data required in proposed 40 CFR 98.84 through 98.87. However, we determined that some of the process data are necessary for emissions verification purposes, and therefore, plants using CEMS are not completely excluded from the requirements in 40 CFR part 98, subpart H (Cement Production). We added clarifying language throughout the Subpart to clearly state which requirements will apply to facilities that use CEMS to measure CO2emissions.

Specifically, we created separate lists of reporting requirements and recordkeeping requirements for cement plants using CEMS.

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Comment: One commenter noted that the data reporting requirements for cement plants, set forth in proposed 40 CFR 98.86, are expressed in different terms that those used for the specified procedures for calculating emissions. For example, the commenter stated that it is unclear what emission sources go into the ``site-specific emission factor (metric tons CO2/metric ton clinker produced)'' required to be reported under proposed 40 CFR 98.86(h), and how that factor would be calculated.

Response: We agree with the commenter that there were inconsistencies between 40 CFR 98.83 and 98.86. We updated reporting requirements in 40 CFR 98.86 to be consistent with the terms used in the emission calculation procedures in 40 CFR 98.83 and provide clarification in 40 CFR 98.83 for terms if needed. As a result, some calculations that are performed on a kiln-specific basis, such as

CO2emission factors, will be required to be reported on a kiln-specific basis in 40 CFR 98.86. Also see the Section II.N of this preamble for the response to comments on the emissions verification approach.

I. Electronics Manufacturing

At this time EPA is not going final with the electronics manufacturing subpart. As we consider next steps, we will be reviewing the public comments and other relevant information.

The Agency received a number of lengthy, detailed comments regarding the electronics manufacturing subpart. Commenters generally opposed the proposed reporting requirements and stated the proposal required excessive detail. For example, commenters asserted that they currently do not collect the data required to report using an IPCC Tier 3 approach and that to collect such data would entail significant burden and capital costs. In most cases, commenters provided alternative approaches to each of the reporting requirements proposed by EPA.

Commenters also requested clarification from EPA on a number of the proposed reporting provisions.

Based on careful review of comments received on the proposal preamble, rule, and technical support documents (TSDs) under proposed 40 CFR part 98, subpart I, EPA will perform additional analysis and evaluate a range of data collection procedures and methodologies. EPA's goal is to optimize methods of data collection to ensure data accuracy while considering industry burden.

J. Ethanol Production

At this time, EPA is not finalizing the Ethanol Production Subpart.

The sources of GHG emissions at ethanol production facilities that were to be reported under the proposed rule were stationary fuel combustion, onsite landfills, and onsite wastewater treatment. EPA has decided not to finalize the portion of 40 CFR part 98, subpart HH (Landfills) that addresses industrial landfills nor 40 CFR part 98, subpart II

(Wastewater Treatment). Stationary fuel combustion sources at ethanol production facilities are subject to the requirements of 40 CFR part 98, subpart C if general stationary fuel combustion emissions exceed the 25,000 metric tons CO2e threshold.

As EPA considers next steps, we will be reviewing the public comments and other relevant information. Based on careful review of comments received on the proposal preamble, rule and TSDs under proposed 40 CFR part 98, subparts J, HH, and II, EPA will perform additional analysis and consider alternatives to data collection procedures and methodologies contained in those subparts.

K. Ferroalloy Production 1. Summary of the Final Rule

Source Category Definition. The ferroalloy production source category consists of facilities that use pyrometallurgical techniques to produce any of the following metals: ferrochromium, ferromanganese, ferromolybdenum, ferronickel, ferrosilicon, ferrotitanium, ferrotungsten, ferrovanadium, silicomanganese, or silicon metal.

Reporters must submit annual GHG reports for facilities that meet the applicability criteria in the General Provisions (40 CFR 98.2) summarized in Section II.A of this preamble.

GHGs to Report. For ferroalloy production, report the following emissions.

Annual process CO2emissions from each EAF used for production of any ferroalloy listed in the source category definition.

Annual process CH4emissions for those EAFs used for the production of silicon metal, ferrosilicon 65 percent, ferrosilicon 75 percent, or ferrosilicon 90 percent.

CO2, N2O, and CH4 emissions from each stationary combustion unit on site under 40 CFR part 98, subpart C (General Stationary Fuel Combustion Sources).

In addition, report emissions from any other source categories for which calculation methodologies are specified in the rule, as applicable.

GHG Emissions Calculation and Monitoring. To calculate process

CO2emissions from EAFs, reporters can use one of two methods, as appropriate:

Most reporters can elect to calculate and report process

CO2emissions from each EAF by either (1) installing and operating a CEMS and following the Tier 4 methodology (in 40 CFR part 98, subpart C) or (2) using the carbon mass balance calculation procedure specified in the rule and summarized below.

However, if CO2process emissions from an EAF are emitted through the same stack as CO2emissions from a combustion unit or process equipment that uses a CEMS and follows Tier 4 methodology to report CO2emissions, then the CEMS must be used to measure and report combined emissions from that stack, instead of using the carbon mass balance calculation procedure described below.

If using the carbon mass balance procedure, perform a once per year calculation using equations in the rule and:

--Recorded monthly production data, and

--The average carbon content for each EAF input and output material determined by either using material supplier information or by annual analysis of representative samples of the material.

For those EAF's for which the reporter must report annual

CH4emissions, annual ferroalloy production data are used with an applicable emissions factor provided in the rule.

Data Reporting. In addition to the information required to be reported by the General Provisions (40 CFR 98.3(c)) and summarized in

Recordkeeping. In addition to the records required by the General

The major changes to the rule since proposal for ferroalloy production facilities were revisions to the carbon

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mass balance calculation procedure for calculating process

CO2emissions from EAFs. These changes reduce the reporting burden and are consistent with revisions made to other similar industries. The rationale for these and any other significant changes can be found below or in ``Mandatory Greenhouse Gas Reporting Rule:

EPA's Response to Public Comments, Subpart K: Ferroalloy Production.''

Frequency of performing the carbon mass balance calculations was revised to be required on an annual basis instead of the proposed monthly basis.

Frequency of material carbon content sampling and analysis of each EAF input and output material used for the material balance was revised to be performed by annual analysis of representative samples of the material instead of the proposed monthly basis.

Materials contributing less than one percent of the total carbon into or out of the EAF do not need to be included carbon mass balance calculations. 40 CFR 98.116 and 98.117 were reorganized and updated to improve the emissions verification process. Some data elements were moved from 40 CFR 98.117 to 40 CFR 98.116, and some data elements that a reporter must already use to calculate GHGs as specified in 40 CFR 98.173 were added to 40 CFR 98.116 for clarity. See Section II.N of this preamble for the response to comments on the emissions verification approach. 3. Summary of Comments and Responses

This section contains a brief summary of major comments and responses. Other comments on ferroalloy production were received covering various topics. Responses to significant comments received can be found in ``Mandatory Greenhouse Gas Reporting Rule: EPA's Response to Public Comments, Subpart K: Ferroalloy Production.''

Comment: One comment was received on the proposed rule specific to ferroalloy production facilities. The commenter requested that EPA allow ferroalloy production facilities to use alternative methods for determining EAF process CO2emissions other than those proposed, and specifically a protocol for silicon metal production facilities developed for use by the Chicago Climate Exchange. This smelting protocol was developed a protocol for calculating the

CO2emissions from based on the World Resources Institute

(WRI) aluminum smelting protocol.

Response: We reviewed the WRI aluminum smelting protocol, which was publicly available and we tried to obtain a copy of the specific protocol that the commenter mentions to fully evaluate whether it is an appropriate alternative. However, we never received it in the long run.

The commenter did not provide additional or more specific recommendations beyond the reference to improve or revise the proposed methodology. At this time, given insufficient information, we have decided not to include additional alternative methods in the final rule for ferroalloy production facilities. As we stated at proposal, the selected methodology was based on review of several existing methodologies used by the 2006 IPCC Guidelines for National Greenhouse

Gas Inventories, Canadian Mandatory Greenhouse Gas Reporting Program, the Australian National Greenhouse Gas Reporting Program, and EU

Emissions Trading System.

However, we have revised the frequency of sampling and analysis of carbon contents for carbon containing input and output materials monthly to annual consistent with revisions made in response to comments for similar production processes (e.g. emissions from metal production). These revisions reduce the reporting burden for ferroalloy production facilities. We understand that the carbon content of material inputs and outputs does not vary widely at a given facility for the significant process inputs that contain carbon, and we continue to account for variations due to changes in production rate, which is likely a more significant source of variability. The response to the comment can be found in ``Mandatory Greenhouse Gas Reporting Rule:

EPA's Response to Public Comments, Subpart K: Ferroalloy Production.''

L. Fluorinated GHG Production

At this time EPA is not going final with the subpart for emissions from fluorinated GHG production. As we consider next steps, we will be reviewing the public comments and other relevant information.

The Agency received a number of lengthy, detailed comments regarding the fluorinated GHG production subpart. Commenters generally opposed the proposed reporting requirements. Several commenters stated that facilities could not meet the proposed accuracy, precision, and frequency requirements using existing equipment and practices. These commenters stated that they would need to expend significant funds

(millions of dollars in some cases) and time to install Coriolis flowmeters in multiple streams and to implement daily sampling protocols to analyze the contents of these streams. Some commenters stated that even after such equipment was installed, the proposed mass- balance approach was likely to be inaccurate, particularly for batch processes. In most cases, commenters provided alternative approaches, such as emission-factor based approaches, to the proposed mass-balance approach.

Based on careful review of comments received on the proposal preamble, rule, and TSDs under proposed 40 CFR part 98, subpart L, EPA will perform additional analysis and evaluate a range of data collection procedures and methodologies. EPA's goal is to optimize methods of data collection to ensure data accuracy while considering industry burden.

M. Food Processing

At this time, EPA is not going final with the Food Processing

Subpart. The sources of GHG emissions at food processing facilities that were to be reported under the proposed rule were stationary fuel combustion, onsite landfills, and onsite wastewater treatment. EPA has decided not to finalize the portion of 40 CFR part 98, subpart HH

(Landfills) that addresses industrial landfills nor 40 CFR part 98, subpart II (Wastewater Treatment). Note, however, that Stationary fuel combustion sources at food processing facilities are subject to the requirements of 40 CFR part 98, subpart C if general stationary fuel combustion emissions exceed the 25,000 metric ton CO2e threshold. As EPA considers next steps, we will be reviewing the public comments and other relevant information.

Based on careful review of comments received on the proposal preamble, rule and TSDs under proposed 40 CFR part 98, subparts M, HH, and II, EPA will perform additional analysis and consider alternatives to data collection procedures and methodologies contained in those subparts.

N. Glass Production 1. Summary of the Final Rule

Source Category Definition. The glass production source category consists of facilities that manufacture glass (including flat, container, pressed, or blown glass) or wool fiberglass using one or more continuous glass melting furnaces. Experimental furnaces and research and development process units are excluded.

Reporters must submit annual GHG reports for facilities that meet the applicability criteria in the General Provisions (40 CFR 98.2) summarized in Section II.A of this preamble.

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GHGs to Report. For glass production facilities, report the following emissions:

CO2process emissions from each continuous glass melting furnace.

CO2combustion emissions from each continuous glass melting furnace,

CH4and N2O emissions from fuel combustion at each continuous glass melting furnace under 40 CFR part 98, subpart C (General Stationary Combustion Sources) using the methodologies in subpart C.

CO2, CH4, and N2O emissions and from each onsite stationary fuel combustion unit other than continuous glass melting furnaces under 40 CFR part 98, subpart C

(General Stationary Combustion Sources).

In addition, report GHG emissions for any other source categories at the facility for which calculation methods are provided in other subparts of the rule, as applicable.

GHG Emissions Calculation and Monitoring. For CO2 process emissions from glass melting furnaces, reporters must use one of two methods, as appropriate:

For glass melting furnaces with certain types of CEMS in place, reporters must use the CEMS and follow the Tier 4 methodology

(in 40 CFR part 98, subpart C) to measure and report under the glass production subpart (40 CFR part 98, subpart N) combined process and combustion CO2emissions.

For other glass melting furnaces, the reporter can elect to either (1) install and operate a CEMS and follow the Tier 4 methodology to measure and report combined process and combustion

CO2emissions or (2) calculate process CO2 emissions for each furnace using an emission factor and process data.

If using approach (2), multiply a default emission factor appropriate for the carbonate raw material by:

--The annual mass of carbonate-based raw material charged to the furnace (required to be measured); and

--The mass-fraction of carbonate in the raw material (based on data supplied by the raw material supplier and verified by an annual measurement).

--Under approach (2), report process CO2emissions from each glass melting furnace under 40 CFR part 98, subpart N (Glass

Production), and report combustion CO2emissions from each glass furnace under 40 CFR part 98, subpart C (General Stationary Fuel

Combustion Sources).

Data Reporting. In addition to the information required to be reported by the General Provisions (40 CFR 98.3(c)) and summarized in

Recordkeeping. In addition to the records required by the General

Response to Public Comments, Subpart N: Glass Production.''

The definition of the term ``glass produced'' was added to the definitions in 40 CFR part 98, subpart A. 40 CFR 98.146 was reorganized and updated to improve the emissions verification process. Some data elements were moved from 40

CFR 98.147 to 40 CFR 98.146, and some data elements that a reporter must already use to calculate GHGs as specified in 40 CFR 98.143 were added to 40 CFR 98.146 for clarity. 3. Summary of Comments and Responses

This section contains a brief summary of major comments and responses. Several comments on glass production were received covering numerous topics. Responses to significant comments received can be found in ``Mandatory Greenhouse Gas Reporting Rule: EPA's Response to

Public Comments, Subpart N: Glass Production.''

Definition of Source Category

Comment: One commenter stated that EPA should exempt from the rule all fiber glass and rock and slag wool insulation facilities within the glass production source category because glass production facilities subject to the proposed rule are a miniscule portion of the total national emissions of CO2e, and amount to less than 0.1 percent of total GHG emissions in the U.S. and the subset of fiber glass and rock and slag wool insulation facilities is an even smaller portion. The commenter stated that there is virtually no benefit to having the glass production source category subject to the proposed rule, and any benefit is outweighed by the burden imposed on these facilities. The commenter also pointed out the importance of the fiber glass and rock and slag wool insulation industry's products in meeting the nation's energy needs and reducing GHG emissions. Exempting the industry from the proposed rule's reporting requirements will help the industry focus more of its scarce resources on producing insulation.

Response: We recognize that the glass manufacturing industry is comprised of a wide range of facilities, many of which are small in size and have relatively low levels of emissions. However, the data we have collected on the industry indicate that there are several large glass manufacturing plants with significant GHG emissions. These plants include some that produce glass fiber, flat glass, and container glass, as well as other types of pressed and blown glass products. As a result, we do not agree with the commenter that fiber glass and other types of insulation facilities should be exempt from reporting.

However, we tried to reduce the burden on the glass manufacturing industry by incorporating into the proposed rule a 25,000 metric ton

CO2e threshold, which should preclude small facilities from having to report GHGs. This threshold remains in the final rule. Thus, any small fiber glass and rock and slag wool insulation facilities with low GHG emissions will fall under the threshold and will be exempt from reporting. To further minimize the burden on the industry, we have tried to limit recordkeeping and reporting requirements to the types of data that glass production facilities already collect as part of normal business operations.

Commenters may also be interested in reviewing Section II.H of this preamble for the response on provisions to cease reporting. The final rule contains provisions to cease reporting if annual reports demonstrate emissions less than specified levels for multiple years.

Selection of Threshold

Comment: One commenter remarked that EPA should raise the threshold for reporting for fiberglass and rock and slag wool insulation entities. Doing so would reduce the number of entities reporting with only a minimal impact on the amount of emissions covered. The commenter stated that EPA's analysis did not address reasonable alternative thresholds between 25,000 and 100,000 metric tons.

Response: When evaluating potential thresholds for reporting GHG emissions, we considered several thresholds

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between 1,000 and 100,000 metric tons CO2e. We selected the 25,000 metric tons CO2e threshold for reporting GHG emissions in order to achieve a balance between quantifying the majority of the emissions and minimizing the number of facilities impacted. For example, at a 1,000 metric tons CO2e threshold, 98 percent of emissions would be covered, with about 58 percent of facilities being required to report. Compared to the 100,000 metric tons CO2e threshold, the proposed 25,000 metric tons

CO2e threshold achieves reporting of 11 times more emissions while requiring less than 15 percent of the facilities to report.

Compared to the 10,000 metric tons CO2e threshold, the 25,000 metric tons CO2e threshold captures more than half of those emissions, but only requires a third of the facilities in the industry to report. This threshold offers significant coverage of the

GHG emissions while impacting a relatively small portion of the industry. Although a threshold of 50,000 metric tons CO2e would greatly reduce the number of facilities reporting, it would capture less than 20 percent of total emissions for the industry. We believe the proposed threshold of 25,000 metric tons CO2e represents the best option for ensuring that the majority of emissions are reported without imposing an unreasonable burden on the industry.

Section II.E of this preamble contains a general discussion of the selection of the 25,000 metric tons CO2e threshold.

Method for Calculating GHG Emissions

Comment: One commenter fully supports EPA's proposed rule for measuring, calculating, monitoring, and reporting emissions from the glass melting process. They agree that 40 CFR part 98, subpart N represents a good balance between site reporting burden, cost, and data accuracy and consistency. Specifically, the commenter supports using raw-material emissions factors and usage rates, as proposed, to calculate emissions from glass production in lieu of requiring installing CEMs on sources that another regulation does not currently require to be installed.

Response: We acknowledge this support for the proposal and appreciate these comments. We have retained the proposed calculation methodology in the final rule.

Data Reporting Requirements

Comment: One commenter stated that, at various places in the preamble and proposed rule, EPA uses the phrase ``glass produced,'' but has not defined this phrase in the rule. The commenter noted that the phrase could be interpreted to mean either glass melted or glass product produced. The commenter assumed that the phrase refers to the amount of glass melted, but requested clarification.

Response: We agree that the term glass produced is subject to interpretation. We have added a definition of the term to 40 CFR part 98, subpart A of the final rule. ``Glass produced'' means the weight of glass exiting a glass melting furnace.

Comment: One commenter remarked that some of the information that would have to be reported under the proposed rule, such as annual quantity of glass produced, is considered to be company confidential and could be used by competitors to back-calculate product formulas.

The commenter requested that EPA remove these reporting requirements from the rule and instead, require that the data be retained by the facility and made available for review by EPA. Should EPA require the reporting of all of this information in the final rule, the commenter requests that EPA explicitly state in the final rule and confirm in the preamble to the final rule that all information provided under 40 CFR part 98, subpart N, other than the annual process emissions of

CO2, is considered confidential information and would not be considered ``emission data'' under this reporting rule. The commenter requests that a new paragraph (e) be added to 40 CFR 98.146 that reads:

``No information required to be reported by this section, other than the information required by 40 CFR 98.146(a), is considered to be emission data under 40 CFR 2.301(a)(2)(i) and (ii).''

Response: We acknowledge the commenter's concerns. However, the quantity of glass produced is an important variable for EPA to verify whether reported emissions are within a reasonable range and therefore is a required reporting parameter under 40 CFR part 98, subpart N.

We have reviewed CBI comments received across the rule (both general and subpart-specific comments) and our response is discussed in

Section II.R of this preamble and in ``Mandatory Greenhouse Gas

Reporting Rule: EPA's Response to Public Comments, Legal Issues.''

O. HCFC-22 Production and HFC-23 Destruction 1. Summary of the Final Rule

Source Category Definition. This source category consists of:

Processes that produce HCFC-22 (chlorodifluoromethane or

CHClF2) using chloroform and hydrogen fluoride.

HFC-23 destruction processes located at HCFC-22 production facilities.

HFC-23 destruction processes that destroy more than 2.14 metric tons of HFC-23 per year and that are not located at HCFC-22 production facilities.

Reporters must submit annual GHG reports for facilities that meet the applicability criteria in the General Provisions (40 CFR 98.2) summarized in Section II.A of this preamble.

GHGs to Report. For facilities that produce HCFC-22 or that destroy

HFC-23, report the following emissions:

HFC-23 emissions from all HCFC-22 production processes at the facility.

HFC-23 emissions from each destruction process.

In addition, report GHG emissions for other source categories at the facility for which calculation methods are provided in the rule, as applicable. For example, report CO2, N2O, and

CH4emissions from each stationary combustion unit on site by following the requirements of 40 CFR part 98, subpart C (General

Stationary Fuel Combustion Sources).

GHG Emissions Calculation and Monitoring. Reporters must calculate

HFC-23 emissions as follows:

For HCFC-22 production processes that do not use a thermal oxidizer or that have a thermal oxidizer that is not connected to the production equipment, calculate annual HFC-23 emissions at the facility level using a mass balance equation and the following information: annual HFC-23 generated, the annual HFC-23 sent off site for sale, the annual HFC-23 sent off site for destruction, the annual increase in the

HFC-23 inventory, and the annual HFC-23 destroyed on site (calculated by multiplying the mass of HFC-23 fed to the destruction device by the destruction efficiency).

For HCFC-22 production processes with a thermal oxidizer that is connected to the production equipment, calculate annual HFC-23 emissions at the facility level by summing the following emissions:

--Annual HFC-23 emissions from equipment leaks (calculated using default emission factors and the measured number of leaks in valves, pump seals, compressor seals, pressure relief valves, connectors, and open-ended lines).

--Annual HFC-23 emissions from process vents (calculated for each vent using the HFC-23 emission rate from the most recent emission test and the ratio of the actual production

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rate and the production rate during the emission test).

--Annual HFC-23 from the thermal oxidizer (calculated by subtracting the amount of HFC-23 destroyed by the destruction device from the measured mass of HFC-23 fed to the destruction device).

For other HFC-23 destruction processes, calculate HFC-23 emissions based on the mass of HFC-23 fed to the destruction device and the destruction efficiency.

For the destruction efficiency, conduct a performance test or use the destruction efficiency determined during a previous performance test. To confirm the destruction efficiency, measure the fluorinated GHG concentration at the outlet to the destruction device annually.

Data Reporting. In addition to the information required to be reported by the General Provisions (40 CFR 98.3(c)) and summarized in

Recordkeeping. In addition to the records required by the General

Response to Public Comments, Subpart O: HCFC-22 Production and HFC-23

Destruction.''

The minimum required frequency of mass flow and concentration measurements has been decreased from daily to weekly.

The required frequency of emissions tests at process vents has been decreased to once every five years. A test is also required after a significant change is made to the process.

The required annual measurements at the outlet of the thermal oxidizer now omit measurements of mass flow. Three samples are required to be taken; the average of these is compared to the concentration at the outlet of the oxidizer that was measured during the initial performance test that established the destruction efficiency.

A term has been added to the mass-balance equation for

HCFC-22 production facilities that do not have a thermal oxidizer that is directly connected to the HCFC-22 production equipment. This term accounts for increases in the inventory of stored HFC-23 that can occur during the year.

EPA has added an additional method for estimating missing mass flow data in the event that a secondary mass measurement for that stream is not available.

The option for reporters to develop their own methods for estimating missing data if they believe that the prescribed method will over- or under-estimate the data has been removed.

Some reporting requirements have been added to be consistent with the changes to the calculations and monitoring sections and to permit verification of emissions calculations.

EPA decreased the minimum frequency of gas flow and concentration measurements from daily to weekly because EPA's research indicates that

HFC-23 concentrations are not likely to vary significantly over a one week period. This change also makes the required measurement frequency more consistent with current industry practice.

As noted above, EPA removed the option for reporters to develop their own methods for estimating missing data if they believe that the prescribed method will over- or underestimate the data. EPA removed this option for two reasons. First, the proposed provision lacked clear guidance on when alternative methods should be used (e.g., on the size of an underestimate that would justify use of an alternative method) and on how they should be developed. Second, the proposed provision was redundant with the new provision that permits reporters to estimate missing data using a related parameter and the historical relationship between the related parameter and the missing parameter. This new option provides reporters with flexibility in substituting for missing data in the event that a secondary mass measurement is not available, but sets out general guidance on how to select the substitute data. 3. Summary of Comments and Responses

This section contains a brief summary of major comments and responses. A number of comments on HCFC-22 production and HFC-23 destruction were received covering numerous topics. Responses to significant comments received can be found in ``Mandatory Greenhouse

Gas Reporting Rule: EPA's Response to Public Comments, Subpart O: HCFC- 22 Production and HFC-23 Destruction.''

Monitoring and QA/QC Requirements

Comment: EPA received a comment that the requirement to annually conduct emissions tests at process vents is overly burdensome and unnecessary because it is unlikely that the emissions rate would deviate from an initial process vent test unless there were a significant change in the process. This commenter argued that testing should be required at least every five years or after a significant change in the process.

Response: In response to this comment, EPA has reduced the required frequency of emissions tests at process vents to once every five years, or after a significant change to the process. EPA has also clarified that the requirement applies only to HCFC-22 production facilities that use a thermal oxidizer connected to the HCFC-22 production equipment.

These are the only facilities that use process vent emission estimates in their calculation of facility-wide HFC-23 emissions.

EPA is decreasing the frequency of emissions tests at process vents for two reasons. First, EPA agrees with the commenter that, in the absence of a significant process change, the process vent emission rate is not likely to vary much (in percentage terms) from year to year.

Second, although small variations in the emission rate could still lead to significant absolute errors for facilities with large process vent emissions, the facilities that are required to test their process vent emissions are likely to have small process vent emissions (because they use thermal oxidizers connected to the production equipment).

(Facilities that do not use thermal oxidizers connected to the equipment would be expected to have larger process vent emissions, but they are required to use a mass-balance approach to calculate emissions rather than summing emissions across process vents, equipment leaks, and thermal oxidizers.) Together, these considerations lead to the conclusion that testing process vent emissions every five years should sufficiently minimize errors in the overall HFC-23 emission calculations of the facilities affected by the testing requirement.

Comment: EPA should add a term to Equation O-4 (the mass-balance equation for HCFC-22 production facilities that do not have a thermal oxidizer that is directly connected to the HCFC-22 production equipment) to account for increases in the inventory of

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stored HFC-23 that can occur during the year.

Response: EPA added a term to Equation O-4 for increases in the inventory of stored HFC-23. EPA agrees that the equation should account for changes in the inventory of HFC-23 that is stored on site. It is important to track all reservoirs of HFC-23 at the facility; mass- balance approaches used to track emissions from other sources (e.g., from electrical equipment) frequently include terms to account for the increase in inventory.

Definition of Source Category

Comment: EPA received a comment that the measurement of HFC-23 emissions from HCFC-22 production should be moved to Subpart L, which covers the reporting of fluorinated GHG production.

Response: EPA proposed provisions for facilities producing fluorinated gases in three separate subparts: 40 CFR part 98, Subpart

L, Subpart O, and Subpart OO. Although there are many similarities across the chemicals and processes covered by the three subparts, the subparts were deliberately tailored to different sources and types of emissions. Subpart L was intended to address emissions of fluorinated

GHGs from fluorinated GHG production. 40 CFR part 98, subpart O was intended to address HFC-23 generation and emissions from HCFC-22 production. 40 CFR part 98, subpart OO was intended to address flows affecting the U.S. industrial gas supply, including production, transformation, and destruction.

EPA determined that 40 CFR part 98, subpart O was necessary because

HCFC-22 production and HFC-23 destruction facilities differ from other fluorinated gas production facilities in two key respects. First, the primary fluorinated GHG that they generate (HFC-23) is made as a byproduct to the production of a substance that is not defined as a fluorinated GHG (HCFC-22). Second, due to the very high GWP of HFC-23, each HCFC-22 facility generates very large quantities of

CO2-equivalent. For the second reason, EPA has worked with

HCFC-22 producers for over ten years to understand and reduce HFC-23 emissions. The requirements for HCFC-22 producers are therefore based on a close knowledge of their production processes and methods for accounting for emissions. These methods are also comprehensive (e.g., accounting for emissions from equipment leaks and losses during transport of HFC-23 that is shipped off-site for destruction). These requirements may not be appropriate for other fluorinated gas producers, and, at the same time, the requirements for fluorinated gas producers may not be appropriate for HCFC-22 producers.

P. Hydrogen Production 1. Summary of the Final Rule

Source Category Definition. The merchant hydrogen production source consists of process units that produce hydrogen by reforming, gasification, or other transformation of feedstock and transfer the hydrogen produced off site. Hydrogen production facilities located at petroleum refineries or other large facilities are included in this source category only if they are not owned by or under the direct control of the refinery owner. Otherwise, they are considered to be a captive hydrogen production source that reports emissions under the subpart applicable to the larger facility, e.g., 40 CFR part 98, subpart Y (Petroleum Refineries).

Reporters must submit annual GHG reports for facilities that meet the applicability criteria in the General Provisions (40 CFR 98.2) summarized in Section II.A of this preamble.

GHGs to Report. For hydrogen production, report the following emissions:

CO2process emissions from hydrogen production.

CO2, N2O, and CH4 emissions from each stationary combustion unit on site by following the requirements of 40 CFR part 98, subpart C (General Stationary Fuel

Combustion Sources).

CO2collected and transferred off site under 40

CFR part 98, subpart PP (Suppliers of Carbon Dioxide).

In addition, report GHG emissions for other source categories for which calculation methods are provided in the rule, as applicable.

GHG Emissions Calculation and Monitoring.

To calculate and report process CO2emissions from hydrogen production, most reporters can elect to either (1) install and operate CEMS and follow the Tier 4 methodology (in 40 CFR part 98, subpart C) or (2) calculate process CO2emissions using equations in the 40 CFR part 98, subpart P and the following data:

--Measurements of monthly feedstocks and fuel consumed.

--Carbon content of the feedstock measured monthly.

--Molecular weight of the feedstock (gaseous fuels only).

However, if process CO2emissions from hydrogen production are vented through the same stack as a combustion unit or process equipment that uses a CEMS to follow Tier 4 methodology to report CO2emissions, then the CEMS must be used to measure and report combined CO2emissions from that stack instead of the calculation procedure described in approach 2 above.

Monitoring and QA/QC Requirements. The methods for the initial calibration and annual recalibration of flow meters are defined in a prescriptive list of industry standard test methods incorporated by reference in the Tier 3 method in 40 CFR part 98, subpart C, while the methods for determining carbon content of fuels and feedstocks are defined in a prescriptive list of an assortment of industry standard test methods incorporated by reference.

Data Reporting. In addition to the information required to be reported by the General Provisions (40 CFR 98.3(c)) and summarized in

Recordkeeping. In addition to the records required by the General

Response to Public Comments, Subpart P: Hydrogen Prodution.'' 40 CFR 98.160 was reworded to clarify the definition of reporting entity. 40 CFR 98.162 was revised to allow reporting of combined process and combustion CO2, CH4, and

N2O emissions.

In 40 CFR 98.163(b), ``feedstock'' was changed to ``fuel and feedstock''. 40 CFR 98.164 was restructured to clarify between CEMS measurements and QA/QC and feedstock method measurements and QA/QC. 40 CFR 98.164 was reworded to allow the characterization of feedstocks to be conducted by either the consumer or the supplier, to allow standard gaseous hydrocarbon fuels of commerce to be characterized annually, and to allow liquid and solid hydrocarbon fuels of commerce to be characterized

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upon delivery if delivered by bulk transport.

The recalibration requirements in 40 CFR 98.164 were changed to reduce economic impact.

The list of standards incorporated by reference in 40 CFR 98.164 was broadened.

The missing data procedures in 40 CFR 98.165 were revised to be consistent with 40 CFR 98.35(b). 40 CFR 98.166 and 98.167 were restructured to distinguish between CEMS recordkeeping and feedstock method recordkeeping. 40 CFR 98.166 was reorganized and updated to improve the emissions verification process. Some data elements were moved from 40

CFR 98.167 to 40 CFR 98.166, and some data elements that a reporter must already use to calculate GHGs as specified in 40 CFR 98.163 were added to 40 CFR 98.166 for clarity. 3. Summary of Comments and Responses

This section contains a brief summary of major comments and responses. A large number of comments on hydrogen production were received covering numerous topics. Responses to significant comments received can be found in ``Mandatory Greenhouse Gas Reporting Rule:

EPA's Response to Public Comments, Subpart P: Hydrogen Production.''

Definition of Source Category

Comment: Multiple commenters pointed out the lack of clarity regarding the definition of the reporting entity, and suggested defining the entity holding the air permit for an affected facility as the reporting entity. For example, ``If the owner/operator of the facility is the holder of the air permit for an affected facility, then the operator should be responsible for reporting GHG emissions. If not, then EPA should clarify the responsibility for reporting.''

Response: EPA reviewed this complex issue. First, a facility is defined in 40 CFR 98.6: ``Facility means any physical property, plant, building, structure, source, or stationary equipment located on one or more contiguous or adjacent properties in actual physical contact or separated solely by a public roadway or other public right-of-way and under common ownership or common control, that emits or may emit any greenhouse gas.'' Therefore, any hydrogen production process unit that is not part of a larger facility covered by another subpart of this rule is a merchant hydrogen production facility which reports emissions under 40 CFR part 98, subpart P. On the other hand, a hydrogen production process unit that is part of a larger facility covered by another subpart of this rule is a captive hydrogen production facility that does not report emissions under 40 CFR part 98, subpart P. Their emissions, including those emissions from the captive hydrogen production facility, are reported under the subpart applicable to the larger facility. Second, in answer to the question, ``Do I need to report?'', 40 CFR 98.2 states that the rule applies to a facility that contains any source category listed in 40 CFR 98.2(a)(2) (which includes hydrogen production) and that emits 25,000 metric tons

CO2e or more per year in combined emissions from stationary fuel combustion units, miscellaneous uses of carbonates, and all source categories listed in 40 CFR 98.2(a)(2). EPA has concluded that the rule explains this clearly in 40 CFR 98.2 and 98.6, and that it is not necessary to change the rule. To add clarity, however, EPA has revised 40 CFR 98.160(c) as follows: ``This source category includes merchant hydrogen production facilities located within a petroleum refinery if they are not owned by, or under the direct control of, the refinery owner and operator.''

GHGs To Report

Comment: Multiple commenters requested clarification on the

CO2emission reporting obligation as combined ``process'' and ``combustion'' CO2emissions, regardless of the calculation method employed. If separate, discrete reporting of such emissions is actually required, commenters asked EPA to provide explicit protection for this information which they stated was very critical CBI.

Response: In response to these multiple commenters, EPA has clarified the rule in 40 CFR 98.162 to provide operators the option of providing combined process and combustion CO2emissions for each hydrogen production process unit whether or not it meets the conditions in 40 CFR 98.33(b)(4)(ii) and (iii) for CEMs. Under 40 CFR 98.166, facilities must report additional parameters for emissions verification.

See Sections II.I and II.N of this preamble for responses to the comments received on the general content of the annual GHG report and the emissions verification approach, respectively. EPA reviewed CBI comments received across the rule (both general and subpart-specific comments) and our response is discussed in Section II.R of this preamble and in ``Mandatory Greenhouse Gas Reporting Rule: EPA's

Response to Public Comments, Legal Issues.''

Method for Calculating GHG Emissions

Comment: Multiple commenters pointed out the need for a calculation method to account for feedstock carbon that does not exit the hydrogen production facility as CO2, but rather in the form of other products or co-products that contain carbon (such as synthesis gas, CO,

CH4). Many argued in favor of correcting equations P-1, P-2 and P-3 to account for feedstock carbon that does not exit the hydrogen production facility as CO2, but rather as products (such as synthesis gas, CO, CH4) that are manufactured which contain carbon.

Response: EPA generally concurs with the need to account for

``carbon other than CO2'' that exits the facility. EPA considered several options for reporting such carbon and chose to have facilities report CO2and ``carbon other than

CO2'' as separate data reporting elements in 40 CFR 98.166 rather than including this carbon in equations P-1, P-2, and P-3. As a result, EPA has added data reporting elements under 40 CFR 98.166 for

(1) quarterly quantity of CO2collected and transferred off site in either gas, liquid, or solid forms (metric tons), following the requirements of 40 CFR part 98, subpart PP of this part, and (2) annual quantity of carbon other than CO2collected and transferred off site in either gas, liquid, or solid forms (metric tons).

Monitoring and QA/QC Requirements

Comment: Multiple commenters recommended that EPA should allow the characterization of feedstocks (sampling and analysis) to be conducted by either the feedstock consumer (the regulated source) or the feedstock supplier. They state that the characterization of standard fuels of commerce used as hydrogen production feedstocks, such as natural gas, should not be required since default values will yield a sufficiently accurate emission estimate. Commenters recommend that characterization of such standard fuels of commerce used as feedstocks be optional, at the source's discretion.

Response: EPA concurs with this comment, since feedstock suppliers regularly monitor the carbon content of their fuels and also, the carbon content of standard fuels of commerce are quite consistent month to month. EPA has revised this section to allow the characterization of feedstocks to be conducted by either the consumer or the supplier, to allow standard gaseous hydrocarbon fuels of commerce to be characterized annually, and allow liquid

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and solid hydrocarbon fuels of commerce to be characterized upon delivery if delivered by bulk transport (e.g., by truck or rail). Other non-standard gaseous fuels and feedstocks must still be subjected to weekly sampling and analysis to determine the carbon content and molecular weight.

Comment: Commenters recommended that EPA limit the requirement for sampling non-gaseous fuels to new deliveries rather than monthly in order to pinpoint the onset of fuel parameter variations.

Response: EPA concurs that the carbon content of a liquid or solid hydrocarbon fuel delivered in bulk will remain constant as the stock on hand from the delivery is consumed, and therefore periodic testing during the interim is not needed. EPA has revised this section to allow the characterization of feedstocks to be conducted by either the consumer or the supplier, to allow standard gaseous hydrocarbon fuels of commerce to be characterized annually, and allow liquid and solid hydrocarbon fuels of commerce to be characterized upon delivery if delivered by bulk transport (e.g., by truck or rail). On the other hand, other non-standard gaseous fuels and feedstocks must still be subjected to weekly sampling and analysis to determine the carbon content and molecular weight since their carbon content can vary significantly from week to week.

Comment: Multiple commenters recommended that EPA should include provisions for an extension of the required meter/monitor calibration deadline (as well as the initial calibration, if appropriate) when the calibration would require removing the process line from service. They recommend that the calibration requirement be extended to the next scheduled maintenance shutdown for the impacted unit/process.

Response: EPA concurs that requiring the facility to remove the process line from service represents an undue hardship and has therefore revised 40 CFR part 98, subpart P to refer to the less stringent monitoring and QA/QC requirements for the Tier 3 methodology included in 40 CFR part 98, subpart C (General Stationary Fuel

Combustion Sources).

Comment: One commenter suggested adding ISO 5167-1 through ISO 5167-4 (Measurement of Fluid Flow by Means of Pressure Differential

Devices) to list of standards incorporated by reference.

Response: EPA agrees ISO 5167-1 through ISO 5167-4 are suitable calibration standards and would be good additions to the list of standards. However, given that the issues covered by these standards

(Venturi and orifice plate differential pressure flow meters) are covered by two American Society of Mechanical Engineers (ASME) standards, one ASHRAE standard, and one AGA report which are already included in 40 CFR 98.164, EPA has not explicitly added these references to the list of standards incorporated by reference.

Procedures for Missing Data

Comment: Multiple commenters recommended that the data substitution method for missing feedstock supply rate data should be changed to be consistent with 40 CFR 98.35(b)(2), allowing use of the ``best available estimate'', and that the data substitution method for missing feedstock carbon content data should be changed to be consistent with 40 CFR 98.35(b)(1), allowing use of the average before/after values.

Response: EPA concurs that the required level of accuracy for hydrogen production is similar to that required for stationary combustion, and that the less stringent ``best available estimate'' approach is appropriate for hydrogen production. Therefore, EPA has changed 40 CFR 98.165 to follow the data substitution method for missing fuel carbon content data prescribed in 40 CFR 98.35 and the data substitution method for missing fuel usage data prescribed in 40

CFR 98.35.

Data Reporting Requirements

Comment: Multiple commenters stated that annual feedstock consumption, annual hydrogen production, and feedstock carbon content are confidential business information (CBI) and should not be reported.

The commenters asked that this information be maintained by the facility and be made available to the Agency upon request. One commenter further stated that if data must be reported, the reporting rules must provide explicit protection for this very critical confidential business information.

Response: Feedstock consumption and feedstock carbon content are parameters used to calculate emissions. Since annual CO2 emissions are calculated from the sum of the products of monthly feedstock consumption multiplied by the monthly average carbon content of the feedstock, all of these parameters are required for emissions data verification purposes. Annual hydrogen production is an additional parameter which is necessary for EPA to effectively verify emissions, since the ratio of carbon emissions to hydrogen production is relatively consistent for each hydrogen production facility. See

Section II.N of this preamble for information on emissions verification. EPA reviewed CBI comments received across the rule (both general and subpart-specific comments) and our response is discussed in

Section II.R of this preamble and in ``Mandatory Greenhouse Gas

Reporting Rule: EPA's Response to Public Comments, Legal Issues.''

Q. Iron and Steel Production 1. Summary of the Final Rule

Source Category Definition. The iron and steel production source category consists of facilities with any of the following processes:

Taconite iron ore processing.

Integrated iron and steel manufacturing.

Cokemaking not co-located with an integrated iron and steel manufacturing process.

EAF steelmaking not co-located with an integrated iron and steel manufacturing process.

Integrated iron and steel manufacturing means the production of steel from iron ore or iron ore pellets. At a minimum, an integrated iron and steel manufacturing process has a basic oxygen furnace for refining molten iron into steel. Each cokemaking process and EAF process located at a facility with an integrated iron and steel manufacturing process is part of the integrated iron and steel manufacturing facility.

Reporters must submit annual GHG reports for facilities that meet the applicability criteria in the General Provisions (40 CFR 98.2) summarized in Section II.A of this preamble.

GHGs to Report. Report the following emissions annually:

CO2, CH4, and N2O emissions from fuel combustion at each stationary combustion unit according to the requirements in 40 CFR part 98, subpart C (General

Stationary Fuel Combustion Sources). Stationary combustion units include, but are not limited to, byproduct recovery coke oven battery combustion stacks, blast furnace stoves, boilers, process heaters, reheat furnaces, annealing furnaces, flame suppression, ladle reheaters, and any other miscellaneous combustion sources (except flares).

CO2emissions from flares according to the requirements in 40 CFR part 98, subpart Y (Petroleum Refineries) and

CH4and N2O emissions from flares using the default emission factors for coke oven gas and blast furnace gas.

CO2process emissions from each taconite indurating furnace, basic oxygen furnace, nonrecovery coke oven

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battery combustion stack, coke pushing process, sinter process, EAF, argon-oxygen decarburization vessel, and direct reduction furnace.

In addition, report GHG emissions for any other source categories at the facility for which calculation methods are provided in other subparts of the rule, as applicable.

GHG Emissions Calculation and Monitoring. For CO2 process emissions at each taconite indurating furnace, basic oxygen furnace, nonrecovery coke oven battery, sinter process, EAF, argon- oxygen decarburization vessel, and direct reduction furnace, reporters must calculate emissions using one of the following methods, as appropriate:

Most reporters can elect to calculate and report process

CO2emissions by either: (1) Installing and operating a CEMS and following the Tier 4 methodology (in 40 CFR part 98, subpart C) or

(2) using one of the following two calculation procedures:

--Use a carbon balance method described in 40 CFR part 98, subpart Q to calculate the annual mass emissions rate of CO2for each process, based on the annual mass of inputs and outputs and an annual analysis of the respective weight fraction of carbon in each process input or output that contains carbon. Use separate procedures and equations for taconite indurating furnaces, basic oxygen process furnaces, nonrecovery coke oven batteries, sinter processes, EAFs, argon-oxygen decarburization vessels, and direct reduction furnaces, or

--Use a site-specific emission factor determined from a performance test that measures CO2emissions from all exhaust stacks and also measures either the feed rate of materials into the process or the production rate during the test for taconite indurating furnaces, basic oxygen process furnaces, nonrecovery coke oven batteries, sinter processes, EAFs, argon-oxygen decarburization vessels, and direct reduction furnaces.

However, if process CO2emissions from a taconite indurating furnace, basic oxygen furnace, nonrecovery coke oven battery, sinter process, EAF, argon-oxygen decarburization vessel, and direct reduction furnace are emitted through the same stack as

CO2emissions from a combustion unit or process equipment that uses a CEMS and follows the Tier 4 methodology to report

CO2emissions, then the CEMS must be used to measure and report combined CO2emissions from that stack. In such cases, the reporter cannot use the other process CO2 calculation approaches outlined above.

For coke oven pushing, facilities must use a

CO2emission factor provided in the rule.

Data Reporting. In addition to the information required to be reported by the General Provisions (40 CFR 98.3(c)) and summarized in

Recordkeeping. In addition to the records required by the General

Response to Public Comments, Subpart Q: Iron and Steel Production.''

The major changes made since proposal include:

The carbon mass balance method was revised to require an annual analysis of all process inputs and outputs for carbon content rather than weekly sampling and monthly analysis.

The site-specific emission factor method was revised to:

(1) Require testing based on representative performance rather than at 90 percent of capacity, (2) sampling for a minimum of three hours or production cycles rather than nine, (3) conducting separate tests for each different process condition that is a part of normal operation if the change in CO2emissions at the different conditions is more than 20 percent, and (4) adding a provision to clarify testing requirements when the EAF and argon-oxygen decarburization vessel are ducted to the same control device and stack.

To improve the emissions verification process, 40 CFR 98.176 was reorganized and updated. Some data elements were moved from 40 CFR 98.177 to 40 CFR 98.176, and some data elements that a reporter must already use to calculate GHGs as specified in 40 CFR 98.173 were added to 40 CFR 98.176 for clarity. 3. Summary of Comments and Responses

This section contains a brief summary of major comments and responses related to the requirements for iron and steel processes. A large number of comments on iron and steel production were received covering numerous topics. Many of these comments were directed at the requirements for 40 CFR part 98, subpart C (General Stationary Fuel

Combustion Sources), and responses to those comments are provided in

Section III.C of this preamble. Also see the Section II.N of this preamble for the response to comments on the emissions verification approach. Responses to other significant comments received related to process emissions from iron and steel production can be found in

``Mandatory Greenhouse Gas Reporting Rule: EPA's Response to Public

Comments, Subpart Q: Iron and Steel Production.''

Method for Calculating GHG Emissions

Comment: Several industry representatives and their three trade associations requested that EPA allow the use of a simplified facility- wide carbon balance approach developed by the American Iron and Steel

Institute (AISI) to calculate CO2emissions from iron and steel production facilities. According to the commenters, the AISI methodology has recently been adapted to facility-wide reporting and is emerging as the preferred reporting protocol internationally. The commenters described the approach as based on determining the mass of carbon in the most significant carbon-containing inputs entering the plant and in the most significant carbon-containing outputs that leave as products or byproducts (excluding, for example, iron ore, scrap, steel). The difference between the mass of carbon entering the facility and leaving the facility is assumed to be converted to CO2.

The annual mass rates of significant inputs and outputs are determined from company records, and their carbon contents are based on typical or default values. The commenters noted that the AISI approach provides a single estimate of the combined total CO2emissions from all processes and combustion sources at the facility. The commenters claimed that the approach would provide a more accurate and complete accounting of facility-wide emissions at a much lower cost than that of the proposed EPA process-specific methods.

Response: As we explained at proposal (74 FR 16517), we considered the many domestic and international

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monitoring guidelines and protocols for process and combustion sources at iron and steel production facilities, including the AISI facility- wide approach. The vast majority of these guidelines and protocols are process-specific rather than facility-wide approaches (e.g., 2006 IPCC

Guidelines, U.S. Inventory, the World Business Council for Sustainable

Development (WBCSD)/WRI GHG protocol, DOE 1605(b), TCR, European Union

Emissions Trading System, and Environment Canada's mandatory reporting guidelines). In addition, the ``higher tier'' (more accurate) site- specific methods use process-specific approaches. We explained at proposal (74 FR 16517) that we did not choose to propose these approaches based on the use of default values in general (such as the

AISI approach) because the use of default values and lack of direct measurements results in a very high level of uncertainty (greater than 25 percent), and default approaches would not provide site- specific estimates of emissions that reflect differences in feedstocks, operating conditions, fuel combustion efficiency, variability in fuels, and other differences among facilities.

We also stated at proposal that we decided not to finalize the proposal using methodologies that relied on default emission factors or default values for carbon content of materials because the differences among facilities described above could not be discerned, such default approaches are inherently inaccurate for site-specific determinations, and the use of default values is more appropriate for sector wide or national total estimates from aggregated activity data than for determining emissions from a specific facility.

We further note here that the AISI approach is not adequate for our reporting needs because it provides only a single emissions number aggregated from the numerous individual processes and combustion units at the iron and steel facility. In contrast, the approaches we are promulgating today for determining CO2emissions provide information at the process level and distinguish between combustion emissions and process emissions. Information at the process level is needed for many reasons, such as verification of the reported emissions from comparison with known ranges expected from various types of processes for a given production rate and emissions verification based on data for different plants for similar processes. Process-level reporting also provides information that will be useful in identifying processes that have reduced emissions over time and processes at specific plants that have the most potential for future reductions in emissions. In addition, the process-level reporting may provide information that can be used to improve methodologies for specific processes under future programs and to identify processes that may use a technology that could be the basis for an emission standard at a later time.

We developed estimates of costs for the proposed options for determining CO2emissions and concluded that the costs were reasonable. However, as explained below, we have revised the proposed options in response to comments, and these revisions significantly reduce the burden and costs of the carbon mass balance and site- specific emission factor methods while maintaining a similar level of accuracy.

Comment: Several commenters claimed that the proposed carbon mass balance method is unnecessarily burdensome because it requires weekly sampling, monthly analyses, and determining the monthly mass quantities of all process inputs and outputs. The commenters suggested that EPA allow the use of default values for carbon content, neglect streams that have very little or no carbon, drop the requirement for analysis by an ``independent certified laboratory,'' and allow the use of analyses from suppliers. One commenter recommended sampling and analysis for carbon content no more frequently than annually. The commenters stated that lime, dolomite and slag contain no appreciable carbon and do not need to be tracked, and that it is not necessary to account for the carbon in scrap that is charged to the furnace or in the steel product because they offset each other. One commenter noted that ``independent certified laboratory'' is not defined or explained, and another claimed that it is an unnecessary complication and expense because these carbon analyses are typically done in an in-house laboratory.

One commenter stated that the carbon mass balance equations were incomplete because they did not account for carbon removed by pollution control devices. Another commenter recommended that EPA use default carbon contents for different grades of steel scrap and noted that because companies already track the chemical content of each grade of scrap, highly accurate carbon calculations could be made with minimal additional burden.

Response: We received several useful suggestions for improving the carbon mass balance method without significantly decreasing the accuracy in the estimates. After a close review of the sampling and analysis requirements and comparing them to the requirements applied to other source categories in other subparts of this reporting rule, we concluded that the weekly sampling and monthly analysis of carbon content could be reduced in frequency to an annual analysis of all inputs and outputs at each facility. We also revised the rule to allow the use of carbon content analyses from the material supplier, which is consistent with what is required in other subparts using the carbon balance method. Carbon content does not vary widely at a given facility for the significant process inputs and outputs that contain carbon, and we continue to account for variations due to changes in production rate, which is likely a more significant source of variability. We continue to choose not to use default values for the reasons given in the previous comment response, and we have determined that an annual analysis of carbon content to provide plant-specific values is not burdensome because facilities already perform many such analyses. We agree that the analysis does not have to be performed by an independent certified laboratory, especially since we specify the analytical procedures that must be used by any laboratory, and we note that in- house laboratories may have more applicable experience in analyses of their particular process inputs and outputs.

We agree with the suggestion to evaluate carbon content by the grade or type of ferrous material charged to the furnace, and we incorporated a provision to calculate an average carbon content of ferrous materials charged based on the average weight percent of each type that is used. In addition, we have corrected the equations as suggested to account for carbon in the residue collected by emission control equipment. Finally, we agree that inputs and outputs that contain no carbon or an insignificant amount (i.e., contributing to less than one percent of the carbon in or out) do not need to be tracked in the carbon balance method.

Comment: Several commenters claimed that the site-specific emission factor method is not a viable option as proposed and should be streamlined to: (1) Eliminate annual re-testing, (2) reduce the test length from nine hours (or from nine production cycles for batch processes), (3) clarify that a separate test is not required for each grade of steel, and (4) remove the

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requirement to operate at 90 percent of capacity. One commenter stated that the most frequent re-testing currently required in operating permits is once every 2.5 years rather than annually. Another commenter noted that nine production cycles for certain small specialty steel producers would require 27 hours of testing for each grade of steel because each production cycle is three hours. Commenters stated that testing at 90 percent of production is problematic and is beyond their control because it is dictated by upstream and downstream production levels as well as economic conditions. In addition, capacity is difficult to determine because steelmaking furnaces do not have a nameplate capacity since it is determined by the iron production rate, how fast downstream processes (such as the caster) operate, process inputs, and product specifications that may require different operating cycle times.

One commenter questioned the value of the requirement to re-test if the carbon content of feed materials changes by more than 10 percent because this type of change could occur on a daily or weekly basis when the grade of steel being produced changes. Another commenter noted that

EPA did not define what constituted a significant change in fuel type or mix and recommended that the provision be changed to 20 percent to allow for environmentally beneficial process improvements. Two commenters stated that the 10 percent threshold for re-testing is infeasible for steelmaking and sinter processes because of routine changes in the type of steel produced and the types of materials recycled to the sinter plant. The commenters requested that they be permitted to develop separate emission factors based on various modes that represent different operating scenarios or product categories. The commenters also recommended that EPA eliminate the 10 percent change threshold for re-testing and require that testing be conducted under conditions that are representative of normal operation. One commenter noted that the rule did not address how a site-specific emission factor would be developed when emissions from the EAF and argon-oxygen decarburization vessel are combined and routed to a single emission control device and stack.

Response: We further reviewed the testing requirement in other rules and those in operating permits and found that typical requirements (such as test requirements for particulate matter) include 3 one-hour runs or production cycles for representative testing of process emissions. Consequently, we are revising the testing requirements to three hours or three production cycles. We also agree with the commenters who noted that different routine operating modes may result in different levels of CO2emissions, and it is necessary to develop separate emission factors for these different operating conditions. Consequently, we have dropped the 10 percent re- testing threshold and instead require that separate emission factors be developed for each of different routine operating conditions that result in a change in CO2emissions by 20 percent or more.

We disagree that annual re-testing is excessive because testing for

CO2emissions is much simpler and less costly than sampling for hazardous pollutants or for particulate matter, and annual sampling is consistent with our requirement for annual reporting. We agree that it is not necessary or always possible to test while operating at 90 percent of capacity for the reasons identified by the commenters.

Instead, we are requiring that the test be performed based on representative performance, i.e., under normal operating conditions. We have revised the rule to clarify and provide options for testing when emissions from the EAF and argon-oxygen decarburization vessel are combined.

Comment: Several commenters asked EPA to clarify that

CH4and N2O emissions do not have to be reported for iron and steel production processes, and other commenters requested that CH4and N2O emissions reporting not be required for the combustion of coke oven gas and blast furnace gas.

Commenters noted that default emission factors for CO2,

CH4, and N2O were not provided in the tables in 40 CFR part 98, subpart C, and in the absence of such emission factors, asked if they would be required to test for these minor emissions.

Response: We have clarified that 40 CFR part 98, subpart Q does not require reporting of CH4and N2O emissions from the iron and steel production processes because we expect these emissions (if any) to be very low, and we have no protocols for calculating them. However, emission factors are available in the 2006

IPCC guidelines for combustion sources, including the combustion of coke oven gas and blast furnace gas. We have added the IPCC default emission factors for CO2and N2O for these process gases to the tables in 40 CFR part 98, subpart C, and we developed new emission factors for CH4based on the typical

CH4content of coke oven gas (28 percent) and blast furnace gas (0.2 percent).

R. Lead Production 1. Summary of the Final Rule

Source Category Definition. The lead production source category consists of primary lead smelters and secondary lead smelters. A primary lead smelter is a facility engaged in the production of lead metal from lead sulfide ore concentrates through the use of pyrometallurgical techniques (smelting). A secondary lead smelter is a facility at which lead-bearing scrap materials (including but not limited to lead-acid batteries) are recycled by smelting into elemental lead or lead alloys.

Reporters must submit annual GHG reports for primary lead smelters and secondary lead smelters that meet the applicability criteria in the

General Provisions (40 CFR 98.2) summarized in Section II.A of this preamble.

GHGs to Report. For lead production, report the following emissions:

CO2process emissions from each smelting furnace used for lead production.

CO2combustion emissions from each smelting furnace used for lead production.

N2O and CH4emissions from each smelting furnace under 40 CFR part 98, subpart C (General Stationary

Fuel Combustion Sources) using the methodologies in subpart C.

CO2, N2O, and CH4 emissions from each on-site stationary combustion unit other than smelting furnaces under 40 CFR part 98, subpart C (General Stationary

Fuel Combustion Sources).

In addition, report GHG emissions for any other source categories at the facility for which calculation methods are provided in other subparts of the rule, as applicable.

GHG Emissions Calculation and Monitoring. To calculate annual process CO2emissions from an affected smelting furnace, the reporter must use the following methods, as applicable to the affected smelting furnace.

For each affected smelting furnace with certain types of

CEMS in place, the reporter must use the CEMS and follow the Tier 4 methodology (in 40 CFR part 98, subpart C) to measure and report under the Lead Production subpart (40 CFR part 98, subpart R) combined process and combustion CO2emissions.

For other affected smelting furnaces, the reporter can elect to either (1) install and operate a CEMS and follow the Tier 4 methodology to measure and report combined process and combustion

CO2emissions or (2) calculate annual process CO2 emissions using a carbon mass balance procedure specified in 40 CFR part 98, subpart R. If using approach (2):

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--Calculate emissions once per year using recorded monthly production data and the average carbon content for each smelting furnace input material determined by either using material supplier information or by annual analysis of representative samples of the material.

--Report process CO2emissions from each smelting furnace under 40 CFR part 98, subpart H (Cement Production), and report combustion CO2emissions from each kiln under 40 CFR part 98, subpart C (General Stationary Fuel Combustion Sources).

Data Reporting. In addition to the information required to be reported by the General Provisions (40 CFR 98.3(c)) and summarized in

Recordkeeping. In addition to the records required by the General

The major changes to the rule since proposal for lead production facilities were revisions to the carbon mass balance calculation procedure used by reporters for calculating process CO2 emissions from affected smelting furnaces. The rationale for these and any other significant changes can be found below or in ``Mandatory

Greenhouse Gas Reporting Rule: EPA's Response to Public Comments,

Subpart R: Lead Production.''

The frequency of performing the carbon mass balance calculations was revised to be required on an annual basis instead of the proposed monthly basis.

The frequency of material carbon content sampling and analysis of each smelting furnace input material used for the carbon mass balance was revised to be performed by annual analysis of representative samples of the material instead of the proposed monthly basis.

A de minimis carbon content level was added to exclude the need to account for carbon-containing materials contributing less than one percent of the total carbon into the smelting furnace in the carbon mass balance calculations.

Data reporting procedures (40 CFR 98.186) were reorganized and updated to consolidate and clarify the emissions verification process. Some data elements for the carbon mass balance calculation were moved from 40 CFR 98.187 to 40 CFR 98.186, and some data elements that a reporter must already use to calculate GHGs as specified in 40

CFR 98.183 were added to 40 CFR 98.186 for clarity. 3. Summary of Comments and Responses

This section contains a brief summary of major comments and responses specific to the lead production source category. Comments were received from one commenter regarding several topics. Responses to significant comments received are presented in ``Mandatory Greenhouse

Gas Reporting Rule: EPA's Response to Public Comments, Subpart R: Lead

Production.''

Selection of Threshold

Comment: The commenter stated that Lead Production is not a source of significant GHG emissions and that EPA cannot assert that the Lead

Production sector is a significant part of the stationary source combustion sector. The commenter notes that based on EPA's estimates in the TSDs for the proposal, estimated emissions from the Lead Production sector are 0.02 percent of the total estimated nationwide emissions from stationary fossil fuel combustion. Moreover, they argue that the combustion-related emissions from lead production are overstated by incorrect assumptions in the TSD. The commenter states that given Lead

Production's relative contribution, it is not a significant source of emissions and should be eliminated from further consideration. The commenter further states that Lead Production is the only category evaluated where raising the threshold to the 100,000 ton level would results in zero facilities being covered. Accordingly, when the analysis shows that all facilities in a particular source category are not covered at the 100,000 ton threshold level, no insignificant GHG emitters in the category should be required to report under the

Proposed Rule. The commenter noted that using the 100,000 threshold would not significantly reduce the coverage of emissions of EPA's rule, as the majority of sources identified would still have well over 90 percent of emissions from that source category covered under the 100,000 threshold. EPA provides no justification for imposing substantially more costs on industry for limited estimated benefits and small likelihood for regulation under the CAA. For these reasons, the

Lead Production sector should be eliminated as a source category, and

EPA should raise the threshold to 100,000 for non-source category facilities.

Response: We acknowledge this comment and concerns; however, the final rule retains the applicability requirement for this source category. We used information available to us for estimating GHG emissions from this industry which involved several assumptions related to the emission factors in the IPCC Guidance and other sources. As noted by the commenter, many of the underlying assumptions were based on an international perspective as opposed to the primary and secondary lead production industry in the U.S. The final rule contains a threshold of 25,000 metric tons CO2e and only lead production facilities with emissions that equal or exceed 25,000 metric tons CO2e will have to report emissions. In addition, the final rule now contains provisions allowing a reporter to cease reporting if the annual reports for a given facility demonstrate emissions less than specified levels for multiple years. These provisions apply to all reporting facilities, including those with lead production processes. See Section II.H of this preamble for the response on provisions to cease reporting.

We have further simplified the reporting requirement to further reduce burden for lead and similar industries by requiring annual as opposed to monthly sampling of carbon inputs. The purpose of this rule is to collect information on emissions sources for future policy development. Requiring reporting for these sources will provide EPA with valuable data to better characterize them and provide a more credible position if EPA elects to exclude these sources from future

GHG policy analyses. Additionally, while some of these sources are currently believed to be small compared to the larger sources, they are not necessarily insignificant. The inclusion of reporting data for these sources is critical to support analysis of future policy decisions for lead production facilities.

When evaluating potential thresholds for reporting GHG emissions, we considered several thresholds between 1,000 and 100,000 metric tons

CO2e. We selected the 25,000 metric tons CO2e threshold for reporting GHG emissions in order to achieve a balance between quantifying the majority of the emissions, while minimizing the number of facilities impacted. For example, at a 1,000 metric tons

CO2e threshold, 99 percent of emissions would be covered, with about 63

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percent of facilities being required to report. The 100,000 metric tons

CO2e threshold captures no emissions or facilities while the proposed 25,000 metric tons CO2e threshold achieves reporting of 92 percent of the GHG emissions while requiring less than 50 percent of the facilities to report. We consider this a significant coverage of the emissions, while impacting a relatively small portion of the industry. We believe the proposed threshold of 25,000 metric tons CO2e represents the best option for ensuring that the majority of emissions are reported without imposing an unreasonable burden on the industry. See also Section II.E of this preamble and

``Mandatory Greenhouse Gas Reporting Rule: EPA's Response to Public

Comments, Selection of Reporting Thresholds, Greenhouse Gases, and De

Minimis Provisions.''

Method for Calculating GHG Emissions

Comment: The commenter made several comments regarding the proposed procedures used to calculate process CO2emissions from smelting furnaces at secondary lead smelters. First, use of default emission factors should be allowed as a calculation method alternative because the smelting furnaces operated at used lead battery recycling facilities consistently process furnace feed materials with low carbon content variability. For affected sources using the carbon mass balance procedure, the frequency required for monitoring carbon content of the smelting furnace input materials should be reduced to reflect consistency and low carbon content variability of these materials.

Response: We decided not to finalize the proposal using methodologies for calculating CO2emissions from lead production that relied on published default emission factors or default values for carbon content of materials because the differences among individual lead production facilities could not be discerned using these factors. Consequently, the available default factors for lead production facilities are inherently less accurate for calculating smelting furnace process CO2emissions than using procedures that include use of site-specific material carbon data. Default approaches do not provide site-specific estimates of emissions that reflect differences in use of and variability in feedstocks, variability in fuels, operating conditions, fuel combustion efficiency, and other differences among facilities. For some carbon-containing input materials, such as lead scrap, representative published defaults do not exist. Therefore, the use of default values is more appropriate for sector wide or national total estimates from aggregated production data for multiple facilities rather than for providing an accurate representation of CO2emissions from a specific facility.

For the final rule, we did reduce the monitoring frequency for determining carbon contents of the smelting furnace input materials used for the carbon mass balance to be determined on annual rather than monthly basis. Facilities can determine carbon contents either by using material supplier information or by annual analysis of representative samples of the input materials. We agree that the carbon content for the significant input materials typically does not vary widely at a given lead production facility. Annual carbon content determinations will still provide representative carbon content data for the smelting furnace process CO2emissions calculations while minimizing the monitoring burden on reporters. We continue to account for process variations due to changes in production rate, which is likely a more significant source of variability in the CO2emissions from an affected smelting furnace during the year, by maintaining the requirement to measure and record monthly carbon containing input materials.

S. Lime Manufacturing 1. Summary of the Final Rule

Source Category Definition. Lime manufacturing plants (LMPs) engage in the manufacture of a lime product (e.g., calcium oxide, high-calcium quicklime, calcium hydroxide, hydrated lime, dolomitic quicklime, dolomitic hydrate, or other products) by calcination of limestone, dolomite, shells or other cacareous substances. This source category includes all LMPs unless the LMP is located at a kraft pulp mill, soda pulp mill, sulfite pulp mill, or only processes sludge containing calcium carbonate from water softening processes.

Lime kilns at pulp and paper manufacturing facilities need to report emissions under 40 CFR part 98, subpart AA (Pulp and Paper

Manufacturing).

Reporters must submit annual GHG reports for facilities that meet the applicability criteria in the General Provisions (40 CFR 98.2) summarized in Section II.A of this preamble and meet the definition of lime manufacturing plants in 40 CFR 63.7081(a)(1).

GHGs to Report. For lime manufacturing, report the following emissions:

Total CO2process emissions from all lime kilns combined.

CO2combustion emissions from lime kilns.

N2O and CH4emissions from fuel combustion at each kiln under 40 CFR part 98, subpart C (General

Stationary Fuel Combustion Sources) using the methodologies in subpart

CO2, N2O, and CH4 emissions from each stationary combustion unit other than kilns under 40 CFR part 98, subpart C (General Stationary Fuel Combustion Sources).

CO2collected and transferred off site under 40

CFR part 98, subpart PP (Suppliers of CO2).

In addition, report GHG emissions for any other source categories at the facility for which calculation methods are provided in other subparts of the rule, as applicable.

GHG Emissions Calculation and Monitoring. For CO2 emissions from kilns, facilities must use one of two methods, as appropriate:

If all lime kilns at a facility have certain types of CEMS in place, the reporter must use the CEMS and follow the Tier 4 methodology (in 40 CFR part 98, subpart C) to measure and report under the Lime Manufacturing subpart (40 CFR part 98, subpart S) combined process and combustion CO2emissions.

If CEMS meeting the specifications above are not in place for all kilns at the facility, the reporter can elect to either (1) install and operate a CEMS and follow the Tier 4 methodology to measure and report combined process and combustion CO2emissions from all lime kilns or (2) calculate CO2process emissions for each lime type using an emission factor for each lime type, the mass of lime produced, an emission factor for byproduct/waste (such as lime kiln dust and scrubber sludge), and the mass of byproduct/waste.

If using approach (2):

--Each emission factor must be determined monthly for each lime type from monthly measurements of the calcium oxide and magnesium oxide content of the lime and stoichiometric ratios of CO2to each oxide in the lime.

--The emission factor for each lime byproduct/waste sold (such as lime kiln dust) must be determined monthly.

--The emissions from lime byproducts/wastes that are not sold (such as lime kiln dust and scrubber sludge) must be determined annually.

--The mass of each lime type produced and lime byproduct/waste sold

(such as lime kiln dust) must be recorded on a monthly basis.

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--The mass of each lime byproduct/waste not sold (such as lime kiln dust and scrubber sludge) must be recorded annually.

--Report process CO2emissions from all kilns combined under 40 CFR part 98, subpart S (Lime Manufacturing), and report combustion

CO2emissions from each kiln under 40 CFR part 98, subpart C

(General Stationary Fuel Combustion Sources).

Data Reporting. In addition to the information required to be reported by the General Provisions (40 CFR 98.3(c)) and summarized in

Recordkeeping. In addition to the records required by the General

Response to Public Comments, Subpart S: Lime Manufacturing.''

The definition of lime manufacturing was revised to be similar to the definition in the Lime NESHAP at Sec. 63.7081(a) and

(a)(1).

Reporting requirements were revised from a ``per kiln'' basis to ``all kilns combined''.

The emissions calculations were revised to determine monthly emissions factors for each lime type and byproduct/waste type rather than for each kiln.

Emission calculations for byproducts/wastes were added.

The requirement to measure the calcium oxide and magnesium oxide content of byproducts/wastes on a monthly basis was changed to an annual basis for byproducts/wastes that are not sold.

The correction factor for byproducts/wastes was removed from the rule.

Additional direct measurement devices/methods are being allowed to include those currently in use by the industry. 40 CFR 98.196 was reorganized and updated. Some data elements were moved from 40 CFR 98.197 to 40 CFR 98.196, and some data elements that a reporter must already use to calculate GHGs as specified in 40 CFR 98.193 were added to 40 CFR 98.196 for clarity. 3. Summary of Comments and Responses

This section contains a brief summary of major comments and responses. A large number of comments on lime manufacturing were received covering numerous topics. Responses to significant comments received can be found in ``Mandatory Greenhouse Gas Reporting Rule:

EPA's Response to Public Comments, Subpart S: Lime Manufacturing.''

Definition of Source Category

Comment: Multiple commenters requested more clarification in defining which sources and equipment are covered by the proposed rule.

The rule defines the source category as a facility that contains ``a rotary lime kiln to produce a lime product.'' In addition, proposed 40

CFR 98.192(b) required sources to report emissions from ``each lime kiln and any other stationary combustion unit.''

Response: We have reviewed the rule language and decided the source category definition should provide more clarity. The source category is meant to include all kiln types used in the lime manufacturing industry; therefore, language in the final rule has been changed to be similar to the definition from the Lime NESHAP in 40 CFR 63.7081(a) and

(a)(1). This Lime NESHAP effectively characterizes lime plants as those engaging in the manufacture of a lime product by calcination. The final rule requires all stationary combustion units to report under 40 CFR part 98, subpart C of the final rule.

Final rule language under 40 CFR 98.192 requires facilities to report CO2, CH4, and N2O emissions from kilns used in the lime manufacturing process and all other combustion units at the lime manufacturing facility other than kilns.

The language has also been clarified in 40 CFR 98.193. Facilities using

CEMS for all lime kilns report combined process and combustion emissions from kilns under 40 CFR part 98, subpart S, according to the

Tier 4 methodology in 40 CFR part 98 subpart C (General Stationary Fuel

Combustion Sources). Facilities must follow the requirements of subpart

C for estimating and reporting combustion related emissions for all other combustion units and report these emissions under subpart C. See

Section III.C of this preamble for an overview of the requirements for stationary combustion units.

Selection of Proposed GHG Emissions Calculation and Monitoring Methods

Comment: Multiple commenters requested the language in 40 CFR part 98, subpart S be changed to allow emissions to be reported by ``all kilns combined'' instead of the proposed rule's request to report emission for each kiln. Multiple commenters further recommended that the process emissions calculations be changed to calculate emissions by the lime type produced as opposed to the current rule calculations which use a kiln specific emission factor. Two commenters stated that lime products are commonly aggregated at the plant making it difficult to estimate the amount of product produced at an individual kiln. These commenters stated that current lime plant configuration do not allow accurate kiln specific calculations.

Response: We have reviewed the common lime plant configuration and the currently proposed rule language and have decided that it is not necessary to require kiln-specific emissions reporting. We have observed that some kilns would have to retrofit weigh belt scales in the production line between kilns and storage silos, since they do not currently exist. Calculating emissions by kiln could increase the reporting burden for these facilities. According to one commenter, when kiln-specific emissions have been reported in the past, the data are usually derived by distributing the aggregated emissions among the kilns. Accurate measurements at the kiln level are rarely achieved. If this is true for most lime manufacturing facilities, the data does not necessarily provide a better estimate of emissions.

For the purposes of this rulemaking, reporting for all kilns combined will simplify and minimize the reporting burden without significant loss in accuracy because: (1) Kilns may produce more than one type of lime in a given reporting period, (2) emission factors are based on lime type, and (3) lime plants collect products in combined bagging areas (separated by lime type). The final rule language has been changed to require reporting by lime type from all kilns combined rather than all lime types for each kiln. This final rule language is consistent with the National Lime Association (NLA) Protocol, which was used as the basis for the methodology in the proposed rule. Information collected under this rule will help to inform future methodologies and determine whether

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kiln level reporting could be more appropriate for future reporting.

Comment: The proposed rule used a default correction factor in calculating lime product and byproduct/waste emissions. Multiple commenters suggested using the National Lime Association Protocol to determine lime product and by-product/waste process emissions.

According to the commenters, this method is more precise due to the use of measured oxide values and stoichiometric ratios rather than correction factors.

Response: We have reviewed the proposed rule and NLA Protocol calculation methods and noted that the use of actual oxide measurements in calculating emissions from lime plants does not cause an additional burden to the reporter since this is a currently used practice. We also agree that the use of actual measurements is more accurate. Therefore, we have decided to remove the use of a correction factor in the final rule equations; emissions will be calculated from actual oxide measurements of each type of lime and calcined byproducts/wastes.

Monitoring and QA/QC Requirements

Comment: Multiple commenters asked that the language pertaining to allowable measurement devices for lime products and byproducts/wastes sold, be changed to include measurement devices commonly used in the lime industry. The current rule language requires weigh hoppers and belt weigh feeders as the measurement devices; the aforementioned commenters have identified bag, truck and rail scales as reliable

(annually calibrated) direct measurement methods commonly used in the lime industry. In addition, commenters have requested lime byproducts/ wastes not sold be calculated by a facility generation rate.

Response: After reviewing the rule language and common industry practices, we have decided to include other direct measurement devices used for accounting purposes, including but not limited to, weigh feeders, calibrated bag, rail or truck scales, and barge measurements.

These methods are consistent with the original intent of the rule and add further clarification on measurement methods applicable to determine quantities of both lime produced and byproducts/waste generated.

In addition, reporters are required to perform an annual cross check by measuring lime products at the beginning and end of the year.

For calcined byproducts/wastes not sold, a material balance approach that indirectly measures the generation rate should be used.

Comment: Multiple commenters asked that the language in 40 CFR part 98, subpart S pertaining to testing the chemical composition of each type of lime (including the byproducts and waste) be changed to allow testing by onsite lab facilities. Currently the rule specifies an

``off-site laboratory analysis'' but according to the commenter, commercial lime plants normally have onsite lab facilities.

Response: We agree that the analysis does not have to be performed by an independent certified laboratory, especially since we specify the analytical procedures that must be used by any laboratory, and we note that in-house laboratories may have more applicable experience in determining chemical composition. Reporters can determine whether to perform the test onsite or send the samples to offsite laboratory facilities. Therefore the language in the final rule has been changed.

Data Reporting Requirements

Comment: Multiple commenters requested the language in 40 CFR part 98, subpart S pertaining to reporting information to EPA be changed so that business sensitive information is kept in company records.

Commenters agree that the production capacity, product quality (i.e., oxide content), emission factors and operating hours and days for each kiln, are required for emissions calculations but are concerned that making this information public would give information about their efficiency, productivity and capacity of kilns and facility.

Response: EPA reviewed CBI comments received across the rule (both general and subpart-specific comments) and our response is discussed in

Section II.R of this preamble for legal issues. Also, see Section II.N of this preamble for the response to comments on the emissions verification approach.

We agree that annual operating hours and capacities are not used in the calculation of CO2emissions and these parameters have been moved to recordkeeping. This information can help to verify anomalies in emissions data if there were temporary shutdowns, etc.

We disagree that emission factors and product quality be maintained as records rather than be reported. Emission factors and product quality are used in calculations to establish the site specific rate of

CO2emissions generated for each type of lime produced.

Therefore these data are required in order to verify the CO2 emissions that are being reported. This internal verification system ensures that the GHG emissions reported are accurate.

T. Magnesium Production

At this time EPA is not going final with the magnesium production subpart (40 CFR part 98, subpart T). For the immediate future, EPA believes that emissions of GHGs from magnesium production are sufficiently covered by the reporting requirements under 40 CFR part 98, subpart OO for Industrial Gas Supply. This information on U.S. production, imports, and exports of SF6will provide at least a general, order-of-magnitude check on consumption of

SF6by magnesium production and other uses of

SF6. EPA will finalize the proposed reporting requirements for the magnesium production industry at a later date.

U. Miscellaneous Uses of Carbonate 1. Summary of the Final Rule

Source Category Definition. The Miscellaneous Uses of Carbonate source category consists of any facility that uses carbonates listed in

Table U-1 of 40 CFR part 98, subpart U in manufacturing processes that emit carbon dioxide. The Table includes the following carbonates:

Limestone, dolomite, ankerite, magnesite, siderite, rhodochrosite, or sodium carbonate. Facilities are considered to emit CO2if they consume at least 2,000 tons per year of the carbonates listed above and that are heated to a temperature sufficient to allow calcination to occur.

This source category does not include facilities processing carbonates or carbonate containing minerals consumed for producing cement, glass, ferroalloys, iron and steel, lead, lime, phosphoric acid, pulp and paper, soda ash, sodium bicarbonate, sodium hydroxide or zinc as CO2emissions from these processes are covered elsewhere in this rule.

Reporters must submit annual GHG reports for facilities that meet the applicability criteria in the General Provisions (40 CFR 98.2) summarized in Section II.A of this preamble.

GHGs to Report. For miscellaneous uses of carbonates, report the following emissions:

Annual CO2process emissions for all miscellaneous uses of carbonates as specified in this subpart.

CO2, N2O, and CH4 emissions from carbonates used in sorbent technology and each stationary combustion unit on site under 40 CFR part 98, subpart C

(General Stationary Fuel Combustion Sources).

In addition, report GHG emissions for other source categories at the facility for

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which calculation methods are provided in the rule, as applicable.

GHG Emissions Calculation and Monitoring. Calculate process

CO2emissions using annual carbonate consumption. All reporters must calculate the annual mass of carbonates used in processes which are heated to temperatures that allow calcination. If the annual amount of carbonates consumed is greater than 2,000 tons,

CO2emissions must be calculated using either calcination fractions or the actual mass of input/output carbonates.

Data Reporting. In addition to the information required to be reported by the General Provisions (40 CFR 98.3(c)) and summarized in

Recordkeeping. In addition to the records required by the General

Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this preamble, reporters must keep records of analyses and calculations required for this source category. 2. Summary of Major Changes Since Proposal

Response to Public Comments, Subpart U: Miscellaneous Uses of

Carbonates.''

The source category definition was revised to exclude non- emissive uses of carbonates.

A de minimis reporting threshold was added to exclude facilities with minor emissions based on annual carbonate consumption.

The GHG calculation methodology was changed to allow reporters to determine emissions from the mass of carbonate input/ output or calcination fractions.

To improve the emissions verification process, 40 CFR 98.216 was reorganized and updated. Some data elements were moved from 40 CFR 98.217 to 40 CFR 98.216, and some data elements that a reporter must already use to calculate GHG as specified in 40 CFR 98.213 were added to 40 CFR 98.216 for clarity. 3. Summary of Comments and Responses

This section contains a brief summary of major comments and responses. A large number of comments on miscellaneous uses of carbonates were received covering numerous topics. Most comments requested clarification on the definition of the source category and its applicability to affected sources. Responses to significant comments received can be found in ``Mandatory Greenhouse Gas Reporting

Rule: EPA's Response to Public Comments, Subpart U: Miscellaneous Uses of Carbonates.''

Definition of Source Category

Comment: Multiple commenters requested that the source category be revised to exclude non-emissive uses of carbonates. Commenters stated that the source category is poorly defined, making it difficult to accurately assess its applicability to an industrial facility.

Commenters noted a number of non-emissive uses as examples, such as the production of sodium bicarbonate and sodium hydroxide, during which sodium carbonates are used, but no carbon dioxide is released; onsite mixing of processed cement with aggregate, limestone used in poultry grit and as an asphalt filler; or adding sodium carbonate to a water softener system.

Response: The rule language has been modified to exclude non- emissive uses of carbonates. Non-emissive uses do not result in

CO2emissions, such as adding sodium carbonate to a water softener system. Acid-induced releases of CO2from the use of carbonates are addressed in other subparts, where they are significant, such as Phosphoric Acid Production.

Selection of Threshold

Comment: Multiple commenters requested that a de minimus reporting threshold be added to exclude facilities with minor emissions. One commenter noted that some facilities use limestone and other carbonate as refractory in furnaces, and it is unclear whether or not this use of carbonates triggers 40 CFR part 98, subpart U, and at what level it is triggered.

One commenter noted that at a pharmaceutical manufacturing facility there would also be a significant listing of small operations and activities which use carbonate compounds in trace quantities, including the creation of reagent solutions, and wastewater treatment operations employing carbonate compounds for buffering, chemical precipitation, or solids stabilization. This commenter recommended that EPA implement a threshold of 2,000 tons per year of carbonates per facility, which would correlate to CO2emissions of about 1,000 tons per year.

One commenter requested that EPA incorporate a de minimis threshold to only include equipment where carbonate is present at greater than 10 percent by weight and heated to a temperature that allows for decomposition. This commenter suggested an alternative threshold, where

EPA would require facilities to calculate CO2emissions from each type of carbonate used in quantities exceeding 2,000 tons per year.

Response: The rule language has been modified to specify that GHG emissions from miscellaneous carbonate use are required to be reported only from processes that consume at least 2,000 tons per year and, further, where the carbonates are heated to a temperature sufficient to allow the calcination reaction to occur. This modification to the definition of the source category allows facilities with minimal carbonate consumption and low amounts of GHG emissions to be excluded from reporting emissions.

Method for Calculating GHG Emissions

Comment: Multiple commenters requested that EPA allow emission calculations to be based on carbonate fraction of the product instead of calcination fractions.

Response: The rule has been changed to allow emission calculations by either the mass of carbonate input/output or calcination fraction.

These methods should provide comparable estimates of emissions.

The calcination fraction method calculates the amount of

CO2emissions based on the amount of each carbonate that is calcined during the process. The mass and calcination fraction of each carbonate are measured and used with a default CO2emission factor to determine CO2emissions.

The carbonate fraction method calculates the amount of

CO2emissions as a mass balance between the input and output amount of each type of carbonate. The masses are measured and used with a default CO2emission factor to determine CO2 emissions.

The mass of carbonate input/output is determined by use of the same plant instruments used for accounting purposes or by direct measurement. Calcination fractions can be measured by the appropriate industry consensus standards that require laboratory analysis of each carbonate type. Alternatively, a default value of one can be used as the calcination fraction.

Data Reporting Requirements and Records That Must Be Retained

Comment: One commenter requested that recordkeeping and reporting

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requirements be exempted for carbonates kept on-site for emergency purposes (not manufacturing or equipment), such as for neutralizing a chemical spill. This commenter explained that when used, these emergency reserves of carbonate material typically generate insignificant amounts of CO2and should therefore be excluded from reporting requirements.

Response: The final rule does not cover carbonates that are used in quantities of less than 2,000 tons per year and that are not heated to the point of calcination. Also, this subpart does not include requirements for calculating and reporting CO2emissions from acid neutralization. Therefore, the use of carbonates in the manner described is not covered by the final rule.

Comment: One commenter noted that the required records are duplicated in proposed 40 CFR 98.217(a) and 98.217(c), and requested that EPA revise this so as not to place unnecessary costs on facilities.

Response: EPA agrees that asking facilities to maintain records on procedures used to ensure the accuracy of monthly carbonate consumption will be duplicative with maintaining records of all carbonate purchases and deliveries. This is especially true if purchase records are used to determine monthly carbonate consumption. We removed this duplicative recordkeeping requirement from the rule.

Commenters may also want to review Section II.M for the response on the general recordkeeping requirements and Section II.N of this preamble for the response on the emissions verification approach.

V. Nitric Acid Production 1. Summary of the Final Rule

Source Category Definition. The nitric acid production source category consists of facilities that use one or more trains to produce weak nitric acid (30 to 70 percent in strength) through the catalytic oxidation of ammonia.

Reporters must submit annual GHG reports for facilities that meet the applicability criteria in the General Provisions (40 CFR 98.2) summarized in Section II.A of this preamble.

GHGs to Report. For nitric acid production facilities, report

N2O process emissions from each nitric acid train.

In addition, report GHG emissions for other source categories at the facility for which calculation methods are provided in the rule, as applicable. For example, report CO2, N2O, and

CH4emissions from each stationary combustion unit on site under 40 CFR part 98, subpart C (General Stationary Fuel Combustion

Sources).

GHG Emissions Calculation and Monitoring. Reporters must calculate

N2O process emissions for each nitric acid train. Calculate the emissions by multiplying the site-specific emission factor for each train by the measured annual nitric acid production for that train.

Determine the site-specific emission factor for each train through an annual performance test to measure N2O from the absorber tail gas vent and the production rate for that train.

When N2O abatement devices (such as nonselective catalytic reduction) are used, adjust the N2O process emissions for the amount of N2O removed using a destruction efficiency factor. The destruction factor is the destruction efficiency and can be specified by the abatement device manufacturer or can be determined using process knowledge or another performance test.

Data Reporting. In addition to the information required to be reported by the General Provisions (40 CFR 98.3(c)) and summarized in

Recordkeeping. In addition to the records required by the General

Response to Public Comments, Subpart V: Nitric Acid Production.''

The re-testing trigger was changed. Performance testing to determine the N2O emissions factor is required annually and whenever new abatement technology is installed. The performance test should be conducted under normal operating parameters.

Equation V-2 was edited to correct a calculation error and to allow multiple types of abatement technologies.

Reorganized and updated 40 CFR 98.226 to improve the emissions verification process. Some data elements were moved from 40

CFR 98.227 to 40 CFR 98.226, and some data elements that a reporter must already use to calculate GHGs as specified in 40 CFR 98.223 were added to 40 CFR 98.226 for clarity. 3. Summary of Comments and Responses

This section contains a brief summary of major comments and responses. A large number of comments on nitric acid production were received covering numerous topics. Responses to significant comments received can be found in ``Mandatory Greenhouse Gas Reporting Rule:

EPA's Response to Public Comments, Subpart V: Nitric Acid Production.''

GHGs To Report

Comment: Multiple commenters asked that the language in 40 CFR 98.222(b) be clarified to include emissions under 40 CFR part 98, subpart V only from units that are 100 percent dedicated to nitric acid production to avoid double counting of combustion emissions.

Response: We appreciate the comments but have decided not to make any changes to 40 CFR part 98, subpart V. According to the applicability criteria in subpart C, all combustion unit emissions from nitric acid facilities (regardless of whether or not the combustion units are associated with nitric acid production operations) are to be reported under subpart C. There will be no potential for double counting of combustion emissions at the facility because Subpart V provides methods for reporting only the process emissions. Also see the preamble for responses on comments related to Subpart C (General

Stationary Combustion).

Method for Calculating GHG Emissions

Comment: Multiple commenters asked that the requirement to repeat the annual performance test be removed. In the proposal, re-testing was triggered whenever the nitric acid production rate changed by more than 10 percent. Commenters asserted that production depends on demand for nitric acid and often varies by up to 20 percent.

Response: We appreciate the comments and have decided to eliminate re-testing. We believe that

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annual determination of the N2O emissions factor is sufficient to accurately calculate N2O emissions as long as the train equipment remains consistent over the year-long period (i.e., no installation of abatement technology).

Comment: Multiple commenters asked that alternative methods be allowed for calculating N2O emissions from nitric acid production. Specifically the commenters asked that EPA allow the use of

N2O and flow CEMS to directly measure N2O emissions and use the performance test to evaluate the CEMS accuracy.

They also requested that EPA allow use of existing process flow meters, process N2O analyzers to determine the amount of

N2O sent to control devices and conduct a performance test measuring control device destruction efficiency for each control device and then calculate N2O emissions.

Commenters also asked that finalizing a methodology for

N2O stack testing for nitric acid units be delayed until EPA can coordinate with the commenters in formulating a more accurate means of measurement from these sources.

Response: We agree that there are other accurate means of determining N2O emissions, such as N2O CEMS. The final rule has been changed to allow alternative test methods, in addition to the proposed methods. Any alternative must be approved by the Administrator before being used to comply with this rule. An implementation plan that details how the alternative method will be implemented must be included in the request for the alternative method.

Currently there is no EPA method for using N2O CEMS. EPA understands the need to further evaluate and establish alternative comparable or potentially more accurate methods for sources to use in calculating N2O emissions from nitric acid production and will address this in future rulemakings or amendments to rulemaking.

Until the method is approved, facilities must use the alternatives proposed in the rule for a performance test. At minimum the performance test will help to QA/QC alternative methods currently used to monitor

N2O emissions (including N2O CEMS).

The final rule allows the use of existing process flow meters and process knowledge in the determination of the destruction efficiency of

N2O abatement technologies. This parameter is often based on site-specific knowledge of operations in combination with manufacturer specifications. We believe that using existing methods reduces the potential cost impacts of this rulemaking and that it is in the best interest of the facilities that required parameters be accurately measured.

Comment: Multiple commenters asked that Equation V-2 be edited to follow the summation format used in the IPCC Tier 2 methodology. The current format does not allow for multiple abatement technologies

(including no abatement).

Response: We agree with this comment. The equation in the proposed rule contained an error and did not allow for multiple abatement technologies. The final rule contains a corrected version of the equation.

Data Reporting Requirements

Comment: Multiple commenters argued that the annual production rates, capacity and operating hours are considered CBI and should not be reported. The commenters asked that this information be maintained by the facility and made available to the Agency upon request.

Response: We reviewed CBI comments received across the rule (both general and subpart-specific comments) and our response is discussed in

Section II.R of this preamble and in ``Mandatory Greenhouse Gas

Reporting Rule: EPA's Response to Public Comments, Legal Issues.'' See also Section II.N of this preamble for the response on the emissions verification approach.

We agree that annual operating hours are not used in the calculation of N2O emissions and this parameter has been moved to recordkeeping. However, this parameter is still important for emissions verification. This information can help to verify anomalies in emissions data if there were temporary shutdowns, etc.

We disagree that production be maintained as records rather than be reported. Nitric acid production is a parameter in the method for determining annual N2O emissions so we need production rate in order to verify the N2O emissions that are being reported. The internal verification system ensures that the GHG emissions reported are as accurate as possible.

We disagree that capacities be considered confidential information.

During the data gathering process, we located multiple publicly available sources that included production capacities for nitric acid production facilities. Capacity information can help EPA determine a reasonable range within which reported emissions should be. We agree that capacities are not used in the calculation of N2O emissions; however, this is still an important parameter for verifying emissions. Therefore, this parameter has been moved to recordkeeping.

W. Oil and Natural Gas Systems

At this time, EPA is not going final with the fugitive and vented methane emissions from the oil and gas sector under 40 CFR part 98, subpart W. As EPA considers next steps, we will be reviewing the public comments and other relevant information.

EPA received a number of lengthy, detailed comments regarding 40

CFR part 98, subpart W. Commenters generally opposed the proposed reporting requirements and thought they would entail significant burden and cost. For example, many commenters asserted that use of direct measurement to collect data required under 40 CFR part 98, subpart W would entail significant burden and that the proposal lacked standards for leak detection and measurement equipment. In many cases, commenters provided alternative approaches to the reporting requirements proposed by EPA such as the use of emission factors and/or reducing the number of sources and sites requiring direct measurement e.g., through statistical sampling. In addition to comments on burden, commenters requested clarification from EPA on a number of proposed reporting provisions.

As EPA received extensive comments on this subpart, EPA plans to take additional time to perform additional analysis and consider alternatives to data collection procedures and methodologies. These alternatives will provide similar coverage of vented and fugitive methane and other GHG emissions in the oil and gas sector, while concurrently taking into account industry burden. As stated in Section

V.W of the preamble to the proposed rule (74 FR 166606, April 10, 2009), EPA will also consider the inclusion of GHG reporting from other sectors of the oil and gas industry.

Where applicable, EPA will also consider the applicability of engineering estimates, emissions modeling software and emissions factors rather than relying so extensively on the use of direct measurement. EPA will consider optimal methods of data collection in order to maximize data accuracy, while considering industry burden.

X. Petrochemical Production 1. Summary of the Final Rule

Source Category Definition. The petrochemical production source category consists of all processes that produce acrylonitrile, carbon black, ethylene, ethylene dichloride, ethylene oxide, or methanol, with certain exceptions. Exceptions include processes that produce a petrochemical

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as a byproduct, processes that produce methanol from synthesis gas when the annual mass production of hydrogen or ammonia exceeds the annual mass of methanol produced, direct chlorination processes operated independently of oxychlorination processes to produce ethylene dichloride, processes that produce bone black, and processes that produce a petrochemical from bio-based feedstock.

Reporters must submit annual GHG reports for facilities that meet the applicability criteria in the General Provisions (40 CFR 98.2) summarized in Section II.A of this preamble.

GHGs to Report. For petrochemical production facilities, report

CO2, CH4, and N2O process emissions from each petrochemical production unit. Process emissions include

CO2generated by reaction in the process. Process emissions also include CO2, CH4, and N2O emissions generated by combustion of off-gas from the process in stationary combustion units and flares. For some of the GHG emission calculation and monitoring options, 40 CFR part 98, subpart X references procedures in 40 CFR part 98, subpart C for calculating emissions from stationary combustion sources, and it references procedures in 40 CFR part 98, subpart Y for calculating emissions from flares.

In addition, report GHG emissions for other source categories at the facilities for which calculation methods are provided in the rule, as applicable. For example, report CO2, N2O, and

CH4emissions from each stationary combustion unit on site that does not burn process off-gas under 40 CFR part 98, subpart C

(General Stationary Fuel Combustion Sources). The quantity of

CO2captured must also be reported by following the requirements of 40 CFR part 98, subpart PP.

GHG Emissions Calculation and Monitoring. CO2process emissions from petrochemical production must be determined by one of three methods. Process emissions include emissions from CO2 generated by chemical reactions in the process and from the combustion of process off-gas and liquid wastes.

One emission calculation option is to route all process vent emissions to one or more stacks and use CEMS to measure the

CO2emitted from each stack (except flare stacks). For each stack that includes emissions from combustion of process off-gas, reporters must calculate CH4and N2O emissions by the procedures specified in 40 CFR part 98, subpart C. For each flare, the final rule requires CO2, CH4, and

N2O emissions to be calculated using the procedures in 40

CFR 98.253(b) (Petroleum Refineries). If CO2CEMS are used on all subject stacks, even if the CEMS were installed for reasons other than compliance with this rule, then the rule requires the use of this reporting option.

A second emission calculation option is to use a mass balance.

Under this option, the quantity of each carbon-containing feedstock added to the process and the quantity of each carbon-containing product produced by the process must be measured for each calendar month, or it may be calculated based on measured changes in the liquid level in storage tanks. The carbon content of each feedstock and product also must be determined at least once per month. The carbon content may be measured directly, or it may be calculated based on measurements of the composition and known compound molecular weights. Under this option, the procedures for products also apply to byproducts and liquid organic wastes that are not combusted onsite. To prevent double-counting of combustion emissions, this option specifies that the procedures for stationary combustion sources in 40 CFR part 98, subpart C apply only to the supplemental fuel (e.g., natural gas) burned in combustion units that supply energy needs for petrochemical processes. The final rule specifies numerous measurement method options and related calibration requirements in 40 CFR 98.244. To potentially minimize the sampling and analysis burden, the final rule, like the proposed rule, includes an option that allows reporters to assume a feedstock or product is always 100 percent pure if they determine that the specified compound is always present at greater than 99.5 percent.

A third emission calculation option is available only for ethylene processes. Because nearly all process emissions from this process are from combustion of process off-gas, the final rule allows calculation of emissions from all stationary combustion units that burn process off-gas (with or without supplemental fuel) in accordance with the Tier 3 or Tier 4 procedures in 40 CFR part 98, subpart C. In addition, this option requires CO2, CH4, and N2O emissions from each flare to be calculated using the procedures in 40

CFR 98.253(b) (Petroleum Refineries).

Data Reporting. In addition to the information required to be reported by the General Provisions (40 CFR 98.3(c)) and summarized in

Recordkeeping. In addition to the records required by the General

Response to Public Comments, Subpart X: Petrochemical Production.''

The definition of the source category was changed to exclude ethylene dichloride production by the direct chlorination process alone from the petrochemical production source category because the only GHG emissions from this process are from the combustion of supplemental fuel and the combustion of hydrocarbon emissions in air pollution control devices. Ethylene dichloride produced by both direct chlorination and oxychlorination in the ``balanced process'' is still part of the source category.

For the mass balance option, the measurement and emission calculation frequency was changed from weekly to monthly.

For ethylene processes, an alternative was added to the mass balance option that allows reporters to calculate emissions from stationary combustion sources that burn ethylene process off-gas (with or without supplemental fuel) using the Tier 3 or Tier 4 procedures in 40 CFR part 98, subpart C. This includes all such combustion units, including units that supply energy to processes other than the ethylene process. This option does not affect requirements for stationary combustion sources related to ethylene processes that burn no process off-gas; emissions from these combustion units still must be calculated using the methods in any applicable Tier in 40 CFR part 98, subpart C.

The reporting requirements in 40 CFR 98.246 were reorganized and updated to facilitate the emissions verification process, simplify and clarify requirements, and address requirements for the new monitoring option for ethylene processes.

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3. Summary of Comments and Responses

This section contains a brief summary of major comments and responses. Many comments on petrochemical production were received covering numerous topics. Responses to significant comments received can be found in ``Mandatory Greenhouse Gas Reporting Rule: EPA's

Response to Public Comments, Subpart X: Petrochemical Production.''

Definition of Source Category.

Comment: Several commenters stated that ethylene production should be removed from the petrochemical production source category because essentially all GHG emissions from such processes are from combustion sources, which would be subject to reporting under 40 CFR part 98, subpart C regardless of whether the process is included in the petrochemical production source category. According to two commenters, using a mass balance approach is irrelevant and confusing because ethylene processes have no normal process vents. One commenter noted that methane is produced in ethylene processes, but the vast majority is returned as fuel within the plant or another plant at the same site and thus would produce CO2emissions only when combusted.

Another commenter noted that off-gas from ethylene processes that are co-located with a petroleum refinery or other chemical plants is sent to the fuel gas system where it is mixed with other process gases from non-ethylene units in a fuel gas blend drum and then distributed to combustion units throughout the refinery and/or chemical plant.

According to two commenters, the mass balance approach is onerous due to the number of product streams that would have to be measured, and the results of a mass balance most likely would be less accurate than a fuel combustion methodology. These two commenters also noted that calculating GHG emissions based on fuel combustion is the methodology used currently by most ethylene units. One commenter suggested that as an alternative to excluding ethylene units from the petrochemical production source category, EPA could add an emission calculation methodology to 40 CFR part 98, subpart X that would allow facilities to calculate combustion emissions based on fuel consumption.

Response: As one commenter noted, methane (and other light ends) are generally burned in combustion units to supply energy needs for the ethylene process itself and possibly other processes. Emissions from combustion of these process off-gases are process emissions that are intended to be reported under 40 CFR part 98, subpart X. At facilities where the ethylene process off-gases are not mixed with off-gas from other processes, we do not believe that the mass balance approach is illogical; the flows and carbon contents of feedstocks and products can be determined for an ethylene process, and the resulting values can be used in the mass balance equations, just as they can for any other petrochemical process. Furthermore, we do not know if the views of the commenters reflect the views of all ethylene manufacturers. Therefore, we have retained ethylene in the petrochemical production source category, and we have retained the mass balance option in the final rule.

Although we still think a mass balance approach is appropriate and valid for ethylene processes, we have also evaluated combustion-based methodology options for the final rule. Given that the cracking and separation operations generate negligible CO2, we agree with the commenters that the only significant source of emissions in ethylene production is from combustion operations. One concern we have with using the Tier 1 and Tier 2 methodologies in 40 CFR part 98, subpart C is that they rely on default emission factors and company records (rather than measurements) of fuel flow. Given the variety of feedstocks and the corresponding variety in process off-gas, we do not believe default emission factors or fuel flow based on company records are appropriate. Therefore, we rejected the Tier 1 and Tier 2 methodologies. On the other hand, Tier 3 requires measurement of the total fuel flow and relatively frequent measurement of the carbon content of the fuel. Using CEMS to measure CO2emissions

(i.e., the Tier 4 methodology in 40 CFR part 98, subpart C) is also a good way to measure CO2emissions from any combustion unit.

Therefore, we determined that use of the Tier 3 or Tier 4 methodology is acceptable for calculating emissions from combustion units that burn ethylene process off-gas (with or without mixing with supplemental fuel), and these options are included in the final rule. In addition, because the methodology used for calculating emissions from one combustion unit has no bearing on the emissions from any other combustion unit, the final rule states that a facility is not required to use the same Tier for each stationary combustion unit.

Comment: One commenter requested that EPA remove ethylene dichloride (EDC) from the petrochemical source category because EDC is not manufactured using a fossil fuel-based feedstock (e.g., crude oil, naphtha, natural gas condensate, methane, or other fossil fuel-based chemicals), no GHGs are used in the manufacturing process, and only a trace amount of CO2is generated in the process. Another commenter requested clarification that EDC produced as an intermediate in the production of vinyl chloride monomer is not part of the petrochemical source category because the entire process is considered to be an ``integrated process'', and the primary product of the process is not EDC. The commenter noted that the term ``primary product'' is also used in the Hazardous Organic NESHAP (HON) (40 CFR part 63, subpart F), but it has a different definition. To avoid confusion created by multiple definitions for the same term, the commenter urged

EPA to consider alternatives to the concept of primary product for determining applicability of an integrated process.

Response: EDC is produced by two processes. In one process, the direct chlorination process, ethylene is reacted with chlorine to create EDC. As the commenters noted, reactions in this process produce negligible CO2emissions and no other GHG emissions. The only GHG emissions associated with this process are from the combustion of process off-gas and supplemental fuel. We have determined that monitoring and reporting of these emissions will be required under 40

CFR part 98, subpart C. Therefore, we have removed this process from the petrochemical source category.

In the second EDC process, the oxychlorination process, ethylene is reacted with hydrochloric acid to create EDC and water. Some of the ethylene, however, oxidizes to CO2and water in a competing side reaction. All facilities in the United States (U.S.) that operate this process operate it as part of an integrated process that includes vinyl chloride monomer production and a direct chlorination process.

This integrated process is called a ``balanced process''. Although available estimates suggest the amount of CO2emitted is small relative to emissions from combustion, we do not have data to support such estimates. Furthermore, even if small relative to other sources, the total amount is not necessarily insignificant. We continue to believe information about these emissions is needed in order to support future policy decisions regarding petrochemical processes.

Therefore, we have not removed EDC production by the balanced process from the petrochemical production source category.

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In the proposed rule, an ``integrated process'' was defined as ``a process that produces a petrochemical as well as one or more other chemicals that are part of other source categories'' subject to reporting under 40 CFR part 98. This concept does not apply to production of EDC as an intermediate that is used in the onsite production of vinyl chloride monomer because vinyl chloride monomer production is not a source category that is subject to reporting under 40 CFR part 98. We used general language in the proposed rule that would apply to various integrated process scenarios, but the only scenario we know of that meets these conditions is methanol production from synthesis gas that is sometimes also used to produce hydrogen and/ or ammonia (both of which are subject to reporting under other subparts in 40 CFR part 98). Because this is the only situation where the

``integrated process'' concept would apply, we decided to replace it in the final rule with language in 40 CFR 98.240 that explicitly states the applicability determination procedures for a process that produces methanol, hydrogen, and/or ammonia from synthesis gas. Thus, the term

``primary product'' has also been removed from the final rule, which eliminates the potential conflict with the definition in the HON.

Method for Calculating GHG Emissions

Comment: Two commenters stated that the proposed CEMS requirements are overly restrictive. According to these commenters, a facility should have the option to install a CEMS on one or more sources without being required to have a CEMS on all sources associated with a petrochemical production process. For example, the commenters suggested that a facility should have the flexibility to use a CEMS on a large emission point while being allowed to use the combustion equations and/ or the mass balance approach for smaller emission points in the process

(e.g., start-up heaters and steam jet exhausts from distillation columns operating under vacuum).

Response: If some emissions were from stacks monitored with CEMS and all other emissions were from combustion units without CEMS, it would be possible to use a combination of CEMS and the combustion equation methodology to calculate the total GHG emissions from a petrochemical process. However, this scenario is unlikely, which means other methodology would be needed to estimate emissions from other emission points (e.g., the steam jet exhausts cited by the commenters).

It is not clear to us how the mass balance methodology would be used to estimate these other emissions because the mass balance relies on knowledge of the total carbon input to the process and the total amount of carbon in all products (and organic liquid wastes); the difference is assumed to be the total CO2emissions. Theoretically, other methodology could be developed to calculate emissions from specific other emission points, but the commenter has not suggested other techniques. Therefore, the final rule does not include an option to mix CEMS with other methodology for a given process unit.

Comment: According to several commenters, weekly measurements of feedstocks and products are burdensome or unwarranted. Two commenters suggested changing the frequency to monthly because monthly accounting would align better with existing industry accounting procedures, reduce the burden, and provide 12 high-quality estimates per year. One commenter suggested monthly mass balance calculations for carbon black facilities because the emissions from a carbon black manufacturing facility do not vary significantly from week to week. Another commenter requested a provision to allow the reporter to determine a sampling frequency that is consistent with the variability of the stream.

Response: We are sensitive to the burden imposed by the rule and want to minimize it when possible. Based on the results of an uncertainty analysis (see memorandum entitled ``Monte Carlo Simulation of Uncertainty in Monitoring Frequency for Mass Balance Option for

Petrochemical Production Facilities'' in the docket) we believe longer monitoring periods will not significantly compromise the monitoring results for the mass balance option. Therefore, the mass balance option in the final rule requires monthly monitoring instead of the proposed weekly monitoring.

Data Reporting Requirements

Comment: Two commenters stated that the proposed reporting requirements are excessive, particularly information such as each carbon content measurement and information on the calibration of each flow meter. According to the commenters, submitting this information will not improve the overall quality of the GHG emission calculation, and it is not necessary because the facilities are required to certify that the submitted information is true, accurate, and complete.

Therefore, the commenters recommended that facilities be required to retain records of such information rather than submit it in reports.

Response: A primary reason that additional information beyond annual emissions must be reported is so that EPA can verify the results. To facilitate the emissions verification process, 40 CFR 98.246 was reorganized and updated. For example, the final rule requires reporting of all input data used in the emission calculation equations, not just the carbon content values and the annual quantities, because this information is needed so the calculations can be reproduced and confirmed as part of the emissions verification process. Note, however, that any increase in the burden to report flow measurements has been offset by the reduction in monitoring frequency from weekly to monthly. The reporting requirements in the final rule for the mass balance option also have been simplified and clarified by replacing the requirement to submit all information related to uncertainty estimates with a requirement to submit only the dates and summarized results of measurement device calibrations. The estimated accuracy of measurement devices and the technical basis for such measurements must also be documented as part of the monitoring plan that is maintained onsite. The reporting section also was updated to include reporting requirements for the new monitoring option for ethylene processes.

Y. Petroleum Refineries 1. Summary of the Final Rule i. Source Category Definition

Petroleum refineries are facilities that produce gasoline, gasoline blending stocks, naphtha, kerosene, distillate fuel oils, residual fuel oils, lubricants, or asphalt (bitumen) by the distillation of petroleum or the redistillation, cracking, or reforming of petroleum derivatives.

The definition of petroleum refineries excludes facilities that distill only pipeline transmix (off-spec material created when different specification products mix during pipeline transportation), regardless of the products produced.

Reporters must submit annual GHG reports for facilities that meet the applicability criteria in the General Provisions (40 CFR 98.2) summarized in Section II.A of this preamble. ii. GHGs to Report

The refinery processes and gases that must be reported are listed in Table Y-1 of this preamble along with the rule subpart that specifies the calculation methodology that must be used.

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Table Y-1--GHGs To Report

Report emissions of the listed GHGs by following the requirements of the 40 CFR part 98, subpart

For this refinery process . . .

indicated . . .

CO2

CH4

N2O

Stationary combustion........................................

Flares.......................................................

Catalytic cracking...........................................

Traditional fluid coking.....................................

Fluid coking with flexicoking design.........................

C/Y

Delayed coking...............................................

Catalytic reforming..........................................

Onsite and offsite sulfur recovery...........................

Coke calcining...............................................

Asphalt blowing..............................................

Equipment leaks..............................................

Storage tanks................................................

Other process vents..........................................

Uncontrolled blowdown systems................................

Loading operations...........................................

Hydrogen plants (nonmerchant)................................

Key:

C = 40 CFR part 98, subpart C (General Stationary Combustion Sources).

P = 40 CFR part 98, subpart P (Hydrogen Production).

Y = 40 CFR part 98, subpart Y (Petroleum Refineries).

-- = Reporting from this process is not required. iii. GHG Emissions Calculation and Monitoring

Under 40 CFR part 98, subpart Y, petroleum refineries must calculate CO2, CH4and N2O emissions using the calculation methods described below for each refinery process.

For CO2emissions, reporters must use CEMS or specified calculation methods as follows:

For refinery units with certain types of CEMS in place, reporters must use the CEMS and follow the Tier 4 methodology of 40 CFR part 98, subpart C to report combined process and combustion

CO2emissions.

For refinery units without CEMS in place, reporters can elect to either (1) install and operate a CEMS to measure combined process and combustion CO2emissions according to the requirements specified in 40 CFR part 98, subpart C or (2) calculate

CO2emissions using the methods summarized below.

Flares. CO2emissions from flares must be calculated using the gas flow rate (either measured with a continuous flow meter or calculated using engineering calculations) and either: (1) At least weekly measured carbon content of the flare gas, or (2) at least weekly measured heat content of the flare gas and an emission factor provided in the rule. If the carbon content and heat content of the gas are not measured at least weekly, engineering estimates of heat content during normal flare use is allowed, but CO2emissions for each startup, shutdown, and malfunction event exceeding 500,000 standard cubic feet (scf) per day of flare gas must be calculated separately using engineering estimates of the quantity of gas discharged and the carbon content of the flared gas. CH4and N2O emissions from flares must be calculated using the methods specified in 40 CFR part 98, subpart Y.

Catalytic Cracking Units, Fluid Coking Units, and Catalytic

Reforming Units. CO2emissions must be calculated using the volumetric flow rate of the exhaust gas (measured or calculated) and hourly measured carbon monoxide (CO) and CO2concentrations in the exhaust stacks from the catalytic cracking unit regenerator and fluid coking unit burner from units exceeding 10,000 barrels per stream day. Catalytic cracking and fluid coking units below this threshold must use the required flow and gas monitors if they are in-place, but may use engineering estimates for determining CO2emissions if the required flow and gas monitors are not in place. Similarly, catalytic reforming units may use the flow and gas monitors required for large catalytic cracking and fluid coking units; alternatively, reporters may use engineering estimates based on the quantity of coke burned off, the carbon content of the coke (using either a measured or a default value), and the number of regeneration cycles. CH4 and N2O emissions may be measured or may be calculated using the CO2emissions and default emission factors. Fluid coking units that use the flexicoking design may account for their GHG emissions either by using the methods specified for traditional fluid coking units, or by using the methods for stationary combustion specified in 40 CFR part 98, subpart C.

Onsite and Off Site Sulfur Recovery. CO2emissions must be calculated using the volumetric flow rate of the sour gas (measured continuously or calculated from engineering calculations) and the carbon content of the sour gas stream (using a measured or a default value).

Coke Calcining Units. CO2emissions must be calculated from the difference between the carbon input as green coke and the carbon output as marketable petroleum coke and as coke dust collected in the dust collection system. The CH4and N2O emissions from coke calcining units may be measured or calculated using the calculated CO2emissions and default emission factors.

Asphalt Blowing Operations. For uncontrolled asphalt blowing operations or asphalt blowing operations controlled by vapor scrubbing,

CH4and CO2emissions must be calculated using a facility-specific emission factor based on test data or, where test data are not available, a default emission factor provided in the rule.

For asphalt blowing operations controlled by a thermal oxidizer or flare, CH4and CO2emissions must be calculated by assuming 98 percent of the CH4and other hydrocarbons generated by the asphalt blowing operation are converted to

CO2.

Delayed Coking Units. CH4emissions from the depressurization of delayed

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coking vessels must be calculated using the method outlined below for other process vents. The emissions released during the opening of vessels for coke cutting operations must be calculated using the vessel parameters (height and diameter), vessel pressure, the number of times the vessel was opened, the void fraction of the coking vessel prior to steaming, and the mole fraction of CH4in the gas released

(using a measured or a default value provided in the rule). The rule provides an alternative of using only the vessel parameter equation if no water or steam is added to the vessel after the vessel is vented to the atmosphere.

Other Process Vents. GHG emissions from other process vents that contain CO2, CH4, or N2O exceeding concentration thresholds specified in the rule must be calculated using the volumetric flow rate, the mole fraction of the GHG in the exhaust gas, and the number of hours during which venting occurred.

Uncontrolled Blowdown Systems. CH4emissions from uncontrolled blowdown systems must be calculated using either the method specified for process vents or a default emission factor and the sum of crude oil and intermediate products received from off site and processed at the facility.

Equipment Leaks. CH4emissions from equipment leaks must be calculated using either default emission factors or process-specific

CH4composition data and leak data collected using the leak detection methods specified in EPA's Protocol for Equipment Leak

Emission Estimates.

Storage Tanks. For storage tanks covered by the requirements of this rule, the methodology used to calculate the CH4 emissions depends on the material stored. For storage tanks used to store unstabilized crude oil, facilities must use either: (1) The

CH4composition of the unstabilized crude oil (based on direct measurement or product knowledge) and the measured gas generation rate; or (2) an emission factor-based method using the quantity of unstabilized crude oil received at the facility, the pressure difference between the previous storage pressure and atmospheric pressure, the mole fraction of CH4in the vented gas (using either a measured or a default value), and an emission factor provided in the rule. For storage tanks used to store material other than unstabilized crude oil with a vapor-phase CH4 concentration of 0.5 percent by volume or more, facilities must use either tank-specific methane composition data and applicable correlations in AP-42, Section 7.1 (as implemented in the TANKS Model

(Version 4.09D) or similar models) or a default emission factor provided in the rule.

Loading Operations. CH4emissions from loading operations must be calculated using vapor-phase methane composition data and the method in Section 5.2 of AP-42: ``Compilation of Air

Pollution Emission Factors.'' Facilities must calculate CH4 emissions only for loading materials that have an equilibrium vapor- phase CH4concentration equal to or greater than 0.5 percent by volume. Other facilities may assume zero CH4emissions. iv. Data Reporting

In addition to the information required to be reported by the

General Provisions (40 CFR 98.3(c)) and summarized in Section II.A of this preamble, reporters must submit additional data that are used to calculate GHG emissions. A list of the specific data to be reported for this source category is contained in 40 CFR part 98, subpart Y. v. Recordkeeping

In addition to the records required by the General Provisions (40

CFR 98.3(g)) and summarized in Section II.A of this preamble, reporters must keep records of additional data used to calculate GHG emissions. A list of specific records that must be retained for this source category is included in 40 CFR part 98, subpart Y. 2. Summary of Major Changes Since Proposal

Response to Public Comments, Subpart Y: Petroleum Refineries.''

The minimum monitoring frequency for flare gas heat value or carbon content was changed to weekly from daily. (For background on the selection of a weekly frequency, see memorandum entitled:

``Uncertainty in Flare Estimates Based on Sampling Frequency'' in the docket.) Engineering calculations are allowed in the final rule for reporters that do not monitor flare gas flow continuously or flare heating value or carbon content at least weekly.

The minimum monitoring frequency for refinery fuel gas carbon content and molecular weight was changed to weekly from daily in 40 CFR part 98, subpart C for reporters that do not have continuous monitoring equipment, and we clarified in 40 CFR part 98, subpart Y that common (fuel) pipe monitoring is allowed for petroleum refineries.

We added a flare combustion efficiency of 98 percent, and we revised the equation for flare CH4emissions to account for uncombusted methane.

The final rule allows engineering calculations to determine CO2emissions for catalytic cracking units and fluid coking units below 10,000 bbl/stream day that do not have

CO2/CO/O2monitors already installed.

The delayed coking unit depressurization emission equations and asphalt blowing equations were amended to address comments received.

We added concentration thresholds for CO2,

CH4and N2O from process vents below which GHG emissions are not required to be calculated and reported.

The reporting requirements were updated to facilitate the emissions verification process. 3. Summary of Comments and Responses

This section contains a brief summary of major comments and responses. A large number of comments on petroleum refineries were received covering numerous topics. Responses to significant comments received can be found in ``Mandatory Greenhouse Gas Reporting Rule:

EPA's Response to Public Comments, Subpart Y: Petroleum Refineries.''

Definition of Source Category

Comment: Several commenters expressed concern that EPA defined a

Petroleum Refinery so broadly that it could be interpreted to include chemical facilities that use petroleum-based materials as raw materials. Of particular concern was the term ``* * * and other products * * *'' which many commenters interpreted to include the manufacture of chemicals, synthetic rubber, and a variety of plastics.

One commenter also requested clarification that ``other products'' did not include sulfur, ammonia, or hydrogen sulfide. Several commenters requested clarification that the definition of petroleum refineries did not include lube oil production or fuel blending operations if the products were produced without distilling, redistilling, cracking, or reforming of the petroleum derivatives.

Response: We have revised and clarified the definition of petroleum refinery to list a few additional refinery products (specifically gasoline blending stocks and naphtha) and deleted the term ``or other products.'' We believe that this change clarifies that companies that use petroleum derivatives to make

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only petrochemicals, plastics, synthetic rubber, sulfur, or any other product other than those specifically listed are not considered petroleum refineries. We feel the definition also clearly excludes lube oil manufacturing provided the lube oil manufacturer does not distill, redistill, crack, or reform the petroleum derivatives at the facility.

Comment: Numerous commenters requested that many of the emission sources for which 40 CFR part 98, subpart Y required reporting were small and should not have to be reported. Several commenters noted that

EPA's TSD for the Petroleum Refining Sector: Proposed Rule for

Mandatory Reporting of Greenhouse Gases, indicates that 92.9 percent of the refining sector's GHG emissions come from two sources, combustion and catalytic coke operations. The remaining 7.1 percent of emissions come from eight distinct categories, including: Hydrogen plants (2.7 percent); Sulfur Plants (1.9 percent); Flaring (1.6 percent);

Wastewater Treatment (0.43 percent); Blowdown (0.18 percent); Asphalt

Blowing (0.10 percent); Delayed Coking (0.058 percent); Equipment Leaks

(0.014 percent); Storage Tanks (0.007 percent); and Cooling Towers

(0.003 percent). The commenters argued that the burden associated with the collection of data as prescribed in the proposed rule is not warranted for small sources and/or not consistent with EPA's stated intended purpose of the rule which is to support analysis of future policy decisions.

Response: The TSD estimates are based largely on engineering estimates without significant supporting data. For the smaller sources, we have provided very simple methods to calculate the GHG emissions from these sources to minimize the monitoring, recordkeeping, and reporting burden associated with these sources when no measurement data are available. However, requiring reporting for these sources will provide EPA with valuable data to better characterize them and provide a better record upon which to formulate decisions regarding whether to include or exclude these sources from future GHG policy decisions.

Additionally, while some of these sources are currently believed to be small compared to the larger sources present at petroleum refineries, they are not necessarily insignificant. The inclusion of reporting data for these sources is critical to support analysis of future policy decisions for petroleum refineries.

Comment: Several commenters objected to the mandatory reporting of

CH4and N2O emissions within the Petroleum

Refinery source category. Many commenters cited the TSD, which indicated that N2O emissions account for 0.09 percent of the

GHG emissions and CH4account for only 0.87 percent of the

GHG emissions. The commenters argued that the measurement error for the larger sources (stationary combustion sources and catalytic cracking unit coke burn-off) exceeds the contributions of these sources. As such, the commenters stated that the burden associated with reporting these emissions is not warranted and/or not consistent with EPA's stated intended purpose of the rule which is to support analysis of future policy decisions.

Response: The TSD estimates for CH4and N2O are based largely on engineering estimates without significant supporting data. We specifically require reporting of these various

GHGs to obtain better data by which to support future policy analysis.

Moreover, EPA has pending before it a petition to reconsider the recently revised New Source Performance Standard (NSPS) for petroleum refineries asking EPA to reconsider, among other things, whether to establish GHG standards under section 111 for refineries. As such, we have a keen interest in obtaining improved GHG emissions data in order to better analyze policy options. For instance, refineries are a significant source of NOXemissions, but we have no data to determine the fraction of NOXthat is N2O. With the increased use at refineries of NOXcontrol devices, such as low-NOXburners, low excess air, selective catalytic reduction (SCR) systems, and selective non-catalytic reduction (SNCR) systems, it seems plausible that N2O may be a more significant portion of a refinery's NOXemissions. Thus, if a facility has measurement data for a source, the reporting of these data are important for better understanding the impact of current and future policy options. Consequently, we have provided additional alternatives that allow the use of measured N2O (and

CH4) emissions or site-specific emission factors in addition to the default factors. Nonetheless, we have provided very simple default methods to calculate the emission of these GHGs when measurement data are not available. While emissions of CH4 and N2O may not be large comparatively, the reporting method for these pollutants is straightforward and commensurate with the anticipated emissions contribution.

Method for Calculating GHG Emissions

Comment: Several comments objected to the requirements for flares, particularly the requirements for SSM events. Some commenters also stated that daily sampling was too burdensome. The commenters suggested that flare emissions be dropped from the rule or that refineries be allowed to perform a one-time calculation. One commenter noted that the proposed equation did not account for flare combustion efficiency, which was inconsistent with other subparts, and recommended that a flare efficiency factor be added to the equation to calculate the

CO2emissions from flares.

Response: EPA needs accurate data on flare emissions to better understand this emission source, as flare use can vary significantly from day-to-day and year-to-year. Use of flares is too episodic and variable to allow a one-time calculation. However, we recognize that flares may contribute about two percent of a refinery's GHG emissions.

Therefore, we sought to reduce the burden associated with the flare monitoring and reporting requirements. As proposed, special calculations for SSM events were only required if daily measurement data were not available. In this final rule, we allow weekly monitoring of flare use without triggering special SSM event calculations, which should lessen the burden associated with calculating flare emissions while not significantly changing the accuracy of the data.

Additionally, we included a threshold flaring rate of 500,000 scf/day for SSM events. Only SSM events exceeding this gas flare rate require special SSM calculations in the final rule. Some consent decree requirements and State rules require root cause analysis and quantification of emission events exceeding 500,000 scf/day. We consider events of this magnitude to be significant and believe a separate analysis is justified in addition to the procedures that apply to routine operation. We have also revised the equations for

CO2and CH4to account for flare combustion efficiency.

Monitoring and QA/QC Requirements

Comment: Several commenters argued that the monitoring and QA/QC requirements were excessive and that EPA significantly underestimated the costs associated with complying with the reporting requirements under 40 CFR part 98, subpart Y. One commenter noted that existing facility CO2CEMS, HHV monitors, carbon content monitors, and flow meters are not necessarily for ``regulatory'' purposes and thus may not meet the accuracy requirements of the rule. The commenter suggested many more refineries would have to add or replace monitors as a result of the rule. Many commenters suggested EPA significantly

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underestimated the labor hours required to collect and analyze daily samples as well as to develop and implement a QA plan. Various commenters supplied labor or cost estimates for various requirements in the rule, including costs of implementing an LDAR program and flare SSM calculations. Several commenters stated that the requirement to use a

CEMS for monitoring CO2from the catalytic cracking unit was expensive and burdensome, especially for small refineries that do not have a CEMS infrastructure.

Response: We have significantly revised our rule requirements for petroleum refineries and stationary combustion sources to reduce burden to the industry. We have provided in the final rule (in 40 CFR part 98, subpart C) a default emission factor for refinery (still) gas to allow combustion sources that combust refinery gas and meet the applicability requirements in 40 CFR part 98, subpart C to use Tier 2 methods. For sources that do not meet the Tier 2 requirements, weekly monitoring for refinery fuel gas under Tier 3 (40 CFR part 98, subpart C) and for flare gas (40 CFR part 98, subpart Y) is allowed. We have also re- assessed our costs based on the comments received and increased the labor hours estimated to collect and analyze samples, develop QA plans, and to perform QA/QC of existing equipment. We did review our QA/QC requirements and see no validity to the argument that our QA/QC requirements are so stringent that refineries will have to replace existing monitors to comply with the rule. While we note that some cost elements suggested by commenters are relevant and have been addressed in the changes in the labor estimates for sampling, analysis, and QA/QC as described above, other cost elements suggested by commenters are not relevant. For example, revisions of LDAR programs are not required under the rule; the proposed and final rule specifically provides a simple process-based emission factor approach for estimating

CH4emissions from equipment leaks. We are cognizant that refineries with small catalytic cracking units are most likely to elect a compliance option under 40 CFR part 63, subpart UUU that does not require monitoring of coke burn-off, so these small refineries are most likely the facilities that would have been required to install monitoring equipment under the proposed rule. After reviewing these costs and impacts on the small refineries, we have allowed engineering calculations to determine CO2emissions for catalytic cracking units below 10,000 bbl/stream day that do not have

CO2/CO/O2monitors already installed.

Even though we have reduced the stringency of the rule in many places, our revised cost estimates indicate that the average cost per refinery is approximately 60 percent higher than projected at proposal.

We believe our revised refinery costs accurately portray the burden associated with the final reporting requirements in 40 CFR part 98, subpart Y. Nonetheless, we continue to believe that the costs are reasonable for this rule, especially considering that petroleum refineries are among the larger sources of GHG emissions in the U.S.

Z. Phosphoric Acid Production 1. Summary of the Final Rule

Source Category Definition. The phosphoric acid production source category consists of facilities that use a wet-process phosphoric acid process to produce phosphoric acid. A wet-process phosphoric acid process line is any system that manufactures phosphoric acid by reacting phosphate rock and acid and is usually identified by an individual identification number in a CAA operating permit.

Reporters must submit annual GHG reports for Facilities that meet the applicability criteria in the General Provisions (40 CFR 98.2) summarized in Section II.A of this preamble.

GHGs to Report. Report CO2emissions from each wet- process phosphoric acid process line.

In addition, report GHG emissions at each facility for other source categories for which calculation methods are provided in the rule, as applicable. For example, report CO2, N2O, and

CH4emissions from each stationary combustion unit on site under 40 CFR part 98, subpart C (General Stationary Fuel Combustion

Sources).

GHG Emissions Calculation and Monitoring. Calculate process emissions of CO2using one of two methods, as appropriate:

Most reporters can elect to either (1) install and operating CEMS and follow the Tier 4 methodology (in 40 CFR part 98, subpart C) or (2) calculate CO2emissions based on monthly measurements of the mass of phosphate rock consumed and inorganic carbon content of each grab sample of phosphate rock.

However, if process CO2emissions from phosphoric acid production are emitted through the same stack as a combustion unit or process equipment that uses a CEMS and follows Tier 4 methodology to report CO2emissions, then the CEMS must be used to measure and report combined CO2emissions from that stack. In such cases, the reporter cannot use the CO2 calculation methodology outlined in approach (2) in the previous bullet.

Data Reporting. In addition to the information required to be reported by the General Provisions (40 CFR 98.3(c)) and summarized in

Recordkeeping. In addition to the records required by the General

Response to Public Comments, Subpart Z: Phosphoric Acid Production.''

The rule was revised to allow the use of techniques from

Part 60 and Part 63 for calculating the weight of phosphorous- containing rock.

The missing data provisions were revised to allow the use of default inorganic carbon content values based on the origin of the phosphorous-containing rock, in addition to determining missing inorganic carbon contents of phosphate rock consumed using an arithmetic average of measured values from of inorganic carbon contents of phosphate rock of the appropriate origin preceding and following the missing data incident. 40 CFR 98.266 was reorganized and updated to improve the emissions verification process. Some data elements were moved from 40

CFR 98.267 to 40 CFR 98.266, and some data elements that are already used to calculate GHG emissions as specified in 40 CFR 98.263 were added to 40 CFR 98.266 for clarity. 3. Summary of Comments and Responses

This section contains a brief summary of major comments and responses. Several comments on phosphoric acid production were received covering numerous topics shown below.

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Responses to significant comments received can be found in ``Mandatory

Greenhouse Gas Reporting Rule: EPA's Response to Public Comments,

Subpart Z: Phosphoric Acid Production.''

Selection of Threshold

Comment: Multiple commenters asked that phosphoric acid production units not be included as an ``all-in'' category. According to the commenters, the facilities are very minor sources of GHG emissions. The commenter conceded that most (if not all) would still fall within the reporting threshold requirement, but asserted that it was unnecessary to include all phosphoric acid production units as regulated facilities regardless of the amount of emissions. The commenters stated that EPA inaccurately suggests that these units are major emitters of GHGs which could have significant impacts on these minor sources.

Response: We acknowledge the comments and concerns; however the final rule retains the ``all-in'' applicability requirement for this source category. The ``once in, always in'' provision has been removed.

The final rule now contains provisions to cease reporting if annual reports demonstrate emissions less than specified levels for multiple years. These provisions apply to all reporting facilities, including those with phosphoric acid production processes. The purpose of this rule is to collect information on emissions sources for future policy development. Requiring reporting for these sources will provide EPA with valuable data to better characterize GHG emissions from phosphoric acid production and provide a more credible position if EPA elects to exclude these sources from future GHG policy analyses. We also believe that the accurate assessment of the emissions from phosphoric acid production will address the commenters' concerns about potential future impacts.

Commenters may also be interested in reviewing Section II.H of this preamble for the response on provisions to cease reporting.

Method for Calculating GHG Emissions and Monitoring and QA/QC

Requirements

Comment: Multiple commenters asked that production measurements in this rule be consistent with the existing MACT and NSPS regulations for the phosphate industry. In these regulations, production measurement is determined by the mass of phosphate feed (as

P2O5). Two commenters stated that the change would provide consistency, and ensure a reporting structure that fits with the actual practices of the industry.

Response: We agree with the commenters that consistency among EPA regulations is important. Therefore, the final rule allows for techniques from part 60 and part 63 to calculate the weight of phosphorous-containing rock. This request is consistent with the intent of the proposed rule. Under existing regulations in part 60 and part 63, phosphoric acid manufacturing facilities already measure the mass of phosphorous bearing feed on a ton/hour basis. This feed rate can be used to determine monthly phosphate rock consumption. Process

CO2emissions from phosphoric acid production are calculated from the total phosphate rock consumption multiplied by the inorganic carbon content of that rock. Further, part 60 and part 63 establish the appropriate monitoring and QA/QC procedures for determining this feed rate.

Procedures for Estimating Missing Data

Comment: Multiple commenters asked that the final rule allow options for missing data. The commenters asked that the use of default carbon content values based on the origin of the rock be allowed if analytical data are unavailable. In addition, commenters requested that procedures be added for measurement of the mass of phosphate rock consumed, suggesting procedures similar to those in 40 CFR part 98, subpart C, the lesser of the maximum capacity of the system, the maximum rate the meter can measure, or best available estimate based on available process data.

Response: We agree with the commenters on this point. The final rule has been changed to allow the use of a default factor (by origin of the phosphate rock) for each missing value of the inorganic carbon content of phosphate rock. Use of a default carbon value in place of the missing data will provide a reasonable estimate of the total emissions from the facility and will avoid assuming the maximum possible facility emissions when no data are available. These default values have been added to the final rule in Table Z-1 of 40 CFR part 98, subpart Z.

Missing data procedures have also been added as suggested for missing monthly estimates of the mass of phosphate rock consumed consistent with the later recommendation. Again use of the best available data based on all available process data will avoid assuming the maximum possible facility emissions when no data are available.

Facilities must document and keep records of the procedures used for all such estimates.

AA. Pulp and Paper Manufacturing 1. Summary of the Final Rule

Source Category Definition. This source category consists of facilities that produce market pulp (i.e., stand-alone pulp facilities), manufacture pulp and paper (i.e., integrated mills), produce paper products from purchased pulp, produce secondary fiber from recycled paper, convert paper into paperboard products (e.g., containers), or operate coating and laminating processes.

Reporters must submit annual GHG reports for facilities that meet the applicability criteria in the General Provisions (40 CFR 98.2) summarized in Section II.A of this preamble.

GHGs to Report. Table AA-1 of this preamble lists the GHG emission sources at pulp and paper manufacturing facilities for which GHG emissions must be reported along with the rule subpart that specifies the calculation methodology.

Table AA-1--GHGs To Report

Report emissions of the listed GHGs by following the requirements of the 40 CFR part 98, subpart indicated ...

For pulp and paper mills ... ---------------------------------------------------------------------------------

Biogenic

CO2

CH4

N2O

CH4

N2O

Chemical recovery furnace at

AA kraft and soda facilities.

Chemical recovery combustion

AA units at sulfite facilities.

Chemical recovery combustion

AA units at stand alone semi- chemical facilities.

Lime kilns of kraft and soda

AA/C

AA facilities.

Makeup chemicals used in pulp AA

............ ............ ............ ........... ........... mills.

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Stationary combustion units... C

Key:

C = 40 CFR part 98, subpart C (General Stationary Fuel Combustion Sources).

AA = 40 CFR part 98, subpart AA (Pulp and Paper Manufacturing).

AA/C = use 40 CFR part 98, subpart AA for GHG emission factor and subpart C to determine default High Heating

Values.

GHG Emissions Calculation and Monitoring. Under 40 CFR part 98, subpart AA, reporters must calculate emissions from pulp and paper manufacturing facilities as follows:

Chemical recovery furnaces: Calculate biogenic

CO2emissions from combustion of biomass in spent pulping liquor using:

--Measured quantities of spent liquor solids fired, site-specific high heating value (HHV), and default or site-specific emission factors for each chemical recovery furnace located at kraft or soda facilities.

--Measured quantities of spent liquor solids fired and the carbon content of the spent liquor solids for each chemical recovery unit at sulfite or stand-alone semichemical facilities.

Calculate CO2emissions from fossil fuels used in chemical recovery furnaces using direct measurement of fossil fuels consumed and default emission factors according to the Tier 1 methodology for stationary combustion sources in 40 CFR part 98, subpart C.

Calculate CH4and N2O emissions as the sum of emissions from the combustion of fossil fuels and the combustion of biomass in spent pulping liquor, as follows:

--For fossil fuel emissions, use direct measurement of fuels consumed, a default HHV, and default emission factors according to the methodology for stationary combustion sources in 40 CFR 98.33(c).

--For biomass emissions, use measured quantities of spent liquor solids fired, site-specific HHV, and default or site-specific emission factors.

--Lime kilns at kraft and soda facilities.

Lime kilns: Calculate CO2, CH4, and

N2O emissions from combustion \21\ of fossil fuels in pulp mill lime kilns using direct measurement of fossil fuels consumed and default emission factors and HHV found in 40 CFR part 98, subparts AA and C, respectively.

\21\ Biogenic CO2from the conversion of

CaCO3to CaO in kraft or soda pulp mill lime kilns is accounted for in the biogenic CO2emission factor for the recovery furnace.

Makeup chemicals: Calculate CO2emissions from the use of makeup chemicals using direct or indirect measurement of the quantity of chemicals added and ratios of the molecular weights of

CO2and the makeup chemicals.

Data Reporting. In addition to the information required to be reported by the General Provisions (40 CFR 98.3(c)) and summarized in

Recordkeeping. In addition to the records required by the General

Response to Public Comments, Subpart AA: Pulp and Paper

Manufacturing.''

Language was added to clarify that 40 CFR part 98, subpart

AA GHG emissions are to be reported for makeup chemicals added in the chemical recovery areas of pulp mills (as opposed to makeup chemicals used at paper coating and laminating facilities).

The frequency of measurements for the spent liquor solids mass fired (TAPPI Test Method T 650), heating value (TAPPI Test Method

T 684), and carbon content (ASTM D5373-08) was reduced from monthly to annually.

An option to use data from existing online solids meters to determine the annual mass of spent liquor solids fired is provided

(in lieu of conducting an annual TAPPI Test Method T 650).

The requirement to report quarterly data was eliminated.

The reporting requirements were revised to specify units to standardize inputs into the data reporting system. 3. Summary of Comments and Responses

This section contains a brief summary of major comments and responses. A number of comments on pulp and paper manufacturing were received covering numerous topics. Responses to significant comments received can be found in ``Mandatory Greenhouse Gas Reporting Rule:

EPA's Response to Public Comments, Subpart AA: Pulp and Paper

Manufacturing.''

Definition of Source Category

Comment: Two commenters stated that literal interpretation of 40

CFR part 98, subpart AA could require any facility operating paper coating and laminating processes to report emissions for any system used to add makeup chemicals. The commenters requested that language be added to 40 CFR part 98, subpart AA to clearly exclude facilities not intended to be covered and which have not traditionally been part of the pulp and paper source category.

Response: Definitions of terms used in 40 CFR part 98, subpart AA are provided in 40 CFR 98.6 (in subpart A of part 98). The definition of ``makeup chemicals'' is specific to the chemical recovery areas of pulp mills and serves to limit the scope of the pulp and paper subcategory. As defined in Sec. 98.6 (emphasis added):

``Chemical recovery combustion unit means a combustion device, such as a recovery furnace or fluidized-bed reactor where spent pulping liquor from sulfite or semi-chemical pulping processes is burned to recover pulping chemicals.''

``Makeup chemicals means carbonate chemicals (e.g., sodium and calcium carbonates) that are added to the chemical recovery areas of chemical pulp mills to replace chemicals lost in the process.''

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Thus, we disagree that the rule could be interpreted to require any facility operating coating and laminating processes to report emissions for any system used to add makeup chemicals. This was not the intent of the rule. Nevertheless, we have added language consistent with the definition of ``makeup chemicals'' to 40 CFR 98.270(b)(5) and 98.272(e) to further clarify that GHG emissions are to be reported for systems adding makeup chemicals (CaCO3and

Na2CO3) in the chemical recovery areas of pulp mills.

Comment: Commenters stated the rule should include categorical exemptions for emissions from the combustion of non-condensable gases

(NCG), stripper off gases (SOG), tall oil and turpentine (small sources of GHG that are difficult to measure). The commenters noted that these streams are of biogenic origin. One commenter described safety issues associated with sampling these gas streams.

Response: Pulp mill NCG, SOG, tall oil and turpentine were discussed in the Proposed Rule TSD for the pulp and paper manufacturing sector. The Proposed Rule TSD noted that process vent gases such as NCG and SOG and the byproducts tall oil and turpentine are derived from biomass. We acknowledge the safety and measurement issues described by commenters regarding sampling of NCG and SOG streams. No methods are specified in the rule for calculation of GHG associated with combustion of NCG, SOG, tall oil and turpentine. Thus, calculation of these emissions is not required and there is no need for categorical exemptions.

Method for Calculating GHG Emissions

Comment: Commenters stated that monthly measurements of the mass of spent liquor solids, HHV, and carbon content of spent liquor solids are unnecessary. The commenters requested that EPA either allow default fuel carbon content and heating value for spent pulping liquor, or reduce the frequency of measurements to annually or every two years.

Commenters noted that spent liquor HHV and carbon content are measured from time to time but less frequently than monthly. In addition, one commenter pointed out that chemical recovery furnaces often have online solids meters installed to provide continuous measurement of the mass of spent liquor solids entering the furnace for safety and process control reasons. This commenter requested that EPA allow use of such continuous measurement devices instead of requiring monthly measurement of the mass of spent liquor solids with TAPPI Test Method T 650.

Response: We disagree with commenters that default fuel carbon content and high heating values should be allowed instead of measured values. These parameters are already measured by mills (though less frequently than monthly) and thus are available for use and more accurate than default values. We are reducing the frequency of fuel property measurements from monthly to annual. There is little monthly variation in fuel properties over the course of a year. Therefore, annual measurements are sufficient to develop site specific emission factors. This change also reduces the burden associated with complying with the rule. These changes have been incorporated throughout the text and equations of 40 CFR part 98, subpart AA.

In addition, the final rule allows use of either an annual measurement of the mass of spent liquor solids fired (with TAPPI Test

Method T 650) or use of annual spent liquor solids data calculated from continuous measurements already performed for process control purposes

(e.g., with existing online solids meters). If the annual spent liquor solids fired is determined using existing measurement equipment, then reporters must retain records of the calculations used to determine the annual mass of spent liquor solids fired from the continuous measurements in order to demonstrate, if necessary, that calculations where done correctly. Reporters must also document that these measurement devices have been regularly and properly calibrated according to the manufacturer's specifications.

Data Reporting Requirements

Comment: One commenter noted that presenting quarterly data in annual reports for pulp and paper manufacturing annual emissions, consumption of biomass fuels, and quantity of spent liquor solids fired is unnecessary for an annual reporting system.

Response: We have revised 40 CFR 98.276 and 98.277(a) to remove the requirement for providing quarterly details in the annual report. EPA agrees that requiring quarterly details was not necessary for ensuring the accuracy of data reported annually.

Comment: One commenter requested that the spreadsheets developed by the National Council for Air and Stream Improvement (NCASI) for the

International Council of Forest and Paper Associations (ICFPA) be allowed as an option for facilities subject to the Rule to determine emissions. These spreadsheets segregate calculated GHG emissions into fossil fuel and biogenic categories. The commenter believes that tools like those developed by NCASI and others should be allowed as an option for facilities subject to the emission calculation requirements imposed by 40 CFR 98.3. This streamlined approach will provide the Agency with valid GHG emission data without imposing extraordinary capital and labor burdens on the industry.

Response: The ICFPA/NCASI tools were considered in developing the requirements of the GHG reporting rule. However, the ICFPA/NCASI spreadsheets, though valuable tools, are not broadly applicable to all industrial sectors covered under the GHG reporting rule, as are the monitoring, reporting, recordkeeping, and emissions verification requirements specified in 40 CFR 98.3. Additionally, these tools often use default factors and estimates, which differs from the approach proposed by EPA. The data collected from all subparts of the GHG reporting rule will be tabulated in EPA's electronic reporting system.

This system will be used to verify emission calculations and will require specific data be reported in order to run the calculations used for verification. The tools suggested by the commenter, however, would only provide a total emission number. Consequently, EPA would not be able to check the underlying calculations for accuracy. The final GHG reporting rule reflects the data reporting requirements necessary for emissions verification by EPA. Edits to the reporting and recordkeeping language (40 CFR 98.276 and 98.277) of 40 CFR part 98, subpart AA were made to clarify calculation inputs and units of measure to be reported.

As part of the implementation phase of today's final rule, EPA intends to prepare guidance documents to assist the industry in complying with the rule's requirements. In recognition of the fact that the pulp and paper industry has been using the ICFPA/NCASI spreadsheets, EPA will consider including in the guidance materials a comparison between these spreadsheets and EPA's electronic reporting system to reduce the burden on the industry and minimize confusion.

BB. Silicon Carbide Production 1. Summary of the Final Rule

Source Category Definition. The silicon carbide production source category consists of any process that produces silicon carbide for abrasive purposes.

Reporters must submit annual GHG reports for facilities that meet the

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applicability criteria in the General Provisions (40 CFR 98.2) summarized in Section II.A of this preamble.

GHGs to Report. Report process CO2and CH4 emissions from all silicon carbide production furnaces or process units at the facility combined.

In addition, report GHG emissions for other source categories at the facility for which calculation methods are provided in the rule, as applicable. For example, report CO2, N2O, and

CH4emissions from each stationary combustion unit on site under 40 CFR part 98, subpart C (General Stationary Fuel Combustion

Sources).

GHG Emissions Calculation and Monitoring. For CO2 emissions, reporters must use one of the following methods, as appropriate:

Most reporters can elect to calculate and report process

CO2emissions from silicon carbide production processes by either (1) installing and operating CEMS and following the Tier 4 methodology (in 40 CFR part 98, subpart C) or (2) calculating emissions using the measured petroleum coke consumption and a monthly facility- specific emission factor. The facility-specific emission factor is the carbon content of the petroleum coke (provided monthly by the supplier or measured monthly using the appropriate test methods) adjusted for carbon in the silicon carbide product.

However, if process CO2emissions from silicon carbide production are vented through the same stack as a combustion unit or process equipment that uses a CEMS and follows Tier 4 methodology to report process CO2emissions, then the CEMS must be used to measure and report combined CO2emissions from that stack. In such cases, the reporter cannot use the

CO2calculation approach (2) outlined in the above bullet.

For CH4emissions, reporters must use the measured petroleum coke consumption and a default emission factor of 10.2 kilograms (kg) per metric ton of coke consumed.

Data Reporting. In addition to the information required to be reported by the General Provisions (40 CFR 98.3(c)) and summarized in

Recordkeeping. In addition to the records required by the General

Response to Public Comments, Subpart BB: Silicon Carbide Production.''

The emissions calculation method under 40 CFR 98.283(b) was revised to require data on monthly petroleum coke consumption and monthly petroleum coke carbon contents rather than quarterly determinations.

Missing data procedures were added under 40 CFR 98.285 for monthly parameters used to calculate emissions, including mass of petroleum coke, and carbon contents of petroleum coke. 40 CFR 98.286 was reorganized and updated to improve the emissions verification process. Some data elements were moved from 40

CFR 98.287 to 40 CFR 98.286, and some data elements that a reporter must already use to calculate GHGs as specified in 40 CFR 98.283 were added to 40 CFR 98.286 for clarity. 3. Summary of Comments and Responses

No specific comments were received pertaining to the proposed reporting requirements for silicon carbide production facilities.

However, the proposed rule did not clearly specify how quarterly carbon contents should be determined. This determination should be made on a monthly basis as proposed for other chemical production processes where process emissions arise from use of petroleum coke, such as titanium dioxide production. Quarterly reporting of carbon contents of petroleum coke consumed for the quarter would have to be averaged from monthly data. For verification, EPA would require reporting of the monthly carbon contents of the petroleum coke. Therefore, we revised the emissions calculation method to directly require monthly petroleum coke consumption and monthly petroleum coke contents, rather than quarterly based on an arithmetic average of the monthly estimates to improve accuracy of emissions calculations. We have retained the flexibility in use of supplier data to determine carbon contents. We understand that most supplier data on carbon contents of petroleum coke is readily available and that businesses track production inputs and outputs on a monthly basis as a part of normal business practice or existing accounting procedures. The increased frequency of data collection from quarterly to monthly provides greater clarity and accuracy without significantly increasing burden. In addition, see the Section II.N of this preamble for an explanation of the emissions verification approach.

CC. Soda Ash Manufacturing 1. Summary of the Final Rule

Source Category Definition. A soda ash manufacturing facility is any facility with a manufacturing line that produces soda ash by either: calcining trona or sodium sesquicarbonate; or by using a liquid alkaline feedstock process that directly produces CO2. In the context of the soda ash manufacturing sector, ``calcining'' means the thermal/chemical conversion of the bicarbonate fraction of the feedstock to sodium carbonate.

Soda ash produced from a liquid alkaline feedstock using sodium hydroxide does not emit process CO2and therefore is not subject to the requirements of Subpart CC. However, such facilities may be covered under Subpart C (General Stationary Combustion) if they meet the requirements of either Sec. 98.2(a)(1) or (2).

Reporters must submit annual GHG reports for facilities that meet the applicability criteria in the General Provisions (40 CFR 98.2) summarized in Section II.A of this preamble.

GHGs to Report. For soda ash manufacturing, report the following emissions:

CO2process emissions from soda ash manufacturing, reported for each manufacturing line.

CO2combustion emissions from each soda ash manufacturing line.

N2O and CH4emissions from fuel combustion at each soda ash manufacturing line under 40 CFR part 98, subpart C (General Stationary Fuel Combustion Sources) using the methodologies in subpart C.

CO2, N2O, and CH4 emissions from each stationary combustion unit other than soda ash manufacturing lines under 40 CFR part 98, subpart C (General Stationary

Fuel Combustion Sources).

In addition, report GHG emissions for any other source categories at the facility for which calculation methods are provided in other subparts of the rule, as applicable.

GHG Emissions Calculation and Monitoring. For CO2 emissions from soda ash manufacturing lines, reporters must select one of the following methods, as appropriate:

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For each soda ash manufacturing line with certain types of

CEMS in place, reporters must use the CEMS and follow the Tier 4 methodology (in 40 CFR part 98, subpart C) to report under the Soda Ash

Manufacturing subpart (40 CFR part 98, subpart CC) combined process and combustion CO2emissions.

For other soda ash manufacturing lines, reporters can elect to either (1) install and operate a CEMS and follow Tier 4 methodology to measure and report combined process and combustion

CO2emissions or (2) calculate CO2process emissions using the procedures specified in 40 CFR part 98, subpart CC and summarized below.

If using approach 2, calculate process CO2 emissions using one of three alternative methods, as appropriate for each manufacturing line:

--The trona input method calculates the calcination emissions using:

Monthly mass of trona input (required to be measured), the average monthly mass-fraction of inorganic carbon in the trona (required to be measured weekly), and the ratio of CO2emitted for each ton of trona consumed (a default value is provided).

--The soda ash output method calculates the calcination emissions using: Monthly mass of soda ash produced (required to be measured), the monthly average mass-fraction of inorganic carbon in the soda ash

(required to be measured weekly), and the ratio of CO2 emitted for each ton of soda ash produced (a default value is provided).

--The site-specific emission factor method calculates emissions from production of soda ash using liquid alkaline feedstock through an annual performance test using: The average process vent flow rate from the mine water stripper/evaporator for each manufacturing line, direct measurements of hourly CO2concentration, the hourly stack gas volumetric flow rate, the annual process vent flow rate from mine water stripper/evaporator, and annual operating hours.

--Report process CO2emissions from each soda ash manufacturing line under 40 CFR part 98, subpart CC (Soda Ash

Manufacturing), and report combustion CO2emissions from each calciner (kiln) in each manufacturing line under 40 CFR part 98, subpart C (General Stationary Fuel Combustion Sources).

Data Reporting. In addition to the information required to be reported by the General Provisions (40 CFR 98.3(c)) and summarized in

Recordkeeping. In addition to the records required by the General

Response to Public Comments, Subpart CC: Soda Ash Manufacturing.''

A site-specific emission factor method has been added for production of soda ash using liquid alkaline feedstock or mine water.

This method was not included in the proposed rule.

The frequency of inorganic carbon content determination of either trona or soda ash has been revised from daily to monthly based on a weekly composite.

Procedures were added to 40 CFR 98.295 for estimating missing data for monthly values of inorganic carbon content of trona and monthly values of trona consumption or soda ash production. We also added missing data procedures for parameters specific to calculating emissions from soda ash produced from liquid alkaline feedstock (i.e. site-specific emission factor method). 40 CFR 98.296 was reorganized and updated to improve the emissions verification process. Some data elements were moved from 40

CFR 98.297 to 40 CFR 98.296, and some data elements that a reporter must already use to calculate GHGs as specified in 40 CFR 98.293 were added to 40 CFR 98.296 for clarity. 3. Summary of Comments and Responses

This section contains a brief summary of major comments and responses. Two sets of comments on soda ash manufacturing were received covering several topics. Responses to significant comments received can be found in ``Mandatory Greenhouse Gas Reporting Rule: EPA's Response to Public Comments, Subpart CC: Soda Ash Manufacturing.''

Method for Calculating GHG Emissions

Comment: Both commenters noted that facilities produced soda ash using alternative methods to calcining trona or other carbonate containing minerals. Facilities also produce soda ash from mine water, a liquid alkaline feedstock; this is a ``process'' emissive production process, but was not addressed in the proposal. The methods in the proposal did not include methods appropriate for calculating process

CO2from the liquid alkaline feedstock production process.

One commenter using this production method recommended that the appropriate method for calculating emissions from this process would be an annual performance test and described the appropriate parameters that would be measured during the annual performance test to establish an emission factor for calculating annual emissions based on concentration of the CO2in the evaporated stripped mine water and the annual flow from the mine water stripper/evaporator.

Response: We agree that the final rule should address process

CO2emissions generated from this relatively new alternative production process which produces soda ash from liquid alkaline feedstock or mine water. From additional information provided by the commenter, process CO2emissions from this production method are likely to be significant and exceed 25,000 metric tons

CO2e. This process is currently used by a single company, but could become more widespread within the industry in the future as it makes more efficient use of raw materials previously not used. We have updated all sections of 40 CFR part 98, subpart CC for calculating, monitoring and QA/QC, and reporting of process

CO2emissions specific to production of soda ash from liquid alkaline feedstock or minewater. We added procedures for developing site-specific emission factor based on an annual performance test consistent with the recommendations provided by the commenter.

Comment: One commenter noted that using the total alkalinity of either trona or soda ash as prescribed in Equations CC-2 and CC-3 is inappropriate given that the ratio of carbon dioxide to carbon is a factor in the equations. The equations' results artificially inflated the CO2level by 3.67 times the actual amount.

Response: Upon further review, we agree with the commenter's analysis that the ratio 44/12 will overestimate emissions and have removed this fraction, which is the ratio of carbon dioxide to carbon, from Equations CC-2 and CC-3. Equations CC-2 and CC-3

Page 56332

provide results directly for CO2therefore it is not necessary to use a conversion factor to convert the carbon to carbon dioxide.

Comment: One commenter noted that Equation CC-3 does not address plant inefficiency specific to each manufacturing line. The commenter suggested that an efficiency factor should be added to Equations CC-3 to account for these inefficiencies.

Response: The commenter has not suggested an efficiency factor or otherwise provided data with enough specificity to modify the equations and modify the calculation methods as suggested; therefore, we have decided not to add efficiency factors to Equations CC-3.

EPA needs more information to effectively evaluate this comment and update the equations noted, if appropriate. Efficiency factors can relate to a number of factors including combustion and also kiln conditions, which may vary. We need more information to understand how this factor would be derived for each kiln or manufacturing line. The comment was specific to CC-3, and we suggest the use of Equation CC-2 as an alternative calculation method.

Monitoring and QA/QC Requirements

Comment: One commenter stated that daily sampling of inorganic carbon content of each manufacturing line is an unnecessary and potentially extremely costly requirement. They suggested that instead of daily testing, testing should be completed as a weekly composite analysis which would then be used in calculating the monthly average.

Response: We concur that testing of the inorganic carbon content can be done on a weekly schedule and used to calculate a monthly composite without significant loss in accuracy. The weekly composite would still be based on several daily tests. We have updated the monitoring and QA/QC requirements accordingly in the rule under 40 CFR 98.294.

Comment: One commenter stated that the prescribed ASTM method, ASTM

E359-00(2005), for determining the inorganic carbon content of trona or soda ash describes a manual titration method using a methyl orange endpoint. They stated that procedures that use autotitrators with fixed endpoint titration are commonly used in the soda ash manufacturing industry and should be allowed as an acceptable equivalent alternative.

Response: We agree that methods using autotitration to determine inorganic carbon content of trona or soda ash expressed as total alkalinity are acceptable equivalent methods for determining the inorganic carbon content of trona or soda ash. We understand that manual titration offers good levels of accuracy but are labor and time intensive. From our understanding, autotitration methods provide comparable or improved levels of accuracy and are less labor and time intensive by ``automating'' the analysis process. Autotitration methods could provide more consistency in results across the industry. We have updated the procedures in 40 CFR 98.294 for monitoring and QA/QC in the rule to allow for such comparable methods.

DD. Sulfur Hexafluoride (SF6) From Electrical Equipment

At this time EPA is not going final with the electrical equipment subpart. As we consider next steps, we will be reviewing the public comments and the relevant information.

Based on careful review of comments received on the preamble, rule, and TSDs under 40 CFR part 98, subpart DD, EPA will perform additional analysis and evaluate a range of data collection procedures and methodologies. EPA's goal is to optimize methods of data collection to ensure data accuracy while considering industry burden. In addition,

EPA will further evaluate the scope of coverage of electric power systems and the reporting boundaries in other subparts.

EE. Titanium Dioxide Production 1. Summary of the Final Rule

Source Category Definition. The titanium dioxide production source category consists of any facility that uses the chloride process to produce titanium dioxide.

Reporters must submit annual GHG reports for facilities that meet the applicability criteria in the General Provisions (40 CFR 98.2) summarized in Section II.A of this preamble.

GHGs to Report. For titanium dioxide production, report

CO2process emissions from each chloride process line.

In addition, report GHG emissions for other source categories for which calculation methods are provided in the rule, as applicable. For example, facilities must report CO2, N2O, and

CH4emissions from each stationary combustion unit on site under 40 CFR part 98, subpart C (General Stationary Fuel Combustion

Sources).

GHG Emissions Calculation and Monitoring. Reporters must calculate

CO2process emissions using one of two methods, as appropriate:

Most reporters can elect to calculate and report process

CO2emissions from titanium dioxide process lines by either

(1) installing and operating CEMS and following the Tier 4 methodology

(in 40 CFR part 98, subpart C) or (2) using the calculation procedures specified below.

However, if process CO2emissions from titanium dioxide production are emitted through the same stack as a combustion unit or process equipment that uses a CEMS and follows Tier 4 methodology to report CO2emissions, then the reporter must use the CEMS to measure and report combined CO2emissions from that stack instead of using the calculation procedures described below.

If using approach 2, calculate the process

CO2emissions using the equation provided 40 CFR part 98, subpart EE and monthly determination of the mass and carbon content of calcined petroleum coke consumed in each line and all lines combined.

Determine petroleum coke consumption by either direct measurement or purchase records. Determine carbon content of petroleum coke using supplier data or measurement using appropriate test methods. If applicable, also determine the quantity of carbon containing waste generated and its carbon contents using direct measurement.

Data Reporting. In addition to the information required to be reported by the General Provisions (40 CFR 98.3(c)) and summarized in

Recordkeeping. In addition to the records required by the General

Response to Public Comments, Subpart EE: Titanium Dioxide Production.''

Requirements were added for reporting of carbon-containing waste generated from less than 100 percent oxidation of coke during the titanium production process. 40 CFR 98.316

Page 56333

allows for reporting of quantity of carbon-containing waste generated and associated carbon contents.

Missing data procedures were added under 40 CFR 98.315 for monthly parameters used to calculate emissions, including mass of calcined petroleum coke, mass of carbon-containing waste, and carbon contents of calcined petroleum coke. 40 CFR 98.316 was reorganized and updated to improve the emissions verification process. Some data elements were moved from 40

CFR 98.317 to 40 CFR 98.316, and some data elements that a reporter must already use to calculate GHGs as specified in 40 CFR 98.313 were added to 40 CFR 98.316 for clarity. 3. Summary of Comments and Responses

This section contains a brief summary of major comments and responses. We received three sets of comments on titanium dioxide production covering several topics. Several of these comments were directed at the requirements for General Stationary Fuel Combustion

Sources in subpart C, and responses to those comments are provided in the preamble section dealing with that source category. Responses to significant comments received can be found in ``Mandatory Greenhouse

Gas Reporting Rule: EPA's Response to Public Comments, Subpart EE:

Titanium Dioxide Production.''

Method for Calculating GHG Emissions

Comment: One commenter noted that the carbon oxidation factor for calcined petroleum coke is not always 100 percent. They point out that the calcined petroleum coke comes with impurities, and a certain amount of the calcined coke is returned to the ground as landfill along with components such as the un-converted TiO2. Thus, they suggest that EPA should revise the carbon oxidation factor to allow facilities to use the most appropriate factor for their process, with supporting documentation of its derivation available for EPA review as needed.

Response: EPA has considered the comment but maintains the assumption of 100 percent oxidation across all sectors in the final rule. Data reporting requirements have been added to 40 CFR 98.316 to collect information on the quantity of carbon-containing waste generated that is landfilled and its carbon contents which are not emitted. This information will help inform future methods for calculating process emissions from titanium dioxide production (e.g., how to address oxidation rates). EPA interpreted that this comment may also be applicable to carbon content of calcined petroleum coke. EPA agrees that carbon content may not always be 100 percent and therefore has revised the rule to allow facilities to use supplier data or determine carbon contents using appropriate test methods as part of calculating emissions in 40 CFR 98.313.

Procedures for Estimating Missing Data

Comment: Two commenters noted there can be numerous reasons data may not be available, on time, or in the format EPA requires. In cases where a required record is found to be missing or determined to be incorrect, the commenters requested that EPA should provide a procedure for estimating missing data.

Response: We concur that there may be circumstances where data on carbon contents of coke and petroleum coke consumption may be missing.

Records could be misplaced or lost. Thus, we have revised the rule and added specific procedures for estimating missing data in 40 CFR 98.315.

These procedures are consistent with those allowed across the rule for similar parameters. For example, if a facility is missing data on carbon contents of petroleum coke we allow facilities to allow sources to substitute the missing data with another quality assured parameter, such as the arithmetic average of the carbon contents from the month immediately preceding and the month immediately following the missing data incident.

Data Reporting Requirements

Comment: All commenters noted they are concerned that the level of information to be reported, which is considered available for public distribution, could put the domestic TiO2producers at a disadvantage relative to international producers. The commenters do not believe that CBI provisions briefly outlined in the preamble are adequate to safeguard the proprietary technical and financial positions of titanium dioxide production facilities. The annual production of titanium dioxide, annual amount of petroleum coke consumed, and annual operating hours are considered CBI and are unnecessary to carry out the purposes of this proposed regulation. This data should only be available onsite or offsite (e.g., a centralized location), or as requested for security cleared EPA personnel and their security cleared contractors where a need is demonstrated for the purposes of this inventory.

Response: EPA reviewed CBI comments received across the rule (both general and subpart-specific comments) and our response is discussed in

Section II.R of this preamble and in ``Mandatory Greenhouse Gas

Reporting Rule: EPA's Response to Public Comments, Legal Issues.''

In addition, see the Section II.N of this preamble for the response on the emissions verification approach. The amount of petroleum coke consumed is necessary to calculate annual process CO2 emissions. Production capacity and annual production of titanium dioxide are required for EPA to verify annual CO2process emissions. These parameters help EPA to determine whether reported emissions are within a reasonable range. EPA concurs that data on operating hours can be retained as a record and does not need to be reported to EPA. It is not a parameter used in calculating process

CO2emissions. However, operating hours would help to verify any anomalies in reported emissions or supporting parameters related to temporary closures for repairs or maintenance. This data has been moved to recordkeeping requirements in 40 CFR 98.317.

FF. Underground Coal Mines

At this time, EPA is not finalizing the Underground Coal Mines

Subpart (40 CFR part 98, subpart FF). As EPA considers next steps, we will be reviewing the public comments on the proposal preamble, rule and TSDs for proposed 40 CFR 98 Subpart FF and other relevant information. EPA will perform additional analysis and consider alternatives to the monitoring requirements.

GG. Zinc Production 1. Summary of the Final Rule

Source Category Definition. Zinc production facilities consist of zinc smelters and secondary zinc recycling facilities.

Reporters must submit annual GHG reports for facilities that meet the applicability criteria in the General Provisions (40 CFR 98.2) summarized in Section II.A of this preamble.

GHGs to Report. For zinc production, report the following:

CO2process emissions from each Waelz kiln and electrothermic furnace used for zinc production.

CO2, N2O, and CH4 combustion emissions from each Waelz kiln and each other stationary combustion unit on site under 40 CFR part 98, subpart C (General

Stationary Fuel Combustion Sources).

In addition, report GHG emissions for other source categories at the facility for which calculation methods are provided in the rule, as applicable.

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GHG Emissions Calculation and Monitoring. Facilities must calculate

CO2process emissions using one of two methods, as appropriate:

Most reporters can elect to calculate and report process

CO2emissions from each Waelz kiln and electrothermic furnace by either (1) installing and operating CEMS and following the

Tier 4 methodology (in 40 CFR part 98, subpart C) or (2) using the calculation procedures specified in the rule.

However, if process CO2emissions from a Waelz kiln or electrothermic furnace are emitted through the same stack as a combustion unit or process equipment that uses a CEMS and follows Tier 4 methodology to report CO2emissions, then the CEMS must be used to measure and report combined CO2emissions from that stack, instead of the calculation procedure described below.

If using approach 2, calculate process

CO2emissions by determining on an annual basis the total mass (metric tons) of carbon-containing input materials (i.e., zinc- bearing material, flux, electrodes, and any other carbonaceous materials) introduced into each kiln and furnace and the carbon content of each material. Determine carbon content annually either by using supplier data, or by direct measurement using appropriate test methods.

Data Reporting. In addition to the information required to be reported by the General Provisions (40 CFR 98.3(c)) and summarized in

Recordkeeping. In addition to the records required by the General

The major changes since proposal are identified in the following list. The rationale for these changes can be found below.

The carbon input method was revised to require an annual analysis of all process inputs and outputs for carbon content rather than monthly sampling and monthly analysis.

A de minimis was added to exclude accounting for carbon- containing materials contributing less than one percent of the total carbon into Waelz kiln or electrothermic furnaces. These materials do not need to be included in carbon mass balance calculations. 40 CFR 98.336 was reorganized and updated to improve the emissions verification process. Some data elements were moved from 40

CFR 98.337 to 40 CFR 98.336, and some data elements that a reporter must already use to calculate GHGs as specified in 40 CFR 98.333 were added to 40 CFR 98.336 for clarity. 3. Summary of Comments and Responses

No comments specific to regulation of the zinc production sector were received. We revised the frequency of sampling and analysis of carbon contents for carbon containing input materials from monthly to annual consistent with revisions made in response to comments for similar production processes (e.g., emissions from metal production, see the preamble Section III.Q for iron and steel for specific responses to comments). These revisions reduce the reporting burden for zinc production facilities. We understand that the carbon content of material inputs does not vary widely at a given facility for the significant process inputs that contain carbon, and we continue to account for variations due to changes in production rate, which is likely a more significant source of variability.

HH. Municipal Solid Waste Landfills 1. Summary of the Final Rule

Source Category Definition. This source category consists of municipal solid waste (MSW) landfills that accepted waste on or after

January 1, 1980. The source category includes the MSW landfill, landfill gas collection systems, and landfill gas destruction devices

(including flares) at the landfill.

This source category does not include hazardous waste, construction and demolition, or industrial landfills.

Reporters must submit annual GHG reports for facilities that meet the applicability criteria in the General Provisions (40 CFR 98.2) summarized in Section II.A of this preamble.

GHGs to Report. For MSW landfills, report the following:

Annual CH4generation and CH4 emissions from the landfill.

Annual CH4destruction (for landfills with gas collection and control systems).

Annual CO2, CH4, and N2O emissions from stationary fuel combustion devices under 40 CFR part 98, subpart C (General Stationary Combustion Sources).

GHG Emissions Calculation and Monitoring. All facilities must calculate modeled annual CH4generation based on:

Measured or estimated values of historic annual waste disposal quantities; and

Appropriate values for model inputs (i.e., degradable organic carbon fraction in the waste, CH4generation rate constant). Default parameter values are specified for bulk municipal waste and individual waste categories.

Facilities that do not collect and destroy landfill gas must adjust the modeled annual CH4generation to account for soil oxidation (CH4that is converted to CO2as it passes through the landfill cover before being emitted) using a default soil oxidation factor. The resulting value must be reported and represents both CH4generation and CH4emissions.

Facilities that collect and control landfill gas must calculate the annual quantity of CH4recovered and destroyed based on either continuous or weekly monitoring of landfill gas flow rate,

CH4concentration, temperature, and pressure of the collected gas prior to the destruction device.

Those facilities that collect and control landfill gas must then calculate CH4emissions in two ways and report both results.

Emissions must be calculated by: 1. Subtracting the measured amount of CH4recovered from the modeled annual CH4generation (with adjustments for soil oxidation using the default value and destruction efficiency of the destruction device) using the equations provided; and 2. Applying a gas collection efficiency to the measured amount of

CH4recovered to calculate CH4generation, then subtracting the measured amount of CH4recovered (with adjustments for soil oxidation using the default value and destruction efficiency of the destruction device) using the equations provided.

Default collection efficiencies are specified, based on cover material and other factors.

Data Reporting. In addition to the information required to be reported by the General Provisions (40 CFR 98.3(c)) and summarized in

Recordkeeping. In addition to the records required by the General

Provisions (40 CFR 98.3(g)) and

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summarized in Section II.A of this preamble, reporters must keep records of additional data used to calculate GHG emissions. A list of specific records that must be retained for this source category is included in 40 CFR part 98, subpart HH. 2. Summary of Major Changes Since Proposal

The major changes since proposal are identified in the following list. The rationale for these and any other significant changes can be founds below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's

Response to Public Comments, Subpart HH: Landfills.''

Industrial landfills were removed from the applicability provisions of 40 CFR part 98, subpart HH. The applicability provisions were also modified to exempt landfills that did not accept any waste after January 1, 1980.

Additional methods for estimating quantities of waste for prior (historic) years are provided.

The requirement to continuously monitor CH4 composition in the flare gas was removed. If a continuous monitoring system is in place, that data must be used, but weekly sampling of the gas is allowed if such a continuous system is not in place.

Direct flame ionization methods were added to the rule as an alternative to the gas chromatographic methods for determining methane concentrations. To use a direct flame ionization method, a correction factor must be determined at least once each reporting year and applied to adjust the analyzer's total gaseous organic concentration to an unbiased methane concentration.

More detailed default values are provided for landfill gas collection efficiencies based on cover material and other factors. 3. Summary of Comments and Responses

This section contains a brief summary of major comments and responses. A large number of comments on landfills were received covering numerous topics. Responses to significant comments received can be found in ``Mandatory Greenhouse Gas Reporting Rule: EPA's

Response to Public Comments, Subpart HH: Landfills.''

Definition of Source Category

Comment: Several commenters stated that EPA should limit the applicability of the industrial landfills to landfills located at food processing, pulp and paper, and ethanol production facilities (some also listed petroleum refineries) because these are the only industries for which landfills were specifically called out. Several commenters noted that impacts were only estimated for pulp and paper and food processing landfills, so EPA should limit the rule to those industries or correct the cost analysis to reflect the true burden of the rule on industrial landfills. Several commenters noted that the reporting requirements seemed tailored for MSW landfills and were generally inappropriate for industrial landfills (truck scales, etc.). One commenter also noted that, if reporting of GHG emissions from industrial landfills is not limited to the food processing, pulp and paper, and ethanol production facilities, then EPA should amend Table

HH-1 of 40 CFR part 98, subpart HH and provide specific factors that are relevant to the regulated industry. Several commenters requested that EPA specifically exempt inorganic chemical manufacturing and mining landfills because they do not contain organic waste; other commenters suggested EPA delete requirements for landfills in 40 CFR part 98, subpart Y because landfills are insignificant compared to other sources at a petroleum refinery.

On the other hand, one commenter suggested that EPA may be overlooking an important source of methane emissions by excluding construction and demolition landfills as it seems possible that these landfills receive organic materials such as wood or yard waste that could degrade in an anaerobic environment. This commenter requested EPA provide information on the waste composition of construction and demolition landfills to explain more fully the basis for its decision to categorically exempt these sources from GHG reporting requirements.

Response: At this time, EPA is not going final with the industrial landfills proposed requirements of this subpart. In response to the proposal, EPA received numerous detailed public comments on the preamble, rule and TSDs under 40 CFR part 98, subpart HH. Comments addressed the appropriateness, coverage, and methodology for addressing

GHG emissions from industrial landfills. In particular, commenters questioned which industrial landfills should be covered by the rule and the need for industry specific factors and methodologies for calculating and reporting emissions. As EPA considers next steps, we will be reviewing the comments and other relevant information and will perform additional analysis and consider alternatives to the proposed monitoring and reporting requirements for industrial landfills.

With regard to construction and demolition landfills, we note that the IPCC 2006 Guidelines for National Greenhouse Gas Inventories estimates that construction and demolition waste has a degradable organic content (DOC) of 0.04 kg/kg waste (see Table 2.5 in Volume 5:

Waste), and most of this organic matter is expected to be wood, with slow degradation rates (k=0.02 yr-1). Based on the anticipated properties of construction and demolition wastes, we anticipated that methane generation at dedicated construction and demolition debris landfills would be small compared to MSW landfills.

We will further review these assumptions as we review comments on industrial landfills.

Comment: Several commenters stated that the reporting requirements for closed landfills are burdensome, and the rule should be limited to reporting for active landfills. Information on waste disposal quantities and waste composition data are usually not available for closed MSW facilities. Thus, it is impossible to retain or provide the agency with such records for many old landfill sites. Several commenters suggested that EPA should provide additional guidance and screening tools to identify landfills likely to be below the threshold.

The commenters noted that small and closed landfills have to collect all of the data needed to report their emissions in order to determine if they are above the reporting threshold.

Response: Closed MSW landfills account for approximately half of the nationwide methane emissions from MSW landfills. This is because landfills can continue to emit for decades after they are closed and because these landfills are older, and less likely to have been required to add landfill gas collection systems. However, we do agree that we can remove reporting requirements for a subset of closed landfills to lessen the burden on long-closed landfill facilities. We evaluated the various landfill characteristics and identified that a 30-year waste-in-place (i.e., the total quantity of waste added to the landfill in the past 30 years) provided the best correlation of the data to sites that account for the majority of the contribution to the nationwide GHG emissions from landfills (see memorandum entitled

``Correlations with Landfill Methane Generation and Actual Emissions'' in the docket EPA-HQ-OAR-2008-0508-2165). Providing an applicability date for closed landfills is essential to minimize the burden associated with obtaining data on old landfills that provide only a small contribution to the nationwide GHG

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emissions for landfills, and landfills closed prior to 1980 would not be relevant for the purposes of policy analyses. Therefore, the final rule excludes MSW landfills that have not accepted waste since January 1, 1980. We have also expanded and clarified options for projecting waste disposal quantities that will help ease the burden associated with calculating emissions from landfills that have closed after 1980.

EPA remains committed to providing additional outreach materials, guidelines, and screening tools to help potential reporters determine whether the reporting rule applies to their landfill.

Method for Calculating GHG Emissions

Comment: Several commenters requested additional guidance on how to determine waste disposal rates for years prior to the first reporting year. One commenter noted that the population method provided in the rule was difficult for many landfills because of contract carriers that may haul waste to different landfills in different years, so that the population served by a landfill can be variable. Several commenters noted that the data needed to estimate waste disposal rates for past years was especially challenging for closed landfills and requested guidance on how to comply with the rule if the necessary data do not exist.

Response: EPA acknowledges that the single proposed method of estimating past year disposal rates is limiting and may not provide the most accurate projection of waste disposal rates in all cases. We have provided a number of alternative approaches that could be used to estimate annual waste acceptance rates. These include using the current year's annual waste acceptance rate for all past years of operation

(for active landfills) and using the landfill capacity and the operating life of the landfill to calculate an average annual acceptance rate (for active and closed landfills). These methods provide a reasonable estimate of historic disposal quantities based on readily available information, even for older landfills. Furthermore, these alternative methods may be just as appropriate or more appropriate for MSW landfills that do not serve a fixed population area.

Comment: A few commenters noted that the Solid Waste Industry for

Climate Solution (SWICS) has developed protocols for calculating GHG emissions from landfills [see paper titled, Current MSW Industry

Position and State-of-the-Practice on LFG Collection Efficiency,

Methane Oxidation, and Carbon Sequestration in Landfills (July 2007)].

The commenters requested that the SWICS recommended defaults for gas recovery system efficiency, soil oxidation, and flare combustion efficiency be provided in the rule. They also stated that an accurate inventory should account for carbon sequestered in the landfill.

Response: We again reviewed the SWICS methods in light of these comments. We agree that the SWICS default recommendations for gas recovery system efficiency (which vary from 60 to 95 percent for different types of soil covers) could provide more refined data than using the default values provided in the rule. Therefore, we have included these cover-specific gas recovery efficiencies (commensurate with the SWICS Protocol) as an alternative to the 75 percent default value for collection efficiency. We have also reviewed the SWICS protocol for soil oxidation, which provides suggested oxidation factors ranging from 0.22 to 0.55 depending on the soil cover type. We have several concerns with these factors. First, the values were calculated using arithmetic means which appear to be biased high due to a few high oxidation factors; the median values were generally significantly lower than the average values suggested. Second, the recommended values included laboratory test values, which always yielded higher oxidation fractions. The percent of methane oxidized at the landfill surface is highly dependent on the velocity of gas flow. While areas of low flow are expected to have significant oxidation, areas of high flow will have little to no oxidation. Landfill gas will generally flow to the surface in fissures and channels that offer the least resistance to flow. Consequently, a significant portion of the landfill gas is likely to exit the landfill in a limited number of areas under much higher flow rates than other locations. These high volume flows will not have significant oxidation. Consequently, field test data tend to show lower oxidation factors than laboratory tests where flow is more uniform.

Data for five field studies for clay covers (the predominant soil cover type used in the U.S.) were included in the SWICS report. Four of the five field studies had oxidation factors ranging from 0.08 to 0.21, and the median of all five field studies was 0.14. These data appear to support the default 0.10 oxidation factor as provided in the final rule more than they do the 0.22 oxidation factor suggested by SWICS. We will continue to assess the available data to improve soil oxidation estimates; however, we maintain that the use of the 10 percent default rate is appropriate for this final rule, and clarify that the site- specific oxidation factors (based on the SWICS method or other method) are not to be used. We also find that the SWICS Protocol recommended flare efficiency of 99.996 percent appears unreasonably high. The combustion efficiency of flares is very difficult to assess and may be affected by wind speed and other variables that are not under the direct control of the landfill owner and operator. Consequently, we retained the proposed flare efficiency default. Finally, with respect to the suggested sequestration factors, since collecting data on carbon sequestration is not the purpose of this rule, we do not require facilities to calculate or report carbon storage in landfills.

Monitoring and QA/QC Requirements

Comment: Several commenters stated that EPA's proposal to require landfills with gas collection systems to continuously measure the methane flow and concentration at the flare or energy device is financially burdensome. According to commenters, the capital costs as well as operation and maintenance costs of a continuous composition analyzer are prohibitive for many facilities, and EPA underestimated the number of facilities that would have to install the required monitors. The commenters also stated that the composition of landfill gas is not highly variable, so less frequent monitoring is justified.

One commenter noted that the standard operating procedure at many landfills with gas collection systems is to collect monthly

CH4, flow, and concentration data at the flare. Another commenter recommended that MSW landfills be allowed to calculate quarterly, by means of engineering formulae and/or modeling, the amount of methane present at the flare or energy device. The commenter further noted that, in many cases, it is not practical or even possible for the

MSW facility to measure the amount of methane or even landfill gas at the energy device because this device is not owned, operated, or controlled by the facility. Several commenters also requested that EPA allow direct flame ionization analyzers in addition to the gas chromatography methods provided in the proposed rule.

On the other hand, several commenters suggested that EPA should allow, require, or otherwise move towards direct measurement methodologies for characterizing landfill emissions.

Response: Methane composition of landfill gas can be expected to vary

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based on extreme barometric changes, rainfall event, etc. We expect diurnal variations as well (although not to the same extent as seasonal variations). We also expect variations if the gas collection system has a variable speed fan and the fan speed is adjusted. The commenters provided no data to support the claim that the anticipated fluctuations are not significant enough to warrant continuous monitoring. At proposal, we required continuous flow and composition monitors to improve the accuracy of the emissions estimate. However, after additional uncertainty analysis, we determined that the cost of continuous monitoring systems is not justified in relation to the relatively small improvement in certainty over somewhat less frequent monitoring, i.e. weekly. We do require landfill gas collection systems already equipped with continuous monitoring systems to determine daily average flow and concentrations and to use these data in their gas recovery calculations. For collection systems that do not have continuous gas monitors, weekly sampling is required. Weekly monitoring provides an adequate number of samples to evaluate the variability and uncertainty associated with methane generation. We did not select monthly monitoring because monthly monitoring would result in greater uncertainty and would not significantly reduce the costs compared to weekly monitoring.

We did provide for direct flame ionization analyzers to be used as an alternative to the gas chromatography methods provided in the proposed rule. This alternative reduces the burden on landfills that do not have existing gas chromatography equipment. However, direct flame ionization analyzers will measure both methane and non-methane organic compounds and, as such, will tend to overstate the methane concentration in the landfill gas and provide a high bias to the amount of methane recovered. To eliminate this bias, we also required a correction factor that must be determined at least annually, to arrive at the ratio of the methane concentration to the direct flame ionization analyzer response (calibrated with methane). Including this alternative method with the correction factor reduces the burden on landfills, but still ensures that the calculated methane recovery quantities are unbiased and comparable to the recovery quantities calculated when gas chromatographic methods are used to speciate methane specifically.

With respect to direct measurement methods, we find that direct soil measurements have high uncertainties due to heterogeneity of the landfill and cover soils and are, therefore, less desirable than the methods provided in the rule (cost more and have higher uncertainty).

Optical sensing methods, while potentially more accurate, are very expensive. If measurements were done for only a one-time performance test, the measured emissions would have rather high uncertainties due to variations in temperature and atmospheric pressure. If the measurements were conducted more often, they would be prohibitively expensive. At this time, we cannot justify requiring these types of monitoring systems for this rule. Furthermore, we find that the monitoring requirements in the final rule provide for accurate emission estimates at a reasonable cost burden to reporters.

II. Wastewater Treatment

At this time, EPA is not going final with the wastewater treatment subpart (40 CFR part 98, subpart II). As EPA considers next steps, we will be reviewing the public comments and other relevant information.

Please note, as originally proposed for this rule, centralized domestic wastewater treatment plants continue to be excluded.

The Agency received a number of comments regarding the applicability of this subpart as well as clarification of the definition of anaerobic wastewater treatment processes. In addition, commenters requested that EPA consider a de minimus exemption for emissions from wastewater treatment. The Agency also received a number of comments requesting redefinition of the monitoring requirements for this subpart.

Based on careful review of comments received on the preamble, rule and TSDs under proposed 40 CFR part 98, subpart II, EPA will consider alternatives to data collection procedures and methodologies and examine additional study results that have been released since the proposal was issued. Specifically, EPA will consider requirements for the location of meters for taking flow measurements, the frequency of flow and chemical oxygen demand (COD) measurements taken, as well as the potential use of alternate parameters, such as BOD. EPA will also consider the inclusion of indirect or non-methane volatile organic compound emissions. Lastly, EPA will consider the acceptable methods for estimating missing data. EPA will consider optimal methods of data collection in order to maximize data accuracy, while considering industry burden.

JJ. Manure Management 1. Summary of the Final Rule

Source Category Definition. A livestock facility that emits 25,000 metric tons CO2e or more per year from manure management systems must report. A facility with an average annual animal population below those listed in Table JJ-1 of 40 CFR part 98, subpart

JJ, does not need to calculate emissions or report. A facility with an average annual animal population that exceeds those listed in Table JJ- 1 should conduct a more thorough analysis to determine applicability.

Average annual animal populations for static populations (e.g., dairy cows, breeding swine, layers) are estimated by performing an animal inventory or review of facility records. Average annual animal populations for growing populations (meat animals such as beef and veal cattle, market swine, broilers, and turkeys) are estimated using the average number of days each animal is kept at the facility and the number of animals produced annually. The rule also contains procedures for facilities with more than one animal group present (e.g., swine and poultry) to determine if they must report.

A manure management system stabilizes or stores livestock manure, or does both, in one or more of the following system components:

Uncovered anaerobic lagoons.

Liquid/slurry systems with and without crust covers

(including but not limited to ponds and tanks).

Storage pits.

Digesters, including covered anaerobic lagoons.

Solid manure storage.

Drylots, including feedlots.

High-rise houses for poultry production (poultry without litter).

Poultry production with litter.

Deep bedding systems for cattle and swine.

Manure composting.

Aerobic treatment.

GHG emissions from sources at livestock facilities unrelated to the stabilization and/or storage of manure are not covered under this rule and are not reported. Sources considered to be unrelated to the stabilization and/or storage of manure include daily spread or pasture/ range/paddock systems or land application activities or other methods of manure utilization not listed above. In addition, manure management activities located off site from a livestock operation are not included in this rule. These off site activities include but are not limited to off site

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land application of manure, other off site methods of manure utilization, or off site manure composting operations.

Facilities that meet the applicability criteria in the General

Provisions (40 CFR 98.2) summarized in Section II.A of this preamble must report GHG emissions.

GHGs to Report. For all livestock facilities with a manure management system that meets or exceeds the reporting threshold, the facility must report aggregate CH4and N2O emissions from the system components listed above. For those manure management systems that include digesters, CH4generated and destroyed, as well as any CH4leakage, at the digester must also be reported.

A facility that is subject to this rule only because of emissions from manure management systems is not required to report emissions under 40 CFR part 98 subparts C through PP other than subpart JJ.

GHG Emissions Calculation and Monitoring. Detailed methods for calculating GHG emissions are included in the rule and are briefly described below. For each manure management system component other than digesters, facilities must calculate emissions using the following inputs and data:

Type of system component.

Average annual animal population (by animal type) contributing manure to the manure management system component.

Typical animal mass (for each animal type).

Fraction of manure by weight for each animal type managed in each system component (assumed to be equal to the fraction of volatile solids/nitrogen handled in each system component).

Volatile solids excretion rates provided in look-up tables for the animal populations contributing manure to the manure management system component.

Maximum CH4-producing potential of the managed manure and CH4conversion factors provided in look-up tables for the animal populations contributing manure to the manure management system component.

Methane conversion factor used (for each manure management system component).

Nitrogen excretion rates (by animal type) using values provided in look-up tables for the animal populations contributing manure to the manure management system component.

N2O emission factors (by animal type) provided in look-up tables for the animal populations contributing manure to the manure management system component.

For anaerobic digesters, facilities must calculate CH4 emissions and the annual mass of CH4generated and destroyed based on the following inputs and data:

Continuous monitoring of CH4concentration, flow rate, temperature, and pressure of the digester gas.

CH4destruction efficiency of the destruction device and fugitive (leakage) emissions.

The CH4collection efficiency(ies) used (for each digester).

Data Reporting. In addition to the information required to be reported by the General Provisions (40 CFR 98.3(c)) and summarized in

Section II.A of this preamble, facilities must submit additional data that are used to calculate GHG emissions. A list of the specific data to be reported for this source category is contained in 40 CFR part 98, subpart JJ.

Recordkeeping. In addition to the records required by the General

Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this preamble, facilities must keep records of additional data used to calculate GHG emissions. A list of specific records that must be retained for this source category is included in 40 CFR part 98, subpart JJ. 2. Summary of Major Changes Since Proposal

The major changes since proposal are identified below. The rationale for these and any other significant changes can be found below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's Response to Public Comments, Subpart JJ: Manure Management.''

To assist facilities in determining if they are subject to this rule, a table has been provided that presents average annual animal population values for specific livestock operations (i.e., beef, dairy, swine, and poultry). Facilities that have average annual animal population values below those shown in the table will not be required to report or complete the calculations to determine whether they need to report.

Since proposal, the requirements for monthly manure sampling to determine volatile solids (VS) and nitrogen (N) content have been removed. Instead of obtaining VS and N content from manure sampling, facilities must use default VS and N excretion values as provided by EPA in look up tables. The default VS and N excretion values are consistent with the 1990-2008 U.S. GHG inventory for manure management and enteric fermentation. For beef and dairy cows, heifers, and steers, VS and N excretion rates were calculated using the IPCC

Tier II methodology, based on the relationship between animal performance characteristics such as diet, lactation, and weight gain and energy utilization. In response to comments, EPA used the most up- to-date information on U.S. animal diets to calculate these excretion rates. For other animal groups, reference values from ASAE and USDA are used.

EPA has also adjusted the calculations for CH4 and N2O emissions from manure management systems to account for volatile solids and nitrogen removal through solid separation. If solid separation occurs prior to the manure management system component, facilities must use default removal efficiencies as provided by EPA in look up tables. The default values are consistent with those cited in the ``Development Document for the Final Revisions to the

National Pollutant Discharge Elimination System Regulation and the

Effluent Guidelines for Concentrated Animal Feeding Operations'' (EPA- 821-R-03-001), published in December 2002. 3. Summary of Comments and Responses

This section contains a brief summary of major comments and responses. A large number of comments on manure management were received covering numerous topics. Responses to significant comments received can be found in the comment response document for manure management in ``Mandatory Greenhouse Gas Reporting Rule: EPA's Response to Public Comments, Subpart JJ: Manure Management.''

Comment: A number of commenters supported EPA's decision to include livestock facilities with manure management systems in the proposed rule. These commenters noted that the establishment of a mandatory GHG reporting rule is the next logical step in reducing and mitigating GHG emissions in the U.S., and that manure management is a significant source of GHG emissions in the U.S. that should be addressed.

However, other commenters stated that livestock facilities should not be required to report GHG emissions. These commenters noted that a small number of facilities would be covered by the proposed rule, and these facilities would represent a very small percentage of the total number of livestock facilities in the U.S. which would not provide a large enough set of data to help improve or reduce uncertainties associated with GHG inventories. Several of the commenters stated that manure management is not a major source of GHG emissions in the U.S., and the environmental benefits from the rule

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would be minimal compared to the effort required to report emissions.

Response: EPA disagrees that the manure management source category be excluded from this rule. Manure management has been determined to be a key source of GHG emissions in the U.S., based on the key source category methodology developed by the Intergovernmental Panel on

Climate Change (IPCC). The IPCC identifies key sources as those sources that have significant impacts on the total emissions or emission trends in a country.

While livestock manure GHG emissions represent a relatively small fraction of the total U.S. GHG emissions, these emissions are large in absolute terms. According to the 2009 U.S. GHG Inventory,

CH4emissions from manure management systems totaled 44 million metric tons CO2e, and N2O emissions were 14.7 million metric tons CO2e in 2007; manure management systems account for 7.5 percent of total anthropogenic CH4 emissions and 4.7 percent of N2O emissions in the U.S.

In addition, the collection of facility level GHG emission data, including the type of manure management systems in operation and the number and types of animals serviced by those systems, will help to inform future climate change policy decisions. While the actual number of facilities reporting will be quite small in comparison to the total number of facilities in the U.S., the data gathered through this effort is valuable. For example, these data will help to improve the understanding of emission rates and actions that facilities take to reduce emissions and may improve the effectiveness and design of voluntary and/or mandatory programs to reduce emissions.

Comment: Multiple commenters stated that the monitoring requirements in the proposed rule would be too burdensome and expensive for industry to comply with. These commenters expressed concern that sampling manure for VS and N would require more time and effort and be more expensive than EPA estimated. Multiple commenters suggested that default values such as from the American Society of Agricultural and

Biological Engineers (ASABE) be permitted for VS and N instead of measured values to eliminate some of the expense associated with the proposed rule.

In addition, a number of commenters noted that there were some methodological issues associated with the monitoring requirements for

VS and N. Multiple commenters noted that the requirements for manure sampling should be clarified.

Response: EPA acknowledges these concerns and has removed the manure sampling requirements from the final rule. As discussed earlier,

EPA used default values for VS and N excretion from USDA and ASAE for swine and poultry, and has calculated these rates for beef and dairy cows, heifers, and steers using the IPCC Tier II methodology, based on the relationship between animal performance characteristics such as diet, lactation, and weight gain and energy utilization. The use of these animal-specific default values for VS and N will greatly reduce the burden to comply with the reporting rule, while only minimally impacting the estimates of GHG emissions. The variation in sampling techniques from facility to facility when characterizing manure ``as excreted'' from the various animal populations on the facility (as would have been required by the proposal) would negate the benefit derived from this requirement. EPA considered designing a more complex and rigorous program to ensure consistency in the implementation of a manure sampling program and to ensure that manure samples represented

``as excreted'' manure (prior to any storage or treatment). However, after reviewing comments, we determined that the expected burden of such a program, in terms of time, effort, and expense, outweighed the merits at this time.

Comment: A number of commenters noted that calculation errors caused threshold head numbers to be overestimated, which caused the amount of emissions from these operations and the number of operations that would need to report to be underestimated.

Response: To estimate the number of facilities at each threshold,

EPA first developed a number of model facilities to represent the manure management systems that are most common on large livestock operations and have the greatest potential to exceed the GHG reporting threshold. Next, EPA used the U.S. GHG inventory methodology for manure management to estimate the numbers of livestock that would need to be present to exceed the threshold for each model livestock operation type. Finally, EPA combined the numbers of livestock required on each model operation to meet the thresholds with U.S. Department of

Agriculture (USDA) data on farm sizes to determine how many farms in the United States have the livestock populations required to meet the

GHG thresholds for each model livestock operation.

Since proposal, EPA made revisions to the threshold analysis spreadsheet calculations based on information and data provided by commenters. EPA corrected conversion factors used in the nitrous oxide emission calculations, and corrected spreadsheet cell reference errors along with using updated VS and N values. EPA now estimates that there will be approximately 107 livestock facilities that will need to report under the rule.

Comment: Commenters also expressed concerns with the emission calculations. Multiple commenters noted that the maximum methane producing capacity (Bo) values used do not reflect variations in animal diet. Several commenters had concerns about the methodology used to estimate the methane conversion factors. In addition, some commenters suggested that other data sources should be considered, such as the

ASABE manure standards.

Response: After a thorough review of available information, EPA has determined that the methodologies and data sources used to calculate emissions in this rule represent the best available methods and data.

EPA reviewed many protocols and approaches prior to selecting the proposed methodology. EPA's selected methodology for reporting GHG emissions (methane and nitrous oxide) associated with manure management systems is based on EPA's Inventory of U.S. Greenhouse Gas Emissions and Sinks, as well as the IPCC Guidelines for National Greenhouse Gas

Inventories. These methodologies rely on the use of activity data, such as the number of head of livestock, operational characteristics (e.g., physical and chemical characteristics of the manure, type of management system(s)), and climate data, to calculate GHG emissions associated with traditional manure management systems. In addition, the selected methodology for the reporting rule uses measured values for those manure management systems (e.g., anaerobic digesters) that collect and combust biogas.

EPA considered requiring direct measurement of GHG emissions from manure management systems, but rejected this approach due to the extreme expense and complexity of such a measurement program. EPA is promulgating an approach that allows the use of default factors, such as a system emission factor, for certain elements of the calculation, and encourages the use of some site-specific data. The cost of such an approach is significantly lower than a direct measurement program. In addition, this approach is consistent with the methods used in offset programs throughout the world, including the California Climate Action

Registry's (CCAR) Manure

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Management Project Reporting Protocol. For these offset programs, livestock operations are required to complete calculations that establish their ``baseline'' emissions (prior to the use of a biogas collection system). These baseline emission calculations use similar emissions calculations and default values as are in EPA's Reporting

Rule.

The IPCC guidelines have been established by a recognized panel of experts and underwent significant peer review prior to their adoption.

In addition, protocols for offset programs, such as CCAR, have gone through similar public review processes prior to their acceptance and use.

Comment: Multiple commenters have requested more detailed look up tables and a tool to provide more clarity on which facilities are required to report under the final rule.

Response: EPA agrees that additional tables and tools would facilitate compliance with the rule and ease the burden associated with reporting. In response to the comments, EPA has added a threshold table to the final rule (Table JJ-1) to help livestock facilities with manure management systems better determine if they might be subject to the requirements of the rule. EPA also intends to develop applicability tools that can assist facilities that could be covered by the rule, based on table JJ-1 in 450 CFR part 98, subpart JJ, in conducting a more detailed evaluation. These tools will include detailed look-up tables showing the estimated livestock head numbers that would be necessary in order to meet or exceed the threshold and a calculation tool to assist in performing the calculations in the proposed rule.

KK. Suppliers of Coal

At this time, EPA is not going final with a subpart for suppliers of coal. As EPA considers next steps, we will be reviewing the public comments and other relevant information.

The Agency received a number of lengthy, detailed comments regarding the coal suppliers subpart. Commenters generally opposed the proposed reporting requirements and raised multiple issues with EPA's legal authority for requiring coal suppliers to report CO2 emissions. Several commenters stated that reporting by coal suppliers would represent a duplication of the reporting by coal users. For example, electric utilities and industrial plants, which consume the vast majority of coal supplied, are already required to report data on emissions based on their coal purchases. Commenters also stated that the reporting requirement would entail significant burden and capital costs to coal suppliers. In most cases, commenters provided alternative approaches to the reporting requirements proposed by EPA. For example, commenters suggested that EPA exempt from reporting coal mines that supply coal to mine-mouth power plants, modify the required coal weighing and sampling standards, and eliminate the required statistical correlation between HHV and carbon content.

Commenters raised other issues regarding the reporting of data such as concerns that coal suppliers and laboratories could not realistically purchase and install new coal testing and sampling equipment and provide training to meet the requirements of the proposed rule.

Based on careful review of comments received on the preamble, rule and TSDs under proposed 40 CFR part 98, subpart KK, EPA will perform additional analysis and consider alternatives to data collection procedures and methodologies. These alternatives will provide coverage of coal supplied, imported, or exported while concurrently taking into account industry burden.

LL. Suppliers of Coal-Based Liquid Fuels 1. Summary of the Final Rule

Source Category Definition. This source category consists of producers, importers, and exporters of products listed in Table MM-1 of 40 CFR part 98, subpart MM that are coal-based (coal-to-liquid products). A producer of coal-to-liquid products is any owner or operator who converts coal into liquid products (e.g., gasoline, diesel) using the Fischer-Tropsch or an alternative process.

Suppliers of coal-to-liquid products that meet the applicability criteria in the General Provisions (40 CFR 98.2) summarized in Section

II.A of this preamble must report GHG emissions.

GHGs to Report. Suppliers of coal-to-liquid products must report the CO2emissions that would result from the complete combustion or oxidation of the coal-to-liquid products.

Suppliers of coal-to-liquid products are not required to report data on emissions of other GHGs that would result from the complete combustion or oxidation of their products, such as CH4or

N2O.

GHG Emissions Calculation and Monitoring. For each type of coal-to- liquid product, suppliers must calculate CO2emissions that would result from the complete combustion or oxidation of the coal-to- liquid products by following the procedures in 40 CFR 98.393.

Data Reporting. In addition to the information required to be reported by the General Provisions (40 CFR 98.3(c)) and summarized in

Section II.A of this preamble, reporters must submit additional data that are used to calculate GHG emissions that would result from the complete combustion or oxidation of their products. A list of the specific data to be reported for this source category is contained in 40 CFR 98.386.

Recordkeeping. In addition to the records required by the General

Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this preamble, reporters must keep records of additional data used to calculate GHG emissions that would result from the complete combustion or oxidation of their products. A list of specific records that must be retained for this source category is included in 40 CFR 98.387. 2. Summary of Major Changes Since Proposal

The major changes since proposal are identified in the following list. The rationale for these and any other significant changes can be found below.

We replaced the procedures and calculations proposed in 40

CFR part 98, subpart LL with references to the 40 CFR part 98, subpart

MM procedures and calculations. As a result of considerable comment and

EPA analysis, 40 CFR part 98, subpart MM procedures and calculations were significantly updated. Since the procedures and calculations necessary for sampling, testing, and measuring coal-to-liquid products are intrinsically linked to the procedures and calculations used for petroleum products, we concluded that referencing 40 CFR part 98, subpart MM in 40 CFR part 98, subpart LL would achieve consistency and completeness.

We reorganized and updated 40 CFR 98.386 by mirroring 40

CFR 98.396 in order to reflect the updates we made to procedures and calculations and to assist in EPA data verification. 3. Summary of Comments and Responses

EPA did not receive any specific comments on proposed 40 CFR part 98, subpart LL (suppliers of coal-based liquid fuels). Changes made to this subpart were implemented to ensure consistency with changes made to 40 CFR part 98, subpart MM based on public comments provided and EPA analysis conducted.

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MM. Suppliers of Petroleum Products 1. Summary of the Final Rule

Source Category Definition. Suppliers of petroleum products consist of:

Petroleum refineries that produce petroleum products through distillation of crude oil.

Importers who satisfy the same meaning given in 40 CFR 98.6, including any entity that imports petroleum products or NGLs as listed in Table MM-1 of 40 CFR part 98, subpart MM. Any blender or refiner of refined or semi-refined petroleum products shall be considered an importer if it otherwise satisfies the aforementioned definition.

Exporters who satisfy the same meaning given in 40 CFR 98.6, including any entity that exports petroleum products or NGLs as listed in Table MM-1 of 40 CFR part 98, subpart MM. Any blender or refiner of refined or semi-refined petroleum products shall be considered an exporter if it otherwise satisfies the aforementioned definition.

Suppliers of petroleum products that meet the applicability criteria in the General Provisions (40 CFR 98.2) summarized in Section

II.A of this preamble must report GHG emissions that would result from the complete combustion or oxidation of the product(s) they supply.

GHGs to Report. Suppliers of petroleum products must report annually:

CO2emissions that would result from the complete combustion or oxidation of each petroleum product and natural gas liquid produced, used as feedstock, imported, or exported during the calendar year.

CO2emissions that would result from the complete combustion or oxidation of any biomass co-processed with petroleum feedstocks at a refinery.

Suppliers of petroleum products are not required to report data on emissions of other GHGs that would result from the complete combustion or oxidation of their products, such as CH4or

N20.

GHG Emissions Calculation and Monitoring. Suppliers of petroleum products must choose one of two methods to calculate CO2 emissions that would result from the combustion or oxidation of each petroleum product and natural gas liquid:

Method 1: Use the default CO2emission factors provided in the regulations for a given petroleum product or NGL; or

Method 2: Develop an emission factor for a given petroleum product or natural gas liquid using direct measurements of density and carbon share.

To calculate CO2emissions that would result from the combustion or oxidation of biomass co-processed with petroleum feedstock, reporters must use a CO2emission factor that is provided in the regulations for each type of biomass.

In calculating total CO2emissions that would result from the combustion or oxidation of all petroleum products and natural gas liquids that leave the refinery, refineries must subtract the emissions from petroleum products and natural gas liquids that enter the refinery to be further refined or used on site as well as biomass and biomass-based fuels that are co-processed or blended with petroleum feedstocks.

Data Reporting. In addition to the information required to be reported by the General Provisions (40 CFR 98.3(c)) and summarized in

Section II.A of this preamble, reporters must submit additional data used to calculate GHG emissions that would result from the complete combustion or oxidation of the product(s) supplied as well as information on the characteristics of crude oil used at a refinery. The specific list of data to be reported for this source category is contained in 40 CFR part 98.396 and includes information to support the data verification process.

Recordkeeping. In addition to the records required by the General

Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this preamble, reporters must keep records of additional data used to determine the quantities and characteristics of product(s) reported under this subpart and to calculate GHG emissions that would result from the complete combustion or oxidation of the product(s) supplied. A list of specific records that must be retained for this source category is included in 40 CFR part 98.387. 2. Summary of Major Changes Since Proposal

Response to Public Comments, Subpart MM: Suppliers of Petroleum

Products.''

We established a reporting threshold for importers and exporters of 25,000 metric tons of CO2per year.

We changed the source category definition of petroleum refinery for the purposes of 40 CFR part 98, subpart MM to only include facilities that process crude oil. As such, we are not requiring reporting from facilities that only handle intermediary petroleum products.

We refined the definition of importers and exporters of petroleum products to clarify reporting requirements for blenders.

We are not requiring reporters to rely on an exclusive list of standard methods for the measurement of the quantity of products or the calibration and recalibration of equipment. Instead, reporters must use an appropriate standard method published by a consensus-based standards organization. If no such standard exists, reporters are allowed to rely on industry standard practices.

We provide more flexibility in the frequency of equipment recalibration. Reporters must now comply with the frequency specified by the manufacturer's directions or the selected quantity measurement method.

We removed the option for reporters to directly measure density but not carbon share under Calculation Method 2. We determined that using a measured density and a default carbon share factor will likely adversely affect the accuracy of the calculated emission factor since the density and carbon share of hydrocarbons are, in the absence of impurities, correlated.

We are not requiring reporters to rely on an exclusive list of standard methods for sampling products, measuring density, and measuring carbon share under Calculation Method 2. Instead, reporters must use an appropriate standard method published by a consensus-based standards organization.

We added more specific requirements for the frequency of sampling under Calculation Method 2 and now allow for mathematical composites of samples in addition to physical composites of samples.

To ensure consistent accounting of denaturant across reporters, we are requiring reporters to assume that 2.5 percent of the volume of any ethanol product that is blended into a petroleum-based product is a petroleum-based denaturant. See below for further explanation.

For bulk NGLs, reporters must calculate the emissions that would result from the complete combustion or oxidation of the individual components that constitute the NGL (i.e., ethane, propane, butane, isobutane, and pentanes plus).

We updated the definition of petroleum products to be clear that no petroleum product supplier must report on plastics and plastic products and that

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importers and exporters must report on asphalt, road oil, and lubricants.

We updated the default emissions factors based on technical research since the proposal. We updated certain factors to correct technical errors and to reflect more recent data. We expanded the factors to four significant digits to enhance precision. We also added grade-based sub-categories of finished motor gasoline and blendstocks, combined diesel and fuel oil categories into ``distillate fuel'' categories, and added sulfur-based subcategories of distillate fuel No. 1 and 2 to better distinguish between product categories with potentially different carbon contents. Full documentation of default emissions factors can be found in the TSD.

We updated 40 CFR 98.396. First, we made 40 CFR 98.396 more specific, in some cases breaking up one reporting requirement into two for clarity. Second, to allow for EPA verification of reporter calculations, we added reporting requirements for data that a reporter must already use to calculate GHGs as specified in 40 CFR 98.393 through 98.396. Third, after removing the prescriptive list of allowable methods, we added data reporting requirements on the method selected to measure quantity, density, and carbon content and the method selected to sample in order to track the appropriateness of these methods.

We require reporters to assume that ethanol contains 2.5 percent petroleum-based denaturant because we want to ensure that reporters account for the CO2emissions that would result from the combustion or oxidation of the denaturant. All ethanol that is blended with petroleum products reported in 40 CFR part 98, subpart MM should contain more than 1.96 percent petroleum-based denaturant by volume, per the requirements in 27 CFR Parts 20 and 21 to make ethanol non- potable. We considered relying on reporters to estimate the percent volume of denaturant in their products, but we determined that, in many cases, reporters would not know this information. We have concluded that 2.5 percent is a suitable assumption for the level of denaturant since, according to an Internal Revenue Service interpretation of

Section 15332 in the Food, Conservation, and Energy Act of 2008 in notice 2009-06, ethanol containing greater than 2.5 percent denaturant by volume would not be eligible for the full value of the Volumetric

Ethanol Excise Tax Credit. There may be cases where ethanol containing less than 2.5 percent denaturant is blended with petroleum-based products, but we concluded that it is better to conservatively account for potential petroleum-based carbon emissions rather than arbitrarily pick a number between 1.96 percent and 2.5 percent. 3. Summary of Comments and Responses

This section contains a brief summary of major comments and responses. A large number of comments on suppliers of petroleum products were received covering numerous topics. Responses to significant comments received can be found in ``Mandatory Greenhouse

Gas Reporting Rule: EPA's Response to Public Comments, Subpart MM:

Suppliers of Petroleum Products.''

Selection of Threshold

Comment: In the proposed rule, EPA sought comment on whether or not to establish a de minimis level of imported and exported petroleum products, either in terms of the quantity of products or the

CO2emissions associated with the combustion or oxidation of products, to eliminate any reporting burden for parties that may import or export a small amount of petroleum products on an annual basis. In response, EPA received several comments in support of establishing some type of de minimis value, including a threshold of 25,000 metric tons of CO2from the complete combustion or oxidation of all products from individual importers and exporters. EPA also received at least one comment in support of establishing a threshold value for refineries reporting under 40 CFR part 98, subpart MM.

Response: In today's rule, we are establishing a threshold of 25,000 metric tons of CO2per year for importers and exporters of petroleum products and natural gas liquids; the threshold is based on a calculation of CO2emissions that would result from complete combustion or oxidation of the imported or exported petroleum products and natural gas liquids.

When we conducted the threshold analysis for the proposed rule, we estimated from EIA data that 224 companies would be covered in 40 CFR part 98, MM as importers. Through this analysis, we found that at a threshold of 25,000 metric tons CO2per year, 175 importers and 99.9 percent of total emissions that would result from the combustion or oxidation of imported products would be covered by the proposed rule. Therefore, establishing a 25,000 metric ton

CO2threshold would drop 49 reporters in exchange for a 0.1 percent drop in total emissions. Nonetheless, we decided to propose reporting for all importers because we felt the reporting burden would be minimal since importers already report the product quantity data to other Federal agencies.

Since proposing the rule, EPA has learned new information, through comments and research, about importers that could be covered as reporters under 40 CFR part 98, Subpart MM. EPA may have omitted some importers of small volumes of petroleum products or natural gas liquids from our original threshold analysis, due to lack of public data. We never intended to cover such small volume imports with this rule (e.g., importers of non-fossil fuel products that contain small quantities of petroleum or natural gas liquids, such as butane lighters). Therefore, for the final rule, EPA concludes that establishing a 25,000 metric ton

CO2threshold for importers will relieve burden on importers of insignificant quantities of petroleum products and natural gas liquids that we never intended to cover with this rule without significantly diminishing the amount of information received by the agency. In addition, a 25,000 metric ton CO2threshold is consistent with other upstream fuel and industrial gas supplier thresholds for importers and exporters in today's rule.

When we conducted the threshold analysis for the proposed rule, we could not estimate the number of exporting companies that would be covered in 40 CFR part 98, subpart MM because the necessary data was not publically available. Nonetheless, we decided to propose reporting for all exporters because we concluded that the reporting burden would be minimal given the type of information that exporters must maintain as part of their normal business operations.

Since proposing the rule, based on analogous information learned on importers, EPA has concluded that some exporters of very small volumes of petroleum products or natural gas liquids could be covered as reporters under 40 CFR part 98, subpart MM. We never intended to cover such small volume exporters with this rule (e.g., exporters of non- fossil fuel products that contain small quantities of petroleum or natural gas liquids, such as butane lighters). Therefore, for the final rule, EPA has concluded that establishing a threshold for exporters will relieve burden on exporters of insignificant quantities of petroleum products and natural gas liquids that we never intended to cover with this rule. In today's rule, we have selected a 25,000 metric ton CO2threshold because we conclude that it will not significantly diminish the amount of information received by the agency;

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overall, exports of refined and semi-refined products are lower than imports, so the threshold adopted for imports will be adequate for collecting data on exports. In addition, a 25,000 metric ton

CO2threshold is consistent with other upstream fuel and industrial gas supplier thresholds for importers and exporters in today's rule.

In today's rulemaking, we require all refineries as defined in 40

CFR part 98, subpart MM to report, as was proposed. Our threshold analysis of refineries in the proposed rule indicated that all refineries would be covered even if we were to establish a 100,000 metric ton CO2threshold. Furthermore, we have determined that all refineries covered by this subpart are already tracking the necessary data to comply with the reporting requirements so the requirements would not pose an undue burden.

Monitoring and QA/QC Requirements

Comment: EPA received several comments that the proposed approach to determining product quantity was too prescriptive. These comments indicated that the list of allowable methods and equipment types for determining the quantity of products in the proposed rule was incomplete, would result in significant costs for industry, and could adversely impact the quality of the measurements. Commenters noted that industry uses a much larger and ever-growing number of industry methods and equipment types to determine quantity for purposes of product transfers and financial records, including methods and equipment types used to comply with Internal Revenue Service, Securities and Exchange

Commission, and Department of Homeland Security's Bureau of U.S.

Customs & Border Protection regulations. Commenters suggested that

EPA's ability to develop and maintain a comprehensive list of methods would require considerable resources, since companies and consensus- based standards organizations review quantity measurement methods regularly to ensure consistency with technological changes and advancements. Commenters also suggested that methods may improve over time for certain products as a direct result of this rulemaking.

Response: In today's rule, we are addressing these concerns by adopting an approach that recognizes the multitude of appropriate industry standard methods and practices and leaves open the possibility that industry may adopt better methods, equipment, and practices over time to determine quantities of products. EPA is requiring that petroleum product suppliers use an appropriate standard method developed by a consensus-based standards organization, when such a standard method exists. If no such standard method exists, reporters are allowed to follow industry standard practices. Consensus-based standards organizations include organizations such as ASTM

International, the American National Standards Institute (ANSI), the

American Gas Association (AGA), the American Society of Mechanical

Engineers (ASME), the American Petroleum Institute (API), and North

American Energy Standards Board (NAESB). Reporters must ensure that all equipment used for measuring quantity is calibrated and periodically recalibrated according to the manufacturer's directions or specifications in the appropriate consensus-based industry standard method.

In order to further EPA's understanding of the methods and equipment that reporters use, and to help us better assess the appropriateness of the standard methods and industry practices that individual reporters select, we are requiring that all petroleum product suppliers report the standard method or industry standard practice they use to measure each distinct product quantity that they report to EPA.

Comment: Several commenters recommended that EPA provide more flexible approaches to the direct measurement of carbon share and density under Calculation Method 2. Some noted that the proposed requirement to test samples at the end of the year could negatively impact the integrity and quality of those samples. These commenters suggested that EPA allow reporters to test samples monthly and create a mathematical composite of these test results at the end of the year.

Some commenters suggested that EPA develop a mechanism whereby reporters could reduce the frequency of sampling once the reporter demonstrates that the variability in the density and carbon share of the product is sufficiently small, and even eliminate direct measurement requirements and allow reporters to use emissions factors developed in previous years. We also received comments requesting that we expand our list of acceptable carbon share measurement methods.

Response: We have incorporated several of the suggestions to increase the flexibility of the Calculation Method 2 approach in today's rule. Reporters are now allowed to test their monthly samples throughout the year and conduct a mathematical composite of the test results at the end of the year. We have also expanded the list of acceptable sampling, density, and carbon share methods to include any appropriate standard method published by a consensus-based standards organization.

We could not determine an adequate approach for allowing reporters to reduce the sampling frequency of products based on statistical evidence of low variability in the density and carbon share for a given product. We want to capture changes in product characteristics over time and have determined that taking monthly samples of an entire product category would not be overly burdensome. Furthermore, reporters are allowed to use default factors under Calculation Method 1 if they so choose.

Data Reporting Requirements

Comment: EPA received several comments requesting that we eliminate reporting requirements related to products that have potentially non- emissive uses, including plastics and plastic products, petrochemical feedstocks, petroleum coke sent to landfill, asphalt and road oil, and lubricants and waxes. One commenter questioned the incongruity in reporting requirements proposed for refiners, who would report on all products, and importers and exporters who would not be required to report on asphalt, road oil, lubricants, waxes, plastics, and plastic products.

Response: Today's rule requires reporting on products with potentially non-emissive uses. Comprehensive upstream data will provide

EPA with a full accounting of the emissions that would result from the complete combustion or oxidation of all petroleum products and natural gas liquids introduced into the economy. Furthermore, comprehensive facility-level data can help us conduct a more robust mass balance assessment for data verification purposes. While we recognize that carbon in some petroleum products, such as asphalt, can remain un- oxidized for long periods, petroleum product supplier cannot always know with certainty whether or not the carbon in their products will be released into the atmosphere. Even asphalt can be burned as fuel or incinerated as waste. In the Inventory of US Greenhouse Gas Emissions and Sinks, EPA notes several areas of uncertainty surrounding the fate of carbon in petroleum products including those for which the Inventory assumes a 100 percent storage factor for the purposes of the national inventory (e.g., asphalt roofing, asphalt cement,

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and asphalt paving materials). As discussed in the proposal, a comprehensive and rigorous system for tracking the fate of petroleum products that may have non-emissive uses is beyond the scope of this rule, and would require a much more burdensome reporting obligation for petroleum product suppliers and other downstream users of petroleum products and natural gas liquids. The data reported as a result of this rulemaking will allow EPA to conduct further research in the future on the pathways and ultimate fate of products with potential non-emissive uses.

It was never EPA's intention to require reporting on plastics and plastic products, so we made this explicit in the definition of petroleum products as well as our definition of a refinery in 40 CFR part 98, subpart MM, which now excludes any facility (e.g. a plastics manufacturing plant) that does not process crude oil. Any

CO2emissions that would result from the combustion or oxidation of plastics and plastic products manufactured in the U.S. should already be accounted for when a petroleum product supplier introduces the petrochemical feedstock (e.g., propylene) into the economy.

In response to comments on the incongruity of the reporting burden for refiners compared to importers and exporters, we have reevaluated the list of petroleum products with potentially non-emissive uses that importers and exporters do not have to report. In the proposed rule, this list included asphalt, road oil, lubricants, waxes, plastics, and plastic products. Our rationale for excluding these products for importers and exporters was our assessment that there is a much larger variety of these products entering and leaving the country than is produced at a petroleum refinery. Upon further consideration, however, we have concluded that only waxes, plastics, and plastic products would pose an undue administrative burden on importers and exporters. Waxes, plastics, and plastic products enter and leave the country in wide- ranging forms (e.g., cosmetics, candles, lawn furniture, plastic wear) making it difficult to accurately assess the petroleum-based carbon content of these products. We have concluded that the types of asphalt, road oil, and lubricants imported in and exported from the country is much less variable, and importers already track these products and report the quantities to EIA. We have also established a 25,000 metric ton CO2annual reporting threshold for importers and exporters in today's rule, which should reduce the number of reporters and minimize the reporting of products that are imported or exported in very low quantities. Therefore, we are requiring importers and exporters to report the volume and CO2emissions that would result from the complete combustion or oxidation of the asphalt, road oil, and lubricants they supply.

In response to comments that collecting data on products with potentially non-emissive uses will overestimate actual emissions released into the atmosphere, EPA has and will continue to characterize

CO2emissions data reported under 40 CFR part 98, subpart MM as emissions that would result from the complete combustion or oxidation of the reported product(s) and not as actual emissions.

Comment: EPA received many comments urging us to leverage data that petroleum product suppliers already report to the Energy Information

Administration (EIA) and to follow EIA's data collection procedures and protocols. For example, one commenter urged EPA to require refiners on a facility-level and company-wide basis to report to EPA the same level of information on crude imports and processing that is currently reported to the EIA and to follow a process similar to the one used by the EIA; and another commenter urged us to align our reporting requirements with what the industry is already providing to the EIA.

Some commenters, urged EPA to make use of data already reported to EIA or other Federal agencies instead of requiring reporting directly to

EPA through this rulemaking. EPA also received comments recommending that EIA reporting remain separate from the reporting requirements of this rule.

Response: In the proposed rulemaking, EPA stated that we considered, but did not propose, the option of obtaining data by accessing existing Federal government reporting databases and we sought comment on this decision.

In today's rulemaking, we are requiring reporters to report data directly to EPA. We have determined that in order to collect facility- level data from refineries (and company-level data from importers and exporters) that is consistent with other reporters in this rule, in terms of timing, reporting, and verification procedures, we are not able to rely upon EIA data. In addition, EIA relies on a number of legal authorities to pledge confidentiality to statistical survey respondents for company-level information. Some data are collected with legal authority from the Confidential Information Protection and

Statistical Efficiency Act of 2002 (CIPSEA), under which reported information must be held in confidence and must be used for statistical purposes only. Collection of data directly by EPA in a central system will allow EPA to electronically verify and publish the data quickly, to use the information for non-statistical purposes, and to handle confidential business information in accordance with the CAA (see the general provisions preamble for addition discussion on CBI). In today's rulemaking we did not replicate EIA's reporting requirements and methodologies if we did not consider them sufficient to achieve our objective, which is to collect comprehensive and accurate data on the

CO2emissions that would result from the complete combustion or oxidation of petroleum products introduced into the economy. For example, we provide a comprehensive list in Tables MM-1 and MM-2 of 40

CFR part 98, subpart MM, according to which reporters must categorize their products for reporting under today's rulemaking. This list differs from EIA's list of products, according to which reporters must report to EIA. Some of the products are the same on both lists (e.g., aviation gasoline and kerosene) while some products are classified differently on one list than on the other (i.e., EPA's list breaks reformulated gasoline up by summer and winter varieties while EIA breaks reformulated gasoline up by type of oxygenate blended into it).

We crafted EPA's product list carefully and we feel that each category has the potential to have a unique carbon share and/or density.

Overall, the items on our list are common products in commerce and are already tracked by refineries, importers, and exporters. Therefore, we estimate that the additional burden to comply with this rule will be minimal.

NN. Suppliers of Natural Gas and Natural Gas Liquids 1. Summary of the Final Rule

Source Category Definition. Suppliers of natural gas and natural gas liquids are:

NGL fractionators, which are installations that fractionate NGLs into their constituent liquid products: ethane, propane, normal butane, isobutane or pentanes plus for supply to downstream facilities.

Local natural gas distribution companies (LDCs) that own or operate distribution pipelines that deliver natural gas to end users. Companies that operate interstate pipelines transmission or intrastate transmission pipelines are not part of this source category.

Suppliers of natural gas and NGLs that meet the applicability criteria in the General Provisions (40 CFR 98.2)

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summarized in Section II.A of this preamble must report GHG emissions that would result from complete combustion or oxidation of products they supply.

GHGs to Report. Natural gas fractionators must report

CO2emissions that would result from the complete combustion or oxidation of the annual quantities of propane, butane, ethane, isobutene, and pentanes plus supplied.

Local distribution companies must report CO2emissions that would result from the complete combustion or oxidation of the annual volume of natural gas distributed to their customers.

Suppliers of natural gas and NGLs are not required to report data on emissions of other GHGs that would result from the complete combustion or oxidation of their products, such as CH4or

N20.

GHG Emissions Calculation and Monitoring. Reporters must use one of two methods to calculate the CO2emissions that would result from the complete combustion or oxidation of natural gas supply or NGL supply:

One method uses either a measured or default fuel heating value and either a measured or default CO2emissions factor.

This method is most appropriate for liquid fuels.

The second method uses either a measured or default

CO2emissions factor. This method is most appropriate for gaseous fuels.

A NGL fractionator must then follow two additional equations, if applicable, to subtract the CO2emissions that would result from the complete combustion or oxidation of NGL supply that are double-counted. A LDC must then follow up to four additional equations, if applicable, to subtract the CO2emissions that would result from the complete combustion or oxidation of natural gas supply that is double-counted.

Data Reporting. In addition to the information required to be reported by the General Provisions (40 CFR 98.3(c)) and summarized in

Section II.A of this preamble, reporters must submit additional data that are used to calculate natural gas or NGL supply. A list of the specific data to be reported for this source category is contained in 40 CFR part 98, subpart NN.

Recordkeeping. In addition to the records required by the General

Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this preamble, reporters must keep records of additional data used to calculate natural gas or NGL supply. A list of specific records that must be retained for this source category is included in 40 CFR part 98, subpart NN. 2. Summary of Major Changes Since Proposal

Response to Public Comments, Subpart NN: Suppliers of Natural Gas and

Natural Gas Liquids.''

We changed the source category responsible for reporting

NGL supply in 40 CFR part 98, subpart NN from all natural gas processors to only facilities that fractionate natural gas liquids.

We eliminated the requirement to report bulk NGL since NGL fractionators do not supply bulk NGL.

We added equations to calculate emissions that would result from the oxidation or combustion of the following volumes of natural gas and NGLs because they should be subtracted from the reporter's total emissions calculation, when applicable: fractionated

NGLs received from other fractionators; natural gas injected for storage; natural gas delivered to individual customers already reporting under another Subpart of this rule; and natural gas delivered by an LDC to another LDC.

We clarified the points of measurements for reporting purposes.

We changed the rule to allow local distribution companies to use transmission pipeline metered volumes and calculated heating value where the local distribution companies do not perform their own measurements.

We provide flexibility in frequency of equipment calibration, requiring reporters to comply with standard industry practices for measurements used for billing purposes as audited under

Sarbanes Oxley regulations.

We added a procedure for measuring the carbon content of blends of NGLs since NGL fractionators may supply blends of NGLs.

We updated 40 CFR 98.406. First, we made 40 CFR 98.406 more specific, in some cases breaking up one reporting requirement into two for clarity. Second, to allow for EPA verification of reporter calculations, we added reporting requirements for data that a reporter must already use to calculate GHGs as specified in 40 CFR 98.403 to 40

CFR 98.406. This includes the addition of reporting requirements for new calculations introduced in the final rule to prevent supply double- counting. Third, after removing the prescriptive list of allowed standards and methods, we added data reporting requirements on the method selected to measure quantity, HHV, and carbon content. Fourth, we added a reporting requirement for the quantity of odorized propane.

Fifth, we added data reporting requirements for inputs received by a

NGL fractionator in order to conduct verification using a mass-balance approach. 3. Summary of Comments and Responses

This section contains a brief summary of major comments and responses. A large number of comments on suppliers of natural gas and

NGLs were received covering numerous topics. Responses to significant comments received can be found in ``Mandatory Greenhouse Gas Reporting

Rule: EPA's Response to Public Comments, Subpart NN: Suppliers of

Natural Gas and Natural Gas Liquids.''

Definition of Source Category

Comment: EPA received many comments on the non-emissive use of natural gas liquids (NGLs). In general, these comments stated that NGLs such as ethane, butane, and isobutene, are either used as feedstocks in the petrochemical industry or as blendstocks that are reported by refineries in 40 CFR part 98, subpart MM, and should not be reported as though they are completely combusted or oxidized. Several commenters proposed that odorized propane should be the focus of 40 CFR part 98, subpart NN rather than all NGLs because odorized propane is the only

NGL that is combusted as fuel.

Response: Today's rule still requires reporting on all NGL products, even those with potentially non-emissive uses. Comprehensive upstream data will provide EPA with a full accounting of the emissions that would result from the complete combustion or oxidation of all natural gas liquids introduced into the economy.

As discussed in the proposal, a comprehensive and rigorous system for tracking the fate of natural gas liquids that may have non-emissive uses is beyond the scope of this rule, and would require a much more burdensome reporting obligation for NGL fractionators and downstream users of natural gas liquids. Based on the data available today, we do not believe that a NGL fractionator can know with certainty whether or not the carbon in their products will be released into the atmosphere.

The data reported as a result of this rulemaking will allow EPA to conduct further research on the pathways and ultimate fate of NGL and to refine our understanding of and

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policy on products with potential non-emissive uses.

Therefore, EPA does not concur with the proposal to replace NGL reporting with propane odorizers. However, EPA concurs that odorized propane lines up closely with propane combusted downstream, and that data collection on odorized propane would help EPA decide if and how to carry out a wide variety of CAA provisions on emission sources, as authorized broadly under CAA sections 114 and 208. As a result, we have added reporting requirements on the volume of propane odorized on site in today's rule.

We do not concur that products reported under 40 CFR part 98, subpart NN, such as isobutane to be blended with fuel, will be double- counted as products reported under 40 CFR part 98, subpart MM. Subpart

MM requires refineries to report all non-crude feedstocks that enter the facility in order to subtract the emissions that would result from the oxidation or combustion of those products from their calculations.

Such methodology allows EPA to collect data on the entire petroleum and natural gas liquids system without any double-counting.

Finally, in response to comments that collecting data on products with potentially non-emissive uses will overestimate actual emissions released into the atmosphere, EPA will continue to characterize

CO2emissions data reported under 40 CFR part 98, subpart NN as emissions that would result from the complete combustion or oxidation of the reported product(s) and not as actual emissions.

Comment: Many commenters discouraged EPA from requiring reporting from natural gas processors. In general, these comments stated that processors do not know the constituents of the gas they process. They further stated that since bulk NGLs are often sent from one processor to another, reporting by processors on bulk NGLs would result in double-counting of supply. Ultimately, several commenters were confused by the multiple definitions provided in the rule for a natural gas processor and were not clear on the exact covered party in 40 CFR part 98, subpart NN.

Response: In the final rule, we specify the source category as NGL fractionators rather than as natural gas processors, and we have removed the requirement to report bulk NGLs. To avoid any remaining potential for double-counting, we provide an equation for a fractionator to subtract from its calculations any NGL constituents received from other fractionators that would report those products under this rule.

By requiring reporting from NGL fractionators, we have removed the need for the term ``natural gas processor'' in 40 CFR part 98, subpart

NN. Multiple definitions for this term no long exist in the rule.

Monitoring and QA/QC Requirements

Comment: Many commenters interpreted EPA's measurement and calibration requirements differently than we intended, and as a result pressed upon EPA the inability of industry to reasonably meet such requirements. Many commenters interpreted that EPA required meter reading and calibration of every customer meter. Other commenters interpreted that EPA required daily measurement totals of throughput.

Response: In today's rule, we provide precise language to remove any confusion about monitoring and QA requirements. First, we clarify that the point of measurement for natural gas supply is the city gate meter. If the LDC makes its own measurements at the city gate according to business as usual practices, then it must use its own measurements.

If not, it must use the delivering pipeline invoices measurements. The only exceptions are that the point of measurement for natural gas delivered to large end-users is the customer meter and the point of measurement for natural gas stored or removed from storage is the appropriate storage meter. However, we clarify that customer meters and storage meters are not subject to the 40 CFR part 98, subpart NN calibration requirements.

Second, we clarify that the minimum frequency of the measurements of quantities of NGLs and natural gas shall be based on the reporter's standard practices for commercial operations. For NGL fractionators the minimum frequency of measurements shall be the measurements taken at custody transfers summed to the annual reportable volume. For natural gas the minimum frequency of measurement shall be based on the LDC's standard measurement schedules used for billing purposes and summed to the annual reportable volume. If daily measurements are not standard practice for a reporter, then that reporter need not conduct daily measurements.

EPA clarifies in the final rule that customer meters do not face calibration requirements under 40 CFR part 98, subpart NN. Other equipment used to measure quantities must be calibrated prior to their first use for reporting under this subpart, using a suitable standard test method published by a consensus based standards organization or according to the equipment manufacturer's directions. Such equipment must also be recalibrated at the frequency specified by the standard test method used or by the manufacturer's directions. EPA has concluded that initial calibration requirements are necessary to ensure consistency across all reporters and accuracy of data. Since such a wide variety of calibration methods is allowed and since commenters stated that industry already calibrates carefully as a result of State

Utility Commission and other regulations, EPA concluded that industry is already following such calibration requirements for usual business operations.

Data Reporting Requirements

Comment: EPA received many comments on the requirement for LDCs to report information on individual customers. In general, commenters interpreted the reason for EPA to collect this data differently than was intended. Many commented on the CBI nature of customer-specific delivery information. Others commented that LDCs do not or may not have access to the EIA or EPA numbers of their customers. One commenter told us that a LDC can only attest to the gas volume delivered through a single particular meter at a single particular location, which is not necessarily an individual customer.

Response: In the final rule, EPA has clarified that an LDC must report on customers that receive more than 460,000 million standard cubic feet (Mscf) per year in order to subtract that volume out of its total calculations. EPA's intention is to use this data to remove potential double-counting and to prevent a LDC from calculating and reporting an overstated supply volume. EPA can also use these data to verify that covered direct emitters are approximately reporting under the rule. In response to comments that LDCs do not or may not have access to customers' EIA or EPA numbers, we have changed the reporting of this from required to voluntary, if known. We have further specified that LDCs must report large volumes delivered to a single meter rather than to a particular end-user.

OO. Suppliers of Industrial GHGs 1. Summary of the Final Rule

Source Category Definition. Suppliers of industrial GHGs consist of the following:

Facilities producing any fluorinated GHG or

N2O, except those that produce

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only HFC-23 generated as a byproduct during HCFC-22 production.

Bulk importers of fluorinated GHGs or N2O, if the total combined imports of industrial GHGs and CO2exceed 25,000 metric tons of CO2e per year.

Bulk exporters of fluorinated GHGs or N2O, if the total combined exports of industrial GHGs and CO2exceed 25,000 metric tons CO2e per year.

Suppliers of Industrial GHGs that meet the applicability criteria in the General Provisions (40 CFR 98.2) summarized in Section II.A of this preamble must report industrial GHG supply flows.

GHGs to Report. Suppliers of industrial GHGs must report the amount of N2O and each fluorinated GHG produced, imported, exported, transformed, or destroyed during the calendar year. Importers and exporters of CO2must calculate and report annual amounts of CO2according to 40 CFR part 98, subpart PP.

GHG Emissions Calculation and Monitoring. Suppliers must use the following methods to calculate annual industrial GHG supply flows:

The mass of each fluorinated GHG or N2O produced must be determined by measurements of gas production, less the mass of that GHG added to the process upstream (e.g., where used GHGs are added back to the production process for reclamation).

The mass of each fluorinated GHG transformed must be determined considering the mass of fluorinated GHG fed into the transformation process and the efficiency of that process (as indicated by yield calculations or quantities of unreacted fluorinated GHGs or nitrous oxide permanently removed from the process and recovered, destroyed, or emitted).

The mass of each fluorinated GHG destroyed must be determined by measurements of the mass of fluorinated GHG fed to the destruction device and a measurement of the destruction efficiency.

Data Reporting. In addition to the information required to be reported by the General Provisions (40 CFR 98.3(c)) and summarized in

Section II.A of this preamble, reporters must submit additional data that are used to calculate industrial GHG supply flows or that can be used to verify industrial gas supply flows. A list of the specific data to be reported for this source category is contained in 40 CFR part 98, subpart OO.

Recordkeeping. In addition to the records required by the General

Response to Public Comments, Subpart OO: Suppliers of Industrial

GHGs.''

EPA has elaborated on the definition of ``produce'' to clarify what it does and does not include. The definition now explicitly includes (1) the manufacture of a fluorinated GHG for use in a process that will result in the transformation of that GHG (either at or outside of the production facility) and (2) the creation of a fluorinated GHG (with the exception of HFC-23) that is captured and shipped off site for any reason, including destruction. The definition now explicitly excludes the creation of by-products that are released or destroyed at the production facility.

EPA has eased the accuracy and precision requirements for measuring production, transformation, and destruction. EPA is also permitting facilities flexibility in the frequency of measurements and calibration of measurement devices. Masses produced, fed into transformation processes, and fed into destruction devices must now be estimated to a precision and accuracy of one percent rather than 0.2 percent. Requirements to measure concentrations, which had previously been associated with the transformation and destruction provisions, have been changed to requirements to estimate concentrations or related quantities.

EPA has eliminated the requirement that fluorinated GHG production facilities that destroy fluorinated GHGs annually verify the destruction efficiency of their destruction devices.

EPA has added an additional method for estimating missing mass flow data in the event that a secondary mass measurement for that stream isn't available. In that event, producers can use a related parameter and the historical relationship between the related parameter and the missing parameter to estimate the flow.

EPA has removed the option for reporters to develop their own methods for estimating missing data if they believe that the prescribed method will over- or under-estimate the data.

EPA has added some reporting requirements to be consistent with the changes to the calculations and monitoring sections and to permit verification of emissions calculations.

EPA has added an exemption from reporting requirements for import or export shipments containing less than 250 metric tons of

CO2e.

EPA has clarified that the criteria for imported container heels at paragraph 98.417(e) set forth the conditions under which importers do not need to report heels; they do not establish requirements for all containers containing residual gas. If importers import containers with residual gas that does not meet these conditions, they must simply report these imports under paragraph 98.416(c). In addition, EPA is adding another condition under which imported heels do not need to be reported; that is the case in which the heels are recovered and included in a future shipment.

EPA is requiring fluorinated GHG production facilities to submit a one-time report describing current measurement and estimation practices.

EPA is requiring the one-time report on measurement practices because the Agency is providing some flexibility to reporters regarding the methods that they use to calculate industrial gas supply flows.

This flexibility permits reporters to use a larger range of methods and measurement equipment than were proposed, and it is important for EPA to understand the methods and equipment and their accuracies. Similar reports are required under EPA's Stratospheric Ozone Protection

Regulations at 40 CFR part 82.

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3. Summary of Comments and Responses

This section contains a brief summary of major comments and responses. A large number of comments on suppliers of industrial GHGs were received covering numerous topics. Responses to significant comments received can be found in ``Mandatory Greenhouse Gas Reporting

Rule: EPA's Response to Public Comments, Subpart OO: Suppliers of

Industrial GHGs.''

Definition of Source Category

Comment: EPA received a number of comments regarding the proposed definition of ``fluorinated greenhouse gas.'' Several commenters argued that the proposed definition was too broad because it would include nonvolatile materials that could not be emitted to the atmosphere and materials for which GWPs had not been calculated. One commenter suggested establishing a lower vapor pressure limit for fluorinated

GHGs (heat transfer fluids) of 400 Pa (0.004 bar, or three mm Hg absolute) at 25 C. Some commenters expressed the concern that the lack of GWPs for some covered compounds would lead to incomplete or inconsistent reporting because facilities would assign their own GWPs to compounds for which GWPs were not provided in Table A-1 of 40 CFR part 98, subpart A.

Some commenters recommended that EPA address these concerns by requiring reporting of only those fluorinated compounds listed in Table

A-1 of 40 CFR part 98, subpart A. However, one of these commenters noted that the list in A-1 is incomplete and inconsistent, excluding for example, some high-GWP compounds whose low-GWP alternatives are included. This commenter recommended that EPA establish a ``visible and participative process'' to add other compounds as appropriate to Table

A-1 of 40 CFR part 98, subpart A.

Response: In today's final rule, EPA is modifying the proposed definition of fluorinated GHG by adding an exemption for ``substances with a vapor pressure of less than one mm of Hg absolute at 25 degrees

C.'' This modification ensures that non-volatile fluorocarbons such as fluoropolymers are excluded from reporting requirements, while requiring reporting of fluorocarbons (as well as SF6and

NF3) that could reasonably be expected to be emitted to the atmosphere.

As noted by several commenters, this definition would require reporting of some fluorocarbons to which GWPs have not been assigned in either IPCC or World Meteorological Organization (WMO) Scientific

Assessments (i.e., fluorocarbons for which Table A-1 of 40 CFR part 98, subpart A does not provide GWPs). However, the lack of GWPs for some fluorocarbons will not impede reporting because EPA is requiring reporting of production and other quantities in tons of chemical rather than in tons of CO2e. For purposes of determining whether or not the 25,000 metric ton CO2e import or export threshold is exceeded, EPA is requiring facilities to include only substances whose

GWPs appear in Table A-1 of 40 CFR part 98, subpart A.

EPA believes that this approach is prudent and appropriate. As acknowledged by commenters, Table A-1 of 40 CFR part 98, subpart A is not a complete listing of current or potential fluorinated GHGs; the

IPCC and WMO lists on which it is based reflect only the facts that the listed materials have been synthesized, their atmospheric properties investigated, the results published, and the publications found by the

IPCC and WMO Assessment authors. Table A-1 is known to omit some existing fluorinated GHGs and it unavoidably omits future fluorinated

GHGs that have not yet been synthesized. Given the radiative properties of the carbon-fluorine bond, any fluorocarbon emitted into the atmosphere may have a significant GWP. This is true even for some fluorocarbons with lifetimes of less than one year, including, for example, HFE-356pcc3, with a lifetime of four months and a 100-year GWP of 110.

Reporting of fluorocarbons that do not appear in Table A-1 of 40

CFR part 98, subpart A will provide valuable information on the full range of volatile fluorocarbons entering U.S. commerce. This information can be used to assess the overall volume and importance of compounds for which GWPs have not been evaluated and to help identify which compounds should have their GWPs evaluated first. In addition, once GWPs have been identified for these compounds, historical reports in tons of chemical can be converted into CO2e. Without a comprehensive reporting requirement, such historical information could be lost. Ultimately, all of this information can be used to inform policy decisions regarding the appropriate type and scope of emission reduction measures for these gases. Considering the modest cost of reporting production, import, and export of such compounds, the potential value of this information justifies a comprehensive definition of fluorinated GHG.

EPA agrees with commenters who noted that Table A-1 of 40 CFR part 98, subpart A should be periodically updated through a visible and participative process. EPA anticipates that as GWPs are evaluated or re-evaluated by the scientific community, the Agency will update Table

A-1 of 40 CFR part 98, subpart A through notice and comment rulemaking.

EPA may also, through rulemaking, establish a more proactive process for ensuring that GWPs are appropriately evaluated or re-evaluated.

Comment: EPA received comments both supporting and opposing a requirement to report imports of fluorinated GHGs contained in equipment and foams. Commenters supporting such a requirement noted that these imports comprised a significant fraction of U.S. consumption of fluorinated GHGs, that excluding these imports from reporting would put domestic manufacturers at a disadvantage and lead to leakage of manufacturing and increased emissions of GHGs, and that the burden of reporting these imports would be low, since there are relatively few importers and the reported information is easily accessible. Commenters opposing such a requirement stated that the benefit of reporting would be small because pre-charged equipment and foams are ``hermetically sealed systems that essentially emit no GHGs,'' while the cost would be high due to the large number of importers.

Response: EPA did not propose to require reporting of fluorinated

GHGs contained in imported products because EPA was concerned that the administrative burden of such a requirement could be considerable, while the quantities imported in at least some types of products could be small. However, in the proposal EPA acknowledged that the quantities of fluorinated GHGs imported in pre-charged equipment and foams appeared significant, and that ascertaining the identity and quantity of fluorinated GHGs in these products might be relatively straightforward. EPA is continuing to research these issues, and is deferring the final decision on whether to include imports of equipment and foams containing fluorinated GHGs to a later rulemaking.

Monitoring and QA/QC Requirements

Comment: Several commenters stated that facilities could not meet the proposed accuracy, precision, and frequency requirements for their measurements of production, transformation, and destruction using existing equipment and practices. These commenters stated that they would need to expend significant funds (millions of

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dollars in some cases) and time to install Coriolis flowmeters in multiple streams and to implement daily sampling protocols to analyze the contents of these streams. One commenter requested that EPA revise its precision and accuracy requirements to one percent for measurements of mass. Other commenters argued that instead of establishing strict accuracy, precision, and frequency requirements for measuring production, EPA should permit facilities to use existing measurement instruments and practices, such as NIST Handbook 44 and the trial HFC reporting program patterned on EPA's reporting requirements for ozone- depleting substances.

Response: Given the limited amount of time before 2010 data collection must begin, EPA agrees that it is appropriate to ease the accuracy and precision requirements proposed for measuring production, transformation, and destruction. EPA is therefore revising these requirements in the final rule. EPA is also permitting facilities flexibility in the frequency of measurements and calibration of measurement devices.

This approach will permit facilities to begin measuring their production, transformation, and destruction for purposes of the rule beginning in January 2010, using their current practices and equipment.

However, EPA is planning to revisit the precision and accuracy requirements for industrial gas supply as we review public comments and perform analyses related to proposed 40 CFR part 98, subpart L

(fluorinated gas production), which is not included in today's final rule. This is because the accuracy and precision with which production facilities track production, transformation, and destruction can have a profound influence on the accuracy and precision of these facilities' fluorinated GHG emission estimates. For one method of monitoring F-GHG emissions under consideration, a one percent relative error in production mass measurements could result in a much higher relative error in the emissions estimate, e.g., over 90 percent at an emission rate of 1.5 percent. For other methods of monitoring F-GHG emissions, however, a one percent relative error in production mass measurements would not lead to large errors in emission estimates. For both 40 CFR part 98, subpart OO and 40 CFR part 98, subpart L, EPA's goal is to optimize methods of data collection to ensure data accuracy while considering industry burden.

PP. Suppliers of Carbon Dioxide (CO2) 1. Summary of the Final Rule

Source Category Definition. Under the rule, suppliers of

CO2consist of the following:

Facilities with production process units that capture and supply CO2for commercial applications or that capture and maintain custody of a CO2stream in order to sequester or otherwise inject it underground.

Facilities with CO2production wells that extract a CO2stream for the purpose of supplying

CO2for commercial applications.

Importers of bulk CO2, if total combined imports of CO2and other GHGs exceed 25,000 metric tons of

CO2equivalent (CO2e) per year.

Exporters of bulk CO2, if total combined exports of CO2and other GHGs exceed 25,000 metric tons

CO2e per year.

This source category is focused on upstream supply. It does not cover: Storage of CO2above ground or in geologic formations; use of CO2in enhanced oil and gas recovery; transportation or distribution of CO2; or purification, compression, on-site use of CO2captured on site, or processing of CO2.This source category does not include

CO2imported or exported in equipment, such as fire extinguishers.

Suppliers of CO2that meet the applicability criteria in the General Provisions (40 CFR 98.2) summarized in Section II.A of this preamble must submit GHG reports.

GHGs to Report. Suppliers of CO2must report the mass of

CO2in a stream captured from production process units and extracted from production wells, and the mass of CO2in containers that is imported and exported.

GHG Emissions Calculation and Monitoring. While this source category is focused on upstream supply of CO2, EPA recognizes that all CO2supplied to the economy does not necessarily result in an emission. There are a variety of downstream applications for CO2--some applications are emissive and some are non-emissive. Under this rulemaking, a CO2supplier facility must calculate the mass of CO2supplied quarterly by measuring the mass or volumetric flow of gas and multiplying by the

CO2concentration, and density in the case a volumetric flow meter is used, of the gas or liquid, as specified below. EPA requires quarterly monitoring because EPA has concluded that the CO2 concentration of the stream varies throughout the year, and a quarterly concentration number multiplied by a quarterly volume will generate more accurate calculation of CO2supply than annual measurements. EPA requires these quarterly numbers to be reported so that EPA can electronically verify the calculations. The CO2 supplier must also provide information on the downstream CO2 application, if known. Reporters must use the following methodologies, as applicable, for calculating CO2supplied:

For suppliers that make measurements with mass flow meters, calculate quarterly for each meter the total mass of

CO2in a CO2stream in metric tons, prior to any subsequent purification, processing, or compressing, according to

Equation PP-1 of 40 CFR 98.423. Measure mass flow and concentration in accordance with 40 CFR 98.424.

For suppliers that make measurements with volumetric flow meters, calculate quarterly for each meter the total mass of

CO2in a CO2stream in metric tons, prior to any subsequent purification, processing, or compressing, according to

Equation PP-2 of 40 CFR 98.423. Measure volumetric flow, concentration and density in accordance with 40 CFR 98.424.

For suppliers that have multiple flow meters, aggregate data according to methods specified in Equation PP-3 in 40 CFR 98.423.

Importers or exporters that import or export

CO2in containers must calculate the total mass of

CO2supplied in metric tons, prior to any subsequent purification, processing, or compressing, according to equation PP-4 of 40 CFR 98.423. Use weigh bills, scales, or load cells to measure the mass of CO2imported or exported in containers.

Data Reporting. In addition to the information required to be reported by the General Provisions (40 CFR 98.3(c)) and summarized in

Section II.A of this preamble, reporters must submit additional data that are used to calculate CO2supply. A list of the specific data to be reported for this source category is contained in 40 CFR 98.426.

Recordkeeping. In addition to the records required by the General

Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this preamble, reporters must keep records of additional data used to calculate CO2supply. A list of specific records that must be retained for this source category is included in 40 CFR 98.427. 2. Summary of Major Changes Since Proposal

The major changes since proposal are identified in the following list. The rationale for these and any other significant changes can be found below or in ``Mandatory Greenhouse Gas

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Reporting Rule: EPA's Response to Public Comments, Subpart PP:

Suppliers of Carbon Dioxide.''

We added equations and QA requirements to allow reporters to determine CO2quantity using volumetric flow meters, weigh bills, scales, or load cells, as appropriate. These additions supplement the proposed equations and quality assurance requirements to determine CO2quantity using mass flow meters.

We revised the reporting procedures for missing data in 40

CFR 98.425. Facilities must use quarterly values as substitute data as they can no longer use annual average values. We added missing data procedures to allow for more quarterly data points to be used, as appropriate. EPA concluded that quarterly missing data values will generate more accurate estimates than annual average values.

To improve the emissions verification process, we reorganized and updated 40 CFR 98.426. We moved some data elements from 40 CFR 98.427 to 40 CFR 98.426, and added some data elements that a reporter must already use to calculate GHGs as specified in 40 CFR 98.423 to 40 CFR 98.426 for clarity.

We revised the reporting and calculation procedures to require facilities using flow meters to determine annual mass for every flow meter used. To aggregate data at the facility level for

CO2being captured in production wells or production process units, we have added Equation PP-3.

To decrease unnecessary sampling burden, we have removed the requirement of quarterly concentration sampling for importers and exporters that use containers of CO2. 3. Summary of Comments and Responses

This section contains a brief summary of major comments and responses. A large number of comments on suppliers of CO2 were received covering numerous topics. Responses to significant comments received can be found in ``Mandatory Greenhouse Gas Reporting

Rule: EPA's Response to Public Comments, Subpart PP: Suppliers of

Carbon Dioxide.''

Definition of Source Category

Comment: EPA received many comments about how we defined the source category in this Subpart. One group of comments stated that the

CO2supplied to the economy should not be characterized as an emission. Some in this group of comments specified that much of the supplied CO2is stored at enhanced oil recovery (EOR) sites, which are ``closed systems'', rather than emitted. In general, these same commenters stated that any CO2reporting requirements placed by EPA on industry should be placed on downstream CO2 users, such as EOR facilities, rather than CO2suppliers and should be for actual emissions only. Other comments echoed that EPA needs to collect data from recipients of supplied CO2such as EOR sites. This group pressed upon EPA the need to collect not only data on actual emissions but also data on injection, production, and geologic sequestration of CO2. Some of the benefits cited for collecting such comprehensive data include: Assisting in ensuring no more than negligible releases at a facility if it is properly sited, designed, and permitted; achieving full public accountability of

CO2geologic sequestration effectiveness; and tracking the

CO2throughout the entire carbon dioxide capture and sequestration (CCS) chain for the purposes of adjusting CO2 emissions reported or assigning offsets. Along those lines, some commenters urged EPA to rely on or expand the existing underground injection control (UIC) program to deal with CCS.

Response: EPA did not intend to characterize all CO2 supplied to the economy as emissions and recognizes that there are a variety of applications for CO2,both emissive and non- emissive. CO2supplied to the economy would result in an emission if the CO2were used in an application which would ultimately result in release of the CO2to the atmosphere.

EPA is also collecting information from upstream suppliers in other subparts of this rulemaking such as natural gas supply and petroleum product supply.

EPA recognizes that, in order to determine whether or not supplied

CO2has been or will be released to the atmosphere (e.g., emitted), the Agency needs information on the downstream CO2 end-use. In today's final rulemaking, CO2suppliers must provide information on the downstream CO2application, if known. EPA believes information on the end-use will provide some idea of the amounts of CO2which are emitted. Where that end-use is geologic sequestration (at EOR or other types of facilities), EPA will need additional information on the amount of CO2that is permanently and securely sequestered and on the monitoring and verification methodologies applied. With respect to EOR, the geology of an oil and gas reservoir can create a good barrier to trap

CO2underground. Because these formations effectively stored oil or gas for hundreds of thousands to millions of years, it is believed that they can be used to store injected CO2for long periods of time. However, EPA also recognizes that the requirements to identify a suitable GS site extend beyond geophysical trapping parameters alone and include: The evaluation and appropriate management of potential leakage pathways, appropriate rate and pressure of injection, appropriate monitoring, and other such features. While some amount of CO2injected into oil and gas reservoirs for

EOR purposes will be trapped in the subsurface, these and other site- specific elements influence the amount of CO2securely sequestered and the potential for release of CO2during EOR operations.

Given the comments in support of downstream data collection, particularly with respect to EOR systems and CO2geologic sequestration (at EOR or other types of facilities), EPA plans to issue a new proposal on geologic sequestration and will consider how to address emissions and sequestration at active EOR facilities. EPA will take action on this issue in the near future with the goal that data collection for these types of facilities can begin as quickly as possible. EPA will seek comment on monitoring, reporting, and verification methodologies which can be used to determine the amount of

CO2emitted and geologically sequestered at active EOR facilities and geologic sequestration sites where CO2is injected (for long-term storage) into saline aquifers, oil and gas reservoirs, or other geologic formations. Furthermore, as stated in

Section III.W of this preamble, EPA plans to take additional time to consider alternatives to data collection procedures and methodologies in the proposed 40 CFR part 98, subpart W and will consider inclusion of GHG reporting from other sectors of the oil and gas industry besides those proposed for reporting in proposed 40 CFR part 98, subpart W. EOR surface facility operations may be part of those considerations. The data reported under subsequent regulatory actions and the data reported under today's rulemaking will together enable EPA to understand the amount of CO2supplied, emitted, and sequestered in the

U.S., to carry out a wide variety of CAA provisions. The options that we will have considered and the resulting recommended approaches will be further fleshed out through a notice and comment process. See the next comment response for a discussion of why EPA still needs to collect CO2supplier data in today's rulemaking even though a new rulemaking on sequestration is planned.

In response to comments that EPA should rely on or expand the UIC program to address emissions of CO2,

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that issue is outside the scope of this rulemaking. However, EPA agrees that the UIC program and EPA's authority under the Safe Drinking Water

Act (SDWA) will provide a foundation for ensuring safe and effective containment of CO2. However, SDWA is focused on permitting sites for protection of ground and drinking water; the new proposal discussed above will be designed to address issues related to the CAA.

EPA intends to harmonize CCS requirements across relevant statutory or other programs in order to minimize any redundancy and any burden on reporters. The reporting requirements in today's rulemaking for

CO2suppliers and the reporting requirements in new rulemaking for CO2geologic sequestration sites will complement each other and together they can be harmonized with reporting requirements under the UIC proposed rulemaking. In a new CAA rulemaking on geologic sequestration reporting, EPA will rely on UIC permit requirements to the maximum extent possible. EPA will seek comment on these issues and will also endeavor to issue a geologic sequestration GHG reporting rule in the same time frame as it has planned for the stand-alone UIC GS rulemaking.

Comment: EPA received comments requesting information on how

CO2supply will assist EPA in developing future climate policy. Commenters stated that they do not believe CO2 supply data will provide EPA with useful information. Commenters stated that data collection from CO2suppliers does not fit within

EPA's mandate from Congress to measure upstream emissions only as appropriate.

Response: As discussed in Sections I.C and II.Q of this preamble,

EPA is collecting data from CO2suppliers in today's rule to carry out a wide variety of CAA provisions, as authorized broadly under

CAA Sections 114 and 208. For example, this data will enable EPA to evaluate the appropriate action to take under section 103 regarding non-regulatory strategies for pollution prevention. It will also inform evaluation of possible CAA regulation of the supplier and/or recipient of the CO2Data on CO2supply to the economy will allow EPA to make a well informed decision about whether and how to use the CAA to regulate facilities that capture, sequester, or otherwise receive CO2as an end-user.

Though CO2capture and geologic sequestration are occurring now on a relatively small scale, CCS is expected to play a major role in mitigating GHG emissions from a wide variety of stationary sources. According to the Inventory of U.S. Greenhouse Gas

Emissions and Sinks: 1990-2007 (EPA, April 2009), stationary sources contributed 67 percent of the total CO2emissions from fossil fuel combustion in 2007. The stationary sources represent a wide variety of sectors amenable to CO2capture; electric power plants (existing and new), natural gas processing facilities, petroleum refineries, iron & steel foundries, ethylene plants, hydrogen production facilities, ammonia refineries, ethanol production facilities, ethylene oxide plants, and cement kilns. Furthermore, 95 percent of the 500 largest stationary sources are within 50 miles of a candidate CO2reservoir.\22\

\22\ Dooley, JJ, CL Davidson, RT Dahowski, MA Wise, N Gupta, SH

Kim, EL Malone, ``Carbon Dioxide Capture and Geologic Storage: A Key

Component of a Global Energy Technology Strategy to Address Climate

Change.'' Joint Global Change Research Institute, Battelle Pacific

Northwest Division. May 2006. PNWD-3602. College Park, MD.

With this rule, EPA will begin building capacity to track the growth in CO2supply and learn about its disposition throughout the economy. EPA has concluded that we need data now from

CO2suppliers--both industrial facilities and CO2 production wells--in order to effectively track how the supply sources will change over time. For example, we will need to track if and by how much CO2captured from industrial facilities will offset or displace CO2produced from natural formations. Even after

EPA begins collecting data on CO2geologic sequestration under the proposed new rulemaking (discussed above), EPA will continue to need data from CO2suppliers in order to track any

CO2that is not sequestered.

Comment: EPA received some comments asking whether a specific situation results in coverage under 40 CFR part 98, subpart PP, and some comments requesting that their specific situation be exempt from coverage. For example, one commenter asked whether a facility separating CO2that is not supplied to downstream customers is a covered facility. Another asked that a pulp and paper mill that transfers a CO2stream to an adjacent facility by pipeline be exempt from 40 CFR part 98, subpart PP. Several commenters requested clarification on specific scenarios such as taking ownership of an already separated CO2stream for further processing, separating CO2for their own use, and operating versus owning the separation unit.

Response: EPA did not intend for 40 CFR part 98, subpart PP to cover facilities that take ownership of a CO2stream that has already been separated and removed from a manufacturing process or that has already been extracted from CO2production wells in order to do any of the following: Store it in above ground storage of

CO2; transport or distribute it via pipelines, vessels, motor carriers, or other means; purify, compress, or process it; or sell it to other commercial applications. 40 CFR part 98, subpart PP covers facilities that own or operate the equipment that physically separates and removes CO2from an industrial or manufacturing process or physically extracts CO2from production wells because we concluded that the entity with first touch of the CO2supply was the most logical point of coverage. We wanted to minimize any unnecessary duplicative reporting of the same

CO2by being as specific as possible about who in the supply chain is responsible for reporting it.

We did not intend for this source category to include facilities that capture CO2for further processing or use within the fence line of the facility (e.g., for their own use). EPA proposed that 40 CFR part 98, subpart PP only cover CO2that is captured or extracted for purposes of sequestration or supply to other facilities for commercial applications because we concluded that

CO2captured and used on-site is equivalent to an intermediary step in production rather than an actual supply of

CO2.

Comment: EPA received a comment requesting that ethanol plants and other facilities capturing CO2from biomass be exempt from

Subpart PP.

Response: A long standing inventory convention adopted by the IPCC, the UNFCCC, the US GHG Inventory, and many other reporting programs is separate treatment of emissions of CO2from the combustion of biomass and biomass-based fuels from emissions of CO2 from the combustion of fossil-based products. In national inventories, emissions from the combustion of biomass-based fuels are accounted for as part of a comprehensive system-wide tracking of carbon dioxide emissions and sequestration in the land-use, land-use change and forestry sector and the agriculture sector, rather than at the point of fuel combustion. Consistent with this approach, in the proposed and final rule, downstream emitters must only consider non-biogenic emissions when conducting a threshold analysis; however, downstream emitters must report both biogenic and non-biogenic emissions once they trigger the reporting threshold because data on non-biogenic emissions is useful and informative.

For the final rule, EPA has decided not to apply the same approach to

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suppliers of CO2. We have concluded that data on capture of biogenic CO2would be useful and informative because biogenic CO2can potentially be stored in GS sites, or displace fossil CO2applications. We need a full picture of the CO2being supplied into the economy. Though

CO2capture and sequestration is occurring now on a relatively small scale, it is expected to play a major role in mitigating GHG emissions. Therefore information on all potential sources of CO2for sequestration is necessary for a complete picture. Thus, a facility that captures CO2from biomass and otherwise meets the applicability test is covered under 40 CFR part 98, subpart PP and is required to report all CO2supplied along with the percentage of that supply that is biomass-based.

Monitoring and QA/QC Requirements

Comment: A large number of commenters requested that volumetric flow meters be allowed for purposes of calculating CO2 supply in place of or in addition to mass flow meters. These comments indicated that mass flow meters are not in operation at many covered facilities, and the cost to comply with such an equipment requirement would be unnecessarily high. Some commenters suggested that reporters should be allowed to use sales contracts to determine quantity of

CO2as long as the CBI is protected. Some commenters indicated that CO2liquefaction and purification facilities do not operate flow meters for the course of usual business. One of these also commented that importers and exporters of CO2do not operate flow meters for the course of usual business if they handle the product in containers and requested consideration of this incongruity.

Response: As a result of these comments, EPA added two equations to the methodology section of 40 CFR part 98, subpart PP in today's rule in order to ensure that all covered CO2can be reported, irrespective of technical or physical conditions. Therefore, a reporter that measures CO2in a stream using a volumetric flow meter may use this volumetric flow meter to determine quantity rather than having to purchase and install a mass flow meter. EPA has concluded that providing this additional methodology reduces the burden on reporters without compromising the quality of data received by the agency. In addition, a reporter that imports or exports CO2 in containers may use weigh bills, scales, or load cells to determine quantity because applying a mass flow meter would be technically impossible. EPA has concluded that providing this additional methodology reduces the burden on reporters without compromising the quality of data received by the agency.

The final rule does not require reporting from facilities that liquefy or purify CO2that has already been separated or removed from a manufacturing process or already extracted from production wells. Therefore we did not give consideration to the types of equipment in operation at such facilities.

Finally, the rule does not allow reporters to use sales contracts to determine quantity because EPA has concluded that reporters capturing or extracting CO2already operate mass or volumetric flow meters, or already determine quantities of

CO2imported or exported in containers using weigh bills, scales, or load cells. EPA has concluded that mass and volumetric flow meters provide more accurate data than sales contracts.

IV. Mobile Sources

A. Summary of Requirements of the Final Rule

For manufacturers of engines used in mobile sources outside of the light-duty sector,\23\ this rule includes new requirements for reporting emission rates of GHGs.\24\ Mobile source engine manufacturers have been measuring CO2emission rates from their products for many years as a part of normal business practices and existing criteria pollutant emission certification programs, but they have not consistently reported these values to EPA. This final rule requires manufacturers to consistently measure and report

CO2for all engines beginning with model year 2011 and other

GHGs in subsequent model years.\25\ Manufacturers meeting the definitions of ``small business'' or ``small volume manufacturer'' under EPA's existing mobile source emissions regulations will generally be exempt from any new GHG reporting requirements.\26\

\23\ Manufacturers of light-duty vehicles, light-duty trucks, and medium-duty passenger vehicles are not covered in this final rule.

\24\ The term ``manufacturer,'' as well as the term

``manufacturing company,'' as used in this preamble, means companies that are subject to EPA emission certification requirements. This primarily includes companies that manufacture engines domestically and foreign manufacturers that import engines into the U.S. market.

In some cases this also includes domestic companies that are required to meet EPA certification requirements when they import foreign-manufactured engines.

\25\ For aircraft engine manufacturers, reporting requirements will apply for the engine models in production in 2011.

\26\ Small business manufacturers will continue to be subject to measurement and/or reporting requirements for compliance with existing regulations.

In addition to CO2, most manufacturers will now be required to report on two other major GHGs emitted by mobile sources, nitrous oxide (N2O) and methane (CH4). Although most current engines have relatively low emission rates of these GHGs compared to CO2, these compounds have global warming potentials significantly higher than CO2. It is important that EPA improve its understanding of these emissions from today's engines and monitor trends over time. The broad base of emission data that will begin to accrue from requirements in this rule will support emissions modeling by EPA and others, and will help guide future GHG policy.

Emissions of N2O are related to catalytic treatment of engine exhaust, specifically aftertreatment of NOX emissions. Therefore, we will require that manufacturers begin to measure and report N2O emissions, but only for engine models that incorporate NOXaftertreatment technology (as shown in

Table IV-1 of this preamble). The program will not require

N2O reporting before model year 2013, and the requirements will only apply to new engines equipped with NOX aftertreatment technology. (Manufacturers of some engine categories have employed aftertreatment for many years to meet NOX standards; for other engine categories, manufacturers are unlikely to introduce NOXaftertreatment technologies for some years to come.)

Emissions of CH4are a part of overall hydrocarbon emissions from mobile sources. Because CH4is not very reactive in the atmosphere, EPA has often excluded CH4from mobile source hydrocarbon regulations since it has not traditionally been a major determinant of ozone formation.\27\ The new reporting requirements are necessary to evaluate the magnitude of mobile source

CH4emissions from a GHG (rather than ozone precursor) perspective.

\27\ But see Ford Motor Co. v. EPA, 604 F. 2d 685 (D.C. Cir. 1979) (permissible for EPA to regulate CH4under CAA section 202 (b)). In addition, although CH4is not itself regulated, manufacturers subject to ``non-methane hydrocarbon'' standards have needed to determine CH4emission levels, in some cases by using a default value and in many cases by way of testing.

As described above, we are finalizing manufacturer reporting requirements for N2O and CH4emission rates in order to understand current emissions of these GHGs and to monitor potential changes as technologies and policies change in the future.

However, we believe that manufacturers may be able to provide

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alternative test data (and/or other information including engineering judgments based on test data) that would give EPA a reasonable basis for estimating the likely N2O and CH4emission rates for each certified engine family. Therefore, we are including a provision in this final rule that would allow a manufacturer the opportunity to provide such alternative information in lieu of

N2O and/or CH4test data for each engine family.

In assessing such alternative information, EPA would consider how well the information provided by the manufacturer allows EPA to reasonably anticipate the emission performance of each of the manufacturer's engines. For example, we expect that in most cases a manufacturer wishing to omit engine testing will provide EPA with

N2O test data from relevant testing programs (by such sources as industry collaboratives and/or from the suppliers of the catalytic NOXaftertreatment systems they are using on an engine. We would expect the manufacturer to also include an explanation of the manufacturer's engineering judgment as to why the data should apply to the engine family in question. For CH4emissions, our primary concern is the potential for unusually high emissions from natural gas fueled engines. Thus, we expect that in most cases a manufacturer of such an engine will provide test data on similar engines with similar catalyst systems for hydrocarbon control (with an explanation of their engineering judgment as to why the data should apply to that engine family).

The reporting requirements related to C3 marine engines and turbofan and turbojet aircraft engines differ from other engine categories. As with other manufacturers, C3 marine engine and aircraft engine manufacturers will report CO2emission rates beginning in 2011 (for aircraft engines, they will report

CO2separately for each mode of the landing and take-off

(LTO) cycle used in the certification test, as well as the entire LTO cycle). For aircraft engine manufacturers, however, the reporting requirements will apply not just to engines introduced in that year, but for all engines still in production. (This should not require manufacturers to conduct any new testing, only to report existing data.) We are not requiring manufacturers of C3 marine engines and aircraft engines to measure or report N2O or CH4 emission rates because of unique aspects of their industries and technologies.

C3 marine engines are very large and manufacturers generally test them as they are installed into ships rather than in a laboratory setting. For this reason, we have determined that requiring the addition of new N2O and CH4measurement equipment for C3 engines would not be practical, and, as proposed, are not requiring such reporting in this rule.

Since aircraft engine manufacturers are unlikely to employ

NOXafter treatment devices in the foreseeable future, we did not propose requiring N2O reporting from aircraft engines and are not finalizing any requirements in this final rule. We are not finalizing our proposed requirement that aircraft engine manufacturers measure and report CH4, as we learned that aircraft jet turbine engines have been shown to consume CH4 from the ambient air during the dominant operating modes.\28\ However, unlike NOXemissions from most mobile sources,

NOXemissions from aircraft have been shown to make a potential contribution to climate change.\29\ For this reason, we are requiring that aircraft engine manufacturers report the NOX emission data for the LTO modes and the overall LTO cycle for all engine models currently in production, and for new engines as they are introduced. Manufacturers are already measuring NOXas part of current criteria pollutant certification requirements.

NOXemissions rate data from LTO modes will support modeling of overall NOXemissions from aircraft.

\28\ Aerodyne, Rich Miake-Lye, AAFEX Methane presentation at the

Seventh Meeting of Primary Contributors for the Aviation Emissions

Characterization Roadmap, June 9-10, 2009.

\29\ IPCC, Aviation and the Global Atmosphere, 1999, at http:// www.grida.no/climate/ipcc/aviation/index.htm, and NOAA, Written

Testimony of Dr. David W. Fahey, Hearing on ``Aviation and the

Environment: Emissions,'' Before the Committee on Transportation and

Infrastructure, Subcommittee on Aviation, U.S. House of

Representatives, May 6, 2008.

For all engine categories, when a manufacturer certifies the engine in one year and then carries over the certification to subsequent years, EPA will not require re-testing of that engine model for reporting purposes.

As proposed, we are not including any requirements for mobile source fleet operators or State and local governments to report in-use travel activity or other emissions-related data in this final rule.

Table IV-1 of this preamble shows the basic reporting requirements we are finalizing in this notice for each engine category. We discuss in more detail how these reporting requirements will apply to manufacturers of each engine category in ``Mandatory Greenhouse Gas

Reporting Rule: EPA's Response to Public Comments, Motor Vehicle and

Engine Manufacturing.''

Table IV-1--First Model Year for GHG Reporting Requirements

Engine category

CO2

N2O\a\

CH4

Highway Heavy-Duty (engine and

2011 2013 or NOX AT...........................

2012 vehicle).

Nonroad Diesel.......................

2011 2013 or NOX AT...........................

2012

Marine Diesel (other than C3)........

2011 2013 or NOX AT...........................

2012

C3 Marine............................

2011 None.....................................

None

Locomotives..........................

2011 2013 or NOX AT...........................

2012

Small Spark-Ignition.................

2011 2013 or NOX AT...........................

2012

Large Spark-Ignition.................

2011 2013 or NOX AT...........................

2012

Marine Spark-Ignition................

2011 2013 or NOX AT...........................

2012

Snowmobiles..........................

2011 2013 or NOX AT...........................

2012

Highway Motorcycles..................

2011 2013 or NOX AT...........................

2012

Off Highway Motorcycles/ATVs.........

2011 2013 or NOX AT...........................

2012

Aircraft \b\.........................

2011 None.....................................

None

\a\ N2O reporting for new engines begins in 2013 or when the manufacturer introduces NOX aftertreatment technology, whichever is later.

\b\ Applies to all turbofan and turbojet engines in production in 2011 with a rated output greater than 26.7 kilonewtons. Reporting of NOX also required.

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B. Summary of Major Changes Since Proposal

Response to Public Comments, Motor Vehicle and Engine Manufacturers.''

We are not finalizing the proposed requirements related to light-duty vehicles (including light-duty trucks and medium-duty passenger vehicles). EPA expects to propose a comprehensive light-duty

GHG emission control program commencing in MY 2012 (see Notice of

Upcoming Joint Rulemaking to Establish Vehicle GHG Emissions and CAFE

Standards, 74 FR 24007 (May 22, 2009)), which is likely to contain monitoring, reporting and GHG data retention requirements that would supersede any reporting requirements established in this rule.

Eliminating light-duty reporting requirements from this final rule will avoid issues of inconsistency and duplication.

We have revised our proposal that all engine manufacturers measure and report N2O for all of their engines, and instead will require N2O reporting only for engines that use

NOXexhaust aftertreatment technology.

We have delayed the proposed MY 2011 start year for

N2O reporting until MY 2013, and later for categories where the manufacturer has not applied NOXaftertreatment technology.

We have added additional emission test methods that manufacturers can choose for measuring N2O, to assure that an appropriate method is available for any foreseeable circumstance

(including the need to measure very low N2O emission rates).

The final rule incorporates an opportunity for a manufacturer to provide EPA with appropriate alternative information in lieu of N2O and/or CH4testing, as described above.

We have added one year of lead time to the proposed start year for reporting of CH4emissions, until 2012.

We are not finalizing our proposal to require reporting of

CH4for aircraft engines because, for the dominant operating modes, jet engines may consume CH4in the air.

We are finalizing a requirement that we took comment on in the proposal to have aircraft engine manufacturers report

NOXemissions data they already collect, since, at altitude,

NOXemissions from aircraft have been shown to make a potential contribution to climate change.

Since aircraft engines are not certified every year (there is no annual certification as is the case with other mobile sources), we have removed references to ``model year'' in the regulations and revised them to reflect the change to a January 1, 2011 start date for reporting CO2and NOXemissions.

C. Summary of Comments and Responses

This section contains a brief summary of major comments and responses. A large number of comments on mobile source were received covering numerous topics. Responses to significant comments received can be found in ``Mandatory Greenhouse Gas Reporting Rule: EPA's

Response to Public Comments, Motor Vehicle and Engine Manufacturers.''

Comment: Light-duty vehicle manufacturers and their trade organizations raised several concerns about the timing and nature of the reporting requirements.

Response: We agree in part with these comments. However, more fundamentally, we have concluded that the likelihood of GHG emission regulations affecting light-duty vehicles (including light-duty trucks and medium-duty passenger vehicles) in the near future argues for consolidating any new GHG reporting requirements into that upcoming rule. Therefore, we have elected to not finalize the proposed requirements relating to these vehicles at this time, and expect to incorporate similar provisions in a proposed rule on GHG standards for light-duty vehicles in the near future.

Comment: Engine manufacturers and their trade organizations challenged the proposed rule in several ways. In general, they questioned the need for the data to be reported; expressed concern that the proposed timing of the requirements, especially for N2O and CH4, was too aggressive; and commented that the proposed test procedure for N2O was not adequate.

Response: We still conclude that there is significant value to collecting CO2, N2O, and CH4emissions rate data on the broad range of mobile sources being produced. As stated earlier, the domestic and international attention to GHGs and their effects will only grow, and the ability for EPA and the public to understand and monitor emissions from mobile sources will be increasingly important as policies relating to GHGs are considered.

Collecting emissions rate data from engine manufacturers on their new engines can improve modeling of emissions for the entire mobile source sector since current modeling relies on assumptions about

N2O and CH4emissions based on a limited number of field surveys. The data from this rule will also help EPA track emissions impacts from changes in technologies and policies over time.

For N2O and CH4, we agree that revisions in the proposed provisions are warranted. We have limited the reporting requirements for N2O to engines equipped with NOX aftertreatment technology as a way to reduce the reporting burden on engine manufacturers without significantly diminishing the amount of information we receive. As discussed earlier, emissions of

N2O are related to catalytic treatment of engine exhaust, specifically aftertreatment of NOXemissions, and we have concluded that collecting N2O emissions data from engines without NOXaftertreatment technology would provide marginal value to the agency. We expanded the number of approved test methods for N2O measurement since we learned from comments and our own technical research that our proposed test methods for

N2O were not appropriate for every foreseeable circumstance, including measurement of very low levels of N2O. We also extended the lead time available to manufacturers before N2O and CH4reporting is required. We are providing this flexibility based on our conclusion that we can reduce the burden of purchasing and installing the required CH4and

N2O emissions rate measurement equipment by extending the lead time, without significantly diminishing the amount of information we receive. Finally, as described above, the final rule includes an opportunity for a manufacturer to provide EPA with appropriate alternative information in lieu of N2O and/or CH4 testing.

Comment: States and environmental organizations were generally supportive of the proposed reporting requirements, although some argued for earlier implementation, in 2010.

Response: We believe that the lead times we are finalizing for each

GHG and for each engine category represent the earliest feasible timing, taking into consideration existing test capabilities and past experience, or the lack thereof.

Comment: Aircraft engine manufacturers commented that reporting of

CO2emissions from each mode of the LTO \30\ cycle used in the emission certification test, as proposed, is acceptable as long as existing methods for CO2are retained. In particular, commenters noted that reporting would result in minimal

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burden as long as CO2is calculated utilizing the engine fuel mass flow rate measurements, which are currently part of the test procedure requirements for the LTO cycle. However, an industry trade association expressed concern that reporting CO2from the

LTO cycle is unjustified because LTO measurements do not include

CO2emissions from an entire aircraft flight, which is affected by the propulsion system, drag, etc.

\30\ Modes of the landing and takeoff cycle are taxi/idle, takeoff, climb out, and approach.

Response: We determined that calculating aircraft engine

CO2emissions from fuel mass flow rate measurements is an appropriate method for reporting CO2emissions. Therefore, for turbofan and turbojet engines of rated output greater than 26.7 kilonewtons, we are finalizing that manufacturers report CO2 separately for each mode of the LTO cycle by calculation of

CO2from fuel mass flow rate measurements or, alternatively, according to the measurement criteria for CO2in Appendices 3 and 5 to ICAO Annex 16, volume II. Comprehensive and consistent reporting of LTO CO2emissions, along with knowledge of aircraft aerodynamic performance, will support modeling of full-flight

CO2emissions and help us to better understand overall contributions to global warming from aircraft operations.

Comment: Aircraft engine manufacturers raised two major issues related to our proposed CH4reporting. First, in response to

EPA's request for comment on the degree to which engine manufacturers now have the needed equipment in their certification test cells to measure CH4,manufacturers replied that test stands are not currently equipped to measure CH4, and thus, they would incur additional costs to measure CH4. Second, manufacturers noted that aircraft jet turbine engines have been shown to be consumers of CH4from the ambient air during the dominant operating modes (CH4is emitted at aircraft engine idle operation, but at higher power modes aircraft engines usually consume CH4.

Over the range of engine operating modes--including cruise--aircraft engines are typically net consumers of CH4).

Response: Given that aircraft engines are likely net consumers of

CH4and that manufacturers do not currently collect

CH4data as part of existing test procedures, we are not requiring CH4to be measured and reported at this time.

Comment: We received several responses to our request for comment on whether to require aircraft engine manufacturers to report

NOXemissions in the four LTO test modes and for the overall

LTO cycle. Manufacturers commented that NOXemissions do not need to be reported directly to EPA, since this information is already voluntarily reported to the International Civil Aviation Organization

(ICAO) and provided to the Federal Aviation Administration (FAA), and redundancy of reporting is unnecessary. Environmental organizations commented that EPA should require manufacturers to report

NOXsince they currently do not report the data to EPA. In addition, environmental organizations commented that NOXat high altitude can contribute to global warming.

Response: In this final rule, we are requiring that engine manufacturers of turbofan and turbojet engines of rated output greater than 26.7 kilonewtons record and report NOXemissions in the four LTO test modes and for the overall LTO cycles. As discussed in the proposal and earlier in this final rule, NOXfrom aircraft have been shown to make a potential contribution to climate change at high altitude. As required in 40 CFR part 87, manufacturers must already measure and record NOXemissions in each of the four

LTO test modes in order to comply with the LTO NOXemission standard (for the entire LTO cycle). These data are not currently reported to EPA for public consideration as is the case with all other mobile sources. Manufacturers voluntarily report the data to ICAO, but there is no assurance that EPA will receive this information. Likewise, the information provided to FAA is not readily accessible to EPA, and it is not of the detail provided to ICAO. Comprehensive and consistent reporting of LTO NOXemissions rate data will support modeling of overall NOXemissions from aircraft and help us to better understand overall contributions to global warming from aircraft operations.

V. Collection, Management, and Dissemination of GHG Emissions Data

This section of the preamble describes the general processes by which EPA intends to collect, manage, and disseminate data under the

GHG reporting rule. Section A contains a brief description of the provisions in the final rule concerning these processes, and Section B summarizes public comments and responses on data collection, management, and dissemination.

Major changes since proposal include revisions in 40 CFR 98.4 that provide flexibility for designated representatives to delegate their responsibility to agents, and to submit revisions to the certificate of representation within 90 days of a change in owners or operators

(rather than 30 days). In addition, the final rule includes a requirement that the designated representative submit the certificate of representation at least 60 days before the deadline of the facility or supplier's initial GHG report. The rationale for these and any other significant changes can be found in Section V.B of this preamble or in

``Mandatory Greenhouse Gas Reporting Rule: EPA's Response to Public

Comments, Designated Representative, and Data Collection, Reporting,

Management, and Dissemination.''

A. Summary of Data Collection, Management and Dissemination for the

Final Rule 1. Designated Representatives, Alternate Designated Representatives, and Agents

Each covered facility and each supplier must identify one and only one designated representative who is responsible for certifying, signing, and submitting all submissions to EPA. A designated representative must certify and sign a submission, in accordance with the final rule, before it is considered a complete submission.

The designated representative also serves as a single point of contact for EPA to provide information about the program or a submission or to ask questions about a submission. Those facilities submitting any other emission report under 40 CFR part 75, for example,

ARP facilities, must use the same designated representative for certifying, signing and submitting all submissions and reports under this rule.

Each covered facility or supplier may also identify one alternate designated representative to act in lieu of the designated representative. The alternate designated representative can perform the same duties as the designated representative, but the designated representative is responsible for ensuring the appropriate information is submitted to EPA by the timelines specified in the rule.

A designated representative or alternate designated representative may delegate the submission of information to one or more ``agents.''

The agent can make electronic submissions to EPA, but is not allowed to certify or sign a submission. By delegating to an agent the ability to make electronic submissions to EPA, a designated representative or alternate designated representative agrees that a submission to EPA by the agent is deemed to be a submission that is certified, signed, and submitted by such designated representative or alternate designated representative.

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2. Certificate of Representation

A designated representative must submit a certificate of representation that identifies the owners and operators of the facility or supplier, the designated representative, any alternate designated representative, and other information as specified in 40 CFR 98.4. EPA will establish an electronic data reporting system that provides for the submission of initial, as well as subsequently signed, certificates of representation.

In order to ensure sufficient processing time before a facility or supplier's initial GHG report under this part, EPA is requiring that the designated representative submit a certificate of representation at least 60 days before the deadline for the initial GHG report. 3. Data Collection

Methods. If a reporting entity already reports GHG emissions data to an existing EPA program, the Agency will make efforts to minimize any additional burden on the reporter when developing the reporting system for the final rule. Some existing programs, however, have data collection and reporting requirements that are inconsistent with the requirements for the mandatory GHG reporting rule. When it is not feasible to adapt an existing program to collect the appropriate GHG data and supplemental data, EPA will require reporters to submit the data required by the mandatory GHG reporting rule to the new data reporting system for this rule. Such reporters would also continue to submit data to the existing reporting systems for other applicable programs as required by those programs.

Reporters may fall into one or more categories:

(1) Reporters that use existing data collection and reporting methods and will not be required to report separately to the new data reporting system for the GHG reporting rule.

(2) Reporters that use existing data collection and reporting methods but will be required to report the data separately to the new data reporting system for the GHG reporting rule.

(3) Reporters that are not currently required to collect and report

GHG emissions data to EPA and will be required to report using the new data reporting system for the mandatory GHG reporting rule.

For categories (2) and (3), EPA is developing a new system for reporters to submit the required data. The detailed data elements that must be reported are specified in the rule. In general, reporters using this new system must report annually to the Agency according to the schedule specified in 40 CFR 98.3(b).

Data Submission. The Designated Representative (described in 40 CFR 98.4) must use an electronic signature device (for example, a personal identification number (PIN) or password) to submit a report. If the

Designated Representative holds an electronic signature device that is currently used for valid electronic signatures accepted under another

Agency program, we intend to design the new reporting system to also accept valid electronic signatures executed with that device where feasible. (See 40 CFR 3.10 and the definitions of ``electronic signature device'' and ``valid electronic signature'' under 40 CFR 3.3.)

Unique Identifiers for Facilities and Units. The Agency's reporting format for a given reporting year could make use of several ID codes-- unique codes for a unit or facility. To ensure proper matching between databases, e.g., EPA-assigned facility ID codes and the Office of

Regulatory Information Systems (ORIS) (DOE) ID code, and consistency from one reporting year to the next, we plan for the reporting system to provide each facility with a unique identification code to be specified by the Administrator.

Reporting Emissions in a Single Unit of Measure. To maintain consistency with existing State-level and Federal-level GHG programs in the U.S. and internationally, all emission measurements must be reported in the SI, also referred to as metric units. Data used in calculations and supplemental data for QA could still be submitted in

English weights and measures (e.g., mmBtu/hr) but the specific units of measure must be included in the data submission. All emissions data must be submitted to the Agency in kg or metric tons per unit of time.

Conversion of Emissions to CO2e. Reporters must submit the quantity of each applicable GHG emitted (or other metric such as quantities supplied for industrial GHG suppliers) in two forms. The data will be in the form of quantity of the gas emitted (e.g., metric tons of

N2O) per unit of time and CO2e emissions per unit of time.

Delegation of Authority to State Agencies to Collect GHG Data.

Reporters must submit the emissions data and supplemental data directly to EPA. At this time, EPA does not intend to delegate the authority to collect data to State or local agencies.

Submission Method. All entities covered by this rule must report in an electronic format to be specified by the Administrator. The electronic format, which will reflect the underlying electronic data reporting system, will be developed prior to the first reporting date.

By specifying in the rule text the exact information that must be reported but not specifying the exact reporting format, EPA informs reporters about exactly what information they must report and has flexibility to modify the electronic reporting format and electronic data reporting system in a timely manner based on implementation experience and new technology. EPA has used this approach successfully in existing programs, such as the ARP and the Title VI Stratospheric

Ozone Protection Program, facilitating the deployment of new reporting formats and reporting systems that take advantage of technologies such as, eXtensible Markup Language (XML), and reducing the burden on reporters and the Agency. The electronic reports submitted under this rule are subject to the provisions of 40 CFR part 3, specifying EPA systems to which electronic submissions must be made and the requirements for valid electronic signatures. 4. Data Management

QA Procedures. The new reporting system will include automated checks for data completeness, data quality, and data consistency. Such automated checks are used for many other Agency programs (e.g., ARP).

Providing Feedback to Reporters. EPA has established a variety of mechanisms under existing programs to provide feedback to reporters who have submitted data to the Agency. EPA will consider the approaches used by other programs (e.g., electronic confirmations, results of QA checks) and develop appropriate mechanisms to provide feedback to reporters for the GHG reporting rule when we develop the electronic data reporting system. Regardless of data collection system specifics, the goal is to ensure appropriate transparency and timeliness when providing feedback to reporters who submitted data. 5. Data Dissemination

Public Access to Emissions Data. The Agency plans to publish data submitted or collected under this rulemaking through EPA's Web site, reports, and other formats (e.g., XML), with the exception of any confidential business information (CBI) data. For further discussion of

CBI, see Section II.R of this preamble.

EPA will disseminate data after the reporting deadline. The Agency recognizes the high level of public interest in this data and plans to disclose it in a timely manner, while

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also assuring completeness and accuracy.

Sharing Emission Data with Other Agencies. There are a growing number of programs at the State, Tribe, Territory, and local level that require emission sources in their respective jurisdictions to monitor and report GHG emissions. In order to be consistent with and supportive of these programs and to reduce burden on reporters and program agencies, EPA plans to share emissions data, with the exception of any

CBI data, with relevant agencies or approved entities using, where practical, common data exchange standards and infrastructure.

B. Summary of Comments and Responses on Collection, Management, and

Dissemination of GHG Emissions Data

This section contains a brief summary of major comments and responses. A large number of comments on data collection, management, and dissemination were received covering numerous topics. Responses to significant comments received can be found in ``Mandatory Greenhouse

Gas Reporting Rule: EPA's Response to Public Comments, Designated

Representative and Data Collection, Reporting, Management, and

Dissemination.'' 1. Designated Representatives, Alternative Designated Representatives, and Agents

Designated Representatives

Comment: Several commenters requested that EPA use the ARP definition for designated representatives to maintain consistency across the two EPA programs and provide more flexibility regarding who can be a designated representative. Other commenters requested that EPA use the responsible official definition from Title V or senior management official from TRI to maintain consistency with those programs. Other commenters raised concerns over the employment status of designated representatives.

Comment: A commenter noted that rule language was inconsistent in defining the relationships between designated representatives, facilities and suppliers, and owners and operators.

Response: EPA agrees that owners and operators should have more flexibility to identify a designated representative, including third- party representatives. EPA is striking the language requiring the designated representative to be a person responsible for the overall operation of the facility or supplier. Further, EPA is not requiring the use of a responsible official or senior management official because either approach would be more restrictive than the designated representative definition of the final rule. EPA believes that the proposed rule was neutral with respect to the employment status of the designated representative. The final rule provides flexibility for the owners and operators to choose any individual, employee or non- employee, to represent them. EPA modified the rule to clarify that each facility and each supplier shall have one and only one designated representative and that the designated representative must be authorized by binding agreement of the owners and operators.

Agents

Comment: Several commenters requested that EPA allow designated representatives and alternate designated representatives the option of delegating their responsibility to prepare and submit reports to EPA to a preparer or agent. Commenters also stated that the designated representative requirement is inconsistent with Title V reporting.

Response: EPA agrees that it is beneficial to give the designated representatives and alternate designated representatives flexibility concerning who prepares the reports that they are responsible for submitting. The final rule does not specify who must prepare reports, but only specifies who must certify, sign, and submit them. EPA also agrees that flexibility should be provided concerning who actually submits the reports, similar to the flexibility provided in the ARP.

This flexibility was implied in the provision in the proposed rule that reports be submitted ``in a format specified by the Administrator,'' which format has included, in other programs such as the ARP, the ability to use agents. However, EPA decided to make this flexibility explicit by including in the rule provisions allowing and setting requirements for agents selected by designated representatives or alternate designated representatives. The structure of designated representative, alternate designated representative and agent fits a wide range of circumstances from large companies to small, including those accustomed to reporting under Title V.

Certification Statement

Comment: Several commenters described the self-certification procedures in the proposed rule as too restrictive or suggested that the rule should be consistent with requirements of the Title V or TRI program. For example, the rule's requirement that the designated representative certify that they have ``personally examined'' the data should be replaced by the Title V requirement that a responsible official certify that they have made a ``reasonable inquiry'' as to the accuracy of the data.

Response: EPA believes that the high level of public interest in the data collected under this rule, as well as its importance to future policy, warrants establishment, by rule pursuant to CAA Sections 114, 208, and 301(a)(1), of a high standard for data quality and consistency and a high level of accountability for reported data, which will help ensure that the data quality and consistency standard is met. The certification requirements set forth in this rule are similar to the

ARP (Title IV). EPA has successfully implemented this approach in the

ARP and found that it provides a high degree of both data quality and consistency and accountability. 2. Certificate of Representation

Comment: One commenter requested that EPA designate a deadline for the submission of the certificate of representation to ensure sufficient time to process the submissions.

Response: EPA agrees that an earlier deadline for submitting certificates of representation is advisable to provide additional lead time to process the certificates and, if necessary, verify identities and resolve issues. Because any delay in processing a certificate of representation could delay the submission of data, EPA is requiring that the designated representative submit the initial certificate of representation at least 60 days prior to the deadline for a facility or supplier's initial GHG report.

Comment: Several commenters noted that a certificate of representation for each facility and supplier is burdensome either due to timing with the annual report, the need to maintain current information, or ambiguities as to whether the certificate is complete.

Commenters also requested that reporters be allowed more than 30 days to submit a revised certificate of representation in the event of a change in operators or owners.

Comment: Several commenters requested that EPA provide an electronic system for submitting and processing certificates of representation.

Response: EPA does not agree that certificates of representation are unnecessary or overly burdensome or that there should be any uncertainty as to whether a certificate of representation is complete.

The information required on the certificate of representation is

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listed in the rule and should be well known to the owners and operators of the facility or supplier. It is the responsibility of the individual submitting the certificate to ensure its completeness. This certificate of representation has been used successfully for over a decade in the

ARP.

To minimize burden, the electronic data reporting system will provide the means to electronically submit both the initial and any subsequent certificate of representation. EPA agrees that reporters should be allowed more time to update changes in owners or operators but does not agree that doing so in the annual report is sufficient.

The designated representative is the primary point of contact between the owners and operators and the EPA. However, the owners and operators are ultimately responsible for compliance with the requirements of reporting rule, and it is therefore essential that the information in the certificate of representation be timely and accurate in the event

EPA finds it necessary to contact the owners and operators of the facility or supplier during periods in between the submission dates of the annual reports, for example, to perform an audit. The final rule allows reporters up to 90 days to submit a revised certificate of representation when a change in owners or operators occurs. In addition, EPA modified both the owner definition and rule to clarify that the certificate of representation does not need to list persons whose legal or equitable title to or leasehold interest in a facility or supplier arises solely because they are limited partners in a partnership with legal or equitable title to, a leasehold interest in, or control of, the facility or supplier. 3. Data Collection Methods

Comment: Several commenters requested that EPA use current emission inventory reporting programs (e.g., NEI) to handle data collection or to sunset the GHG reporting rule, and instead use such programs, after five years.

Response: EPA is requiring electronic reports to be submitted directly to EPA using a new data reporting system for the GHG reporting rule. The rationale for the decision to report directly to EPA is contained in Sections II.N (emissions verification) and VI.B

(compliance and enforcement) of this preamble. EPA recognizes the value of integrating the GHG data reported under this rule with other emission reporting programs. NEI, for example, plans to incorporate the

GHG emissions data from this collection, as feasible.

Comment: Commenters requested that the design of the new data system be modeled on existing electronic reporting programs, incorporate measures to handle system errors, and provide opportunities for testing and user training.

Response: EPA agrees that a national electronic emissions database should be the basis for receiving GHG data, and that the ARP database provides a useful model for a future GHG emissions database. Data would be provided to EPA electronically to reduce the burden on the reporters and EPA, and to increase the accuracy of the reported emissions, among other reasons. The issue of transmission failures and transmission errors will be addressed in the development of the electronic reporting system. EPA agrees that is it important for data reporters to be able to confirm that their data were accepted by the system and to compare the data in the system to the data that they reported to ensure it was accurately incorporated into the database. The new data system will meet Agency requirements for security and hosting. EPA acknowledges comments supporting a ``user friendly'' reporting system. EPA plans to follow well known design practices within the constraints of security, accessibility and Agency design requirements.

EPA agrees with commenters on the need for testing and user training. We will continue the outreach effort undertaken during this rulemaking to encourage stakeholder participation in `beta' testing and training opportunities.

Unique Identifiers for Facilities and Units

Comment: Several commenters requested that EPA assign and track corporate identifiers for reporting facilities to facilitate corporate- level analysis of emission data. Commenters also requested that EPA publish a list of identifiers for all EPA programs that a covered facility may report to.

Response: EPA is collecting owner and operator information through the Certificate of Representation (40 CFR 98.4). At this time, EPA is not proposing to assign unique identifiers to the owners and operators because of the complexity of ownership structures (including percentage shares of owners, subsidiaries, holding companies, and limited liability partnerships) that can be used in the multiplicity of industrial sectors required to report emission data under this rule.

Although as explained earlier in the preamble, we are exploring options for adding additional data elements to the reports, such as name of parent company and NAICS code(s), to allow easier aggregation of facility-level data to the corporate level under this program. EPA expects to subject any additional requests to notice and comment rulemaking.

EPA's Facility Registry System (FRS) links EPA program identification numbers under a unique facility record. The FRS database is publicly available to queries from the EPA.GOV Web site under the

Envirofacts Data Warehouse home page: http://www.epa.gov/enviro/html/ fii/fii_query_java.html. Descriptive information about FRS can be found at: http://www.epa.gov/enviro/html/fii/index.html. FRS may be searched by program identification, facility name or geographic location. The Agency will continue to make FRS and all program identification numbers readily available and will include the facilities reporting under this rule in the FRS collection of program

ID's once public release of the data is authorized.

Submission Method

Comment: Several commenters requested that EPA specify the format of the data collection methods and subject it to public comment before finalizing the rule. These commenters indicated that without the details of the data collection methods it was not possible to evaluate the GHG reporting rule, including implementation costs and reporting burden.

Response: The final rule requires reports to be submitted ``in a format specified by the Administrator.'' EPA is thereby retaining the flexibility to specify the electronic format, and the underlying electronic reporting system reflected in the format, after promulgation of this rule but well before the first reporting deadline and, if necessary, to change the electronic format and electronic reporting system based on implementation experience and new technology. Several other reporting programs (e.g., ARP) use a similar approach where the specific electronic reporting system is not included within the rule or subjected to formal notice and comment. The relevant subparts of the proposed GHG reporting rule specified the data elements that each entity must report, and therefore parties could evaluate the reporting burden and costs under the proposed rule and had an opportunity to comment on that aspect of the proposed rule. In addition, before specifying the electronic format and underlying electronic reporting system, EPA will conduct outreach and provide opportunities for stakeholder feedback on the specific reporting format and reporting system.

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Mandatory Reporting of Greenhouse Gases

Continued from page 56358

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Comment: Several commenters requested that EPA provide alternative methods to report emission data, including paper submissions, scanned documents, and direct data upload.

Response: EPA is requiring electronic reporting of the GHG and supplemental data to increase the accuracy and timeliness of the reported emission data and is not providing options for paper or scanned GHG reports. Requiring electronic submission of data allows EPA to conduct electronic QA testing of all such data when it is received and to provide electronic feedback to the reporters almost instantaneously. This gives reporters the opportunity to correct any errors, or to provide explanations of potentially problematic data, within a short time frame, thereby increasing the accuracy and timeliness of the data. Moreover, electronically submitted data can be readily sorted and analyzed by EPA and members of the public. In contrast, submission of hardcopy data (whether in paper or scanned documents) would make audit and correction, as well as sorting and analysis, of the data much more cumbersome, inefficient, and time consuming. Indeed, particularly in light of the large number of facilities and suppliers that will be reporting and the large amounts of reported data that will be received as a result, the ability to audit and analyze the data received in hardcopy format would likely be significantly limited. This would adversely affect the usefulness, as well as the accuracy and timeliness of the data.

In requiring electronic data submission, EPA will provide a Web- based reporting system to guide reporters through the data entry, emission calculation, and submission process. This reporting system will conform to EPA information technology standards and 40 CFR part 3.

In addition, EPA will provide a mechanism for reporters to submit data files directly to EPA using a standard format (e.g., XML) to be prescribed by the Administrator before the first reporting date. To reduce the burden on reporters and reduce errors, EPA will conduct outreach and training for reporters on the reporting format and underlying reporting systems. EPA will also provide a hotline to answer questions about the program and reporting format and reporting systems.

EPA expects that most reporters affected by this rule are already familiar with Web-based or electronic reporting systems through other

EPA programs.

Delegation of Authority to State Agencies To Collect GHG Data

Comment: Several commenters requested that EPA delegate rule implementation, including data collection, to State and local agencies.

These commenters indicated that several States already have GHG reporting requirements and have systems in place to collect and verify this data, and suggested that delegation of the rule could help reduce inconsistency or duplication of effort between State programs and this

Federal mandatory GHG reporting rule. Other commenters supported requiring facilities to submit data directly to EPA, without delegation of data collection to State and local agencies, in order to provide national consistency.

Response: EPA is requiring electronic reports to be submitted directly to EPA, and is not delegating data collection to State and local agencies. The rationale for this decision is provided in Section

VI.B of this preamble. 5. Data Dissemination

Public Access to Emissions Data

Comment: Several commenters supported EPA's proposal to make the data submitted under the reporting rule available to the public. Some requested that data be published in real time, while others requested the data be released in a timely manner.

Response: With the exception of CBI, EPA intends to make data submitted under this program available to the public in a timely manner after the reports have been submitted and EPA has completed QA/QC of the data. To that end, EPA intends to establish a new reporting system that will accept electronic submissions of GHG emissions and supporting data and facilitate EPA's verification of the submissions. EPA plans to provide public access to the data by posting electronic data on a Web site in a timely manner after the reporting deadline. This level of transparency is important to public participation in future policy development and for building public confidence in the quality of the data collected.

Sharing Emissions Data With Other Agencies

Comment: Some commenters stressed that electronic data reporting systems need to be consistent and inter-operable and allow data exchange between TCR, State rules, NEI, ARP, other stakeholders and

EPA.

Response: EPA will continue to coordinate with other Federal,

State, and regional programs and will make efforts to facilitate data exchange when designing the data reporting system that will be used for the GHG reporting rule. EPA intends to employ inter-operable data exchange standards. EPA intends to design and manage the GHG data collection to take advantage of existing efforts on data exchange standards and to work with stakeholder groups to promote the easy exchange and sharing of the data collected under this rule. For example, EPA is extending the Consolidated Emissions Reporting Schema

(CERS), currently in use by the EPA's NEI program, to support data reporting and publication under this rule. EPA also intends to use existing tools, such as FRS and SRS, to ensure data consistency.

To the extent possible, EPA will consider existing reporting systems and work with those programs and systems to develop a reporting scheme that facilitates data exchange. EPA anticipates that this coordination will reduce the burden of reporting for both reporters and government agencies. However, as explained in Section II.O of this preamble, the various reporting programs do not have identical data needs and requirements. Therefore, at this time, it is not possible for companies reporting under State and Federal rules and voluntary programs to file a single report that will satisfy all reporting requirements.

Comment: Commenters requested that the data system utilize common standards, such as XML and geographic identifiers, and provide descriptive text wherever codes or abbreviations are used.

Response: EPA agrees that publishing the results of this data collection using common, standards-based schemas and formats will promote the exchange of data between EPA, States and other entities.

The published results will include the latitude and longitude of facilities as well as help text with definitions of codes and abbreviations.

VI. Compliance and Enforcement

This section of the preamble generally describes the compliance assistance and enforcement activities EPA intends to implement for the

GHG reporting rule and summarizes public comments and responses on compliance assistance, role of the States, and enforcement.

A. Compliance and Enforcement Summary 1. Compliance Assistance

EPA plans to conduct an active outreach and technical assistance program following publication of the final rule. The primary audience is

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potentially affected industries. We intend to develop implementation and outreach materials and training to help potential reporters understand whether the rule applies to them and explain the reporting requirements and timetables. The program particularly will target industrial, commercial, and institutional sectors that do not routinely deal with air pollution regulations.

Compliance materials will be tailored to the needs of various sectors. These materials might include, for example, fact sheets, information sheets, plain English guides, frequently asked question and answer documents, applicability tools, monitoring and recordkeeping checklists, and training on rule requirements and the electronic reporting system. We also expect to implement a compliance assistance e-mail and telephone hotline for answering questions and providing technical assistance. Note that while EPA plans to issue compliance assistance materials, reporters should always consult the final rule to resolve any ambiguities or questions. 2. Role of the States

While EPA does not intend to formally delegate data collection and enforcement of the GHG reporting rule to State agencies, EPA will likely enlist State assistance, when it is available, for outreach and compliance assistance with the final rule. (However, State and local agencies will not be required to provide EPA any assistance with these activities, given State and local agency resource constraints and priorities.). State and local air pollution control agencies routinely interact with many of the sources that would report under this rule.

Further, several States have experience implementing State mandatory

GHG reporting and reduction programs. Therefore, we plan to work with those State and local agencies that are able to assist EPA to define their role in communicating the requirements of the rule and providing compliance assistance. In concert with their routine inspection and other compliance and enforcement activities for other CAA programs,

State and local agencies may also be able to assist with educating facilities and assuring compliance at facilities subject to this rule. 3. Enforcement

Facilities or suppliers that fail to monitor or report GHG emissions, quantities supplied, or other data elements according to the requirements of the applicable rule subparts could potentially be subject to enforcement action by EPA under CAA sections 113 and 203- 205. The CAA provides for several levels of enforcement that include administrative, civil, and criminal penalties. The CAA allows for injunctive relief to compel compliance and civil and administrative penalties of up to $37,500 per day per violation.\31\

\31\ The Federal Civil Penalties Inflation Adjustment Act of 1990, Public Law 101-410, 104 Stat. 890, 28 U.S.C. 2461, note, as amended by Section 31001(s)(1) of the Debt Collection Improvement

Act of 1996, Public Law 104-134, 110 Stat. 1321-373, April 26, 1996, requires EPA and other agencies to adjust the ordinary maximum penalty that it will apply when assessing a civil penalty for a violation. Accordingly, EPA has adjusted the CAA's provision in

Section 113(b) and (d) specifying $25,000 per day of violation for civil violations to $37,500 per day of violation.

Actions (or inactions) that could ultimately be considered violations include but are not limited to the following:

Failure to report GHG emissions (for suppliers, the emissions that would result from combustion or use of the products they supply).

Failure to collect data needed to calculate GHG emissions.

Failure to continuously monitor and test as required. Note that merely filling in missing data as specified does not excuse a failure to perform the monitoring or testing.

Failure to calculate GHG emissions according to the methodology(s) specified in the rule.

Failure to keep required records needed to verify reported

GHG emissions.

Falsification of reports.

B. Summary of Public Comments and Responses on Compliance and

Enforcement

This section contains a brief summary of major comments and responses. A large number of comments on compliance and enforcement were received covering numerous topics. Responses to significant comments received can be found in ``Mandatory Greenhouse Gas Reporting

Rule: EPA's Response to Public Comments, Compliance and Enforcement.'' 1. Role of States in Compliance and Enforcement

Comment: Several commenters requested that EPA delegate rule implementation, including data collection, emissions verification, and enforcement of the rule to State and local agencies. These commenters indicated that several States already have GHG reporting requirements and have systems in place to collect and verify these data, and they suggested that delegation of the rule could help reduce inconsistency or duplication of effort between State programs and this Federal mandatory GHG reporting rule. However the majority of commenters, including industry, environmental organizations, and many public citizens supported requiring facilities to submit data directly to EPA, without delegation of data collection or emissions verification to

State and local agencies, in order to provide national consistency.

Response: Section 114(b) of the CAA allows EPA to delegate to

States the authority to implement and enforce Federal rules. At this time, however, EPA does not propose to formally delegate implementation of the rule (such as data collection and enforcement activities) to

State and local agencies, as discussed in Section II.O of this preamble. The goal of data collection under this rule is to establish a consistent, verified, national data set that is available to EPA,

States, other agencies, policy makers, and the public for use in developing and implementing future GHG policies and reduction programs.

To meet these data consistency and timeliness constraints, and to serve policy objectives, it is most efficient to have the data submitted directly into one central EPA system and have centralized emissions data verification. Direct reporting to EPA will also help us better understand and address common compliance problems that may arise from the GHG reporting rule.

EPA recognizes that several States already have mandatory GHG reporting programs that are broader in scope, in a more advanced state of development, and have different policy objectives than this rulemaking. These are important programs that not only led the way in reporting of GHG emissions before the Federal government acted but also have catalyzed important GHG reductions.

As discussed in Section II.O of this preamble, we are committed to working with States and other groups (e.g, TCR, Environmental Council of the States (ECOS)) to develop electronic reporting tools that can both collect and share data in an efficient and timely manner. At this time, EPA is in the process of developing the reporting format and tools and therefore has not specified the exact reporting format, other than it will be electronic, in order to maintain flexibility to modify the reporting format and tools in a timely manner. To the extent possible, EPA will work with existing reporting programs and systems to develop a reporting scheme that minimizes the burden on sources.

While EPA is not delegating authority to the States, we will work with States as we develop rule implementation plans to determine appropriate

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implementation roles, such as assisting with outreach efforts and site visits to audit facility reports. For related comments and responses, please see the following sections of this preamble: II.N (verification approach), II.O (role of States) and II.R (CBI). 2. Enforcement

Comment: Some commenters suggested that States should be allowed to participate in the enforcement of the GHG reporting rule, perhaps through delegated enforcement authority.

Response: EPA welcomes States' interest in helping EPA enforce this or any other Federal rule and we will work with States to determine appropriate roles as described above. We do not plan to delegate the enforcement of this rule in the same sense that we do under other CAA programs such as the NESHAP program in which, for example, notices may be sent only to the delegated States. If a State would like the authority to enforce this rule, then the State may adopt the provisions of this GHG reporting rule into State laws or regulations by reference.

This would make the provisions enforceable as a matter of State law which can be enforced in a State court.

Comment: Some commenters stated that they should be able to petition EPA to enforce against violators where they have evidence of or suspect violations.

Response: EPA welcomes any tips from citizens about suspected violations of this or any rule through our tips Web site, http:// www.epa.gov/tips. However, we are not including a formal petition process in the rule because such a process was not proposed. We do not favor a formal petition process because a formal petition is not necessary for us to investigate concerns raised by citizens and such a process might take extra time or divert resources from other priorities.

Comment: Some commenters stated that a flexible enforcement policy is needed. They noted that the proposed rule cited the CAA for the authority for the GHG reporting rule and stated that a violation of the reporting rule is a violation of the CAA and subject to maximum daily penalties allowed under the CAA. However, the commenters were concerned that the maximum penalty should not be applied in most cases and argued that there are many instances when a less severe action is appropriate.

Response: EPA agrees with the commenters that flexibility is needed in enforcing the rule. The penalty cited in the proposal preamble and rule is a statutory maximum, and would not be applied in every case.

EPA's objective with the reporting rule is to collect accurate GHG data in a timely manner. In order to achieve that objective, EPA will generally work with sources that must submit GHG reports in order to facilitate compliance and provide the needed data to EPA. The CAA allows EPA discretion to pursue a variety of informal and formal actions in order to achieve compliance. While EPA is committed to working with reporters to ensure accuracy, this does not relieve reporters from their obligation to report data that are complete, accurate, and in accordance with the requirements of this rule.

In many instances, based on past enforcement experience, less punitive enforcement actions are exhausted before more punitive fines and penalties are imposed on a non-complying source. These less punitive actions may include a warning to the source that it is in non- compliance along with advice on what needs to be done to comply and a request for response from the facility. Initial actions may also include a formal legal notification from EPA that defines the violation, provides evidence, and requires (orders) corrective actions by specific dates. The EPA enforcement office always uses discretion and takes case-specific circumstances into account when determining the appropriate actions to address violations of CAA rules. We will continue to do so in enforcing the reporting rule, and we are not laying out a specific enforcement policy or hierarchy in order to maintain the necessary flexibility.

VII. Economic Impacts on the Rule

This section of the preamble examines the costs and economic impacts of the GHG reporting rule, including the estimated costs and benefits of the rule, and the estimated economic impacts of the rule on affected entities, including estimated impacts on small entities.

Complete detail of the economic impacts of the final rule can be found in the text of the Regulatory Impact Analysis (RIA) for the final rule

(EPA-HQ-OAR-2008-0508).

This section also contains a brief summary of major comments and responses. A large number of comments on economic impacts of the rule were received covering numerous topics. Responses to significant comments received can be found in ``Mandatory Greenhouse Gas Reporting

Rule: EPA's Response to Public Comments, Cost and Economic Impacts of the Rule.''

A. How were compliance costs estimated? 1. Summary of Method Used To Estimate Compliance Costs

EPA estimated costs of complying with the rule for reporting process emissions of GHGs in each affected industrial facility, as well as emissions from stationary combustion sources at industrial facilities and other facilities, GHG and supply data from fuel suppliers and industrial gas suppliers, and GHG data for mobile sources. 2006 is the representative year of the analysis in that the annual costs were estimated using the 2006 population of emitting sources. EPA used available industry and EPA data to characterize conditions at affected sources. Incremental monitoring, recordkeeping, and reporting activities were then identified for each type of facility and the associated costs were estimated.

The costs of complying with the rule will vary from one facility to another, depending on the types of emissions, the number of affected sources at the facility, existing monitoring, recordkeeping, and reporting activities at the facility, etc. The costs include labor costs for performing the monitoring, recordkeeping, and reporting activities necessary to comply with the rule. For some facilities, costs include costs to monitor, record, and report emissions of GHGs from production processes and from stationary combustion units. For other facilities, the only emissions of GHGs are from stationary combustion. EPA's estimated costs of compliance are discussed in greater detail below:

Labor Costs. The costs of complying with and administering this rule include time of managers, technical, and administrative staff in both the private sector and the public sector. Staff hours are estimated for activities, including:

Monitoring (private): Staff hours to operate and maintain emissions monitoring systems.

Reporting (private): Staff hours to gather and process available data and reporting it to EPA through electronic systems.

Assuring and releasing data (public): Staff hours to quality assure, analyze, and release reports.

Staff activities and associated labor costs will potentially vary over time. Thus, cost estimates are developed for start-up and first- time reporting, and subsequent reporting. Wage rates to monetize staff time are obtained from the Bureau of Labor Statistics (BLS).

Equipment Costs. Equipment costs include both the initial purchase price of monitoring equipment and any

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facility/process modification that may be required. For example, the cost estimation method for mobile sources involves upstream measurement by the vehicle manufacturers. This may require an upgrade to their test equipment and facility. Based on expert judgment, the engineering costs analyses annualized capital equipment costs with appropriate lifetime and interest rate assumptions. Cost recovery periods and interest rates vary by industry, but typically, one-time capital costs are amortized over a 10-year cost recovery period at a rate of seven percent. 2. Summary of Comments and Responses

Comment: A majority of the comments received on the compliance costs of the reporting rule focused on facility level costs for monitoring and reporting. Commenters noted that costs estimated for a representative facility may differ from actual facility level costs.

Some commenters specifically referred to the costs associated with installing and maintaining capital equipment. Other commenters noted that some source categories had higher estimated compliance costs than others. Several commenters expressed confusion over how combustion related monitoring costs are added to process related monitoring costs.

Response: EPA recognizes that the costs presented for facilities represent costs that would be incurred by a representative facility, and may not reflect the costs that would be incurred by each individual facility in each industry because facilities affected by each subpart vary.

Nevertheless, after reviewing the comments received, EPA has determined that its analysis provides a reasonable characterization of costs for facilities affected by each subpart and that its documentation provides adequate documentation of how the costs were estimated. As described in the next section, EPA collected and evaluated cost data from multiple sources, and weighed the analysis prepared at proposal against the input received through public comments. In any analysis of this type, there will be variations in costs among facilities, and after thoroughly reviewing the available information, we have concluded that the costs developed for this rule appropriately reflect a ``representative facility'' in the sector.

The costs facing facilities in some sectors include not only process costs but additional costs associated with other subparts of the rule. While these costs are presented individually in Section 4 of the RIA for the final rule, where these conditions apply the costs are summed across applicable subparts and compared to revenues in the economic and small entity impact analyses.

B. What are the costs of the rule? 1. Summary of Costs

For the cost analysis, EPA gathered existing data from EPA, industry trade associations, States, and publicly available data sources (e.g., labor rates from the BLS) to characterize the processes, sources, sectors, facilities, and companies/entities affected. EPA also considered cost data submitted in public comments on the proposed rule, as further discussed in Section VII.B.2 of this preamble. Costs were estimated on a per entity basis and then weighted by the number of entities affected at the 25,000 metric tons CO2e threshold.

To develop the costs for the rule, EPA estimated the number of affected facilities in each source category, the number and types of combustion units at each facility, the number and types of production processes that emit GHGs, process inputs and outputs (especially for monitoring procedures that involve a carbon mass balance), and the measurements that are already being made for reasons not associated with the rule (to allow only the incremental costs to be estimated).

Many of the affected source categories, especially those that are the largest emitters of GHGs (e.g., electric utilities, industrial boilers, petroleum refineries, cement plants, iron and steel production, pulp and paper) are subject to national emission standards and we use data generated in the development of these standards to estimate the number of sources affected by the reporting rule.

Other components of the cost analysis included estimates of labor hours to perform specific activities, cost of labor, and cost of monitoring equipment. Estimates of labor hours were based on previous analyses of the costs of monitoring, reporting, and recordkeeping for other rules; information from the industry characterization on the number of units or process inputs and outputs to be monitored; and engineering judgment by industry and EPA industry experts and engineers. Labor costs were taken from the BLS and adjusted to account for overhead. Monitoring costs were generally based on cost algorithms or approaches that had been previously developed, reviewed, accepted as adequate, and used specifically to estimate the costs associated with various types of measurements and monitoring.

A detailed engineering analysis was conducted for each subpart of the rule to develop unique unit costs. This analysis is documented in the RIA for the final rule. The TSDs for each source category provide a discussion of the applicable measurement technologies and any existing programs and practices. The appropriate volume of ``Mandatory

Greenhouse Gas Reporting Rule: EPA's Response to Public Comments'' for each source category provide responses to any public comments on these source category engineering and cost analyses. Section 4 of the RIA for the final rule contains a description of the engineering cost analysis.

Table VII-1 of this preamble presents by subpart: The number of entities, the downstream emissions covered, the first year capital costs and the first year annualized costs of the rule. EPA estimates that the total national annualized cost for the first year is $132 million, and the total national annualized cost for subsequent years is

$89 million (2006$). Of these costs, roughly 13 percent fall upon the public sector for program administration in the first year, while 87 percent fall upon the private sector. General stationary combustion sources, which are widely distributed throughout the economy, are estimated to incur approximately 26 percent of costs in the first year; other sectors incurring relatively large shares of costs are pulp and paper manufacturing (9 percent) and vehicle and engine manufacturers (9 percent).

The threshold, in large part, determines the number of entities required to report GHG emissions and hence the costs of the rule. The number of entities excluded increases with higher thresholds. Table

VII-2 of this preamble provides the cost-effectiveness analysis for various thresholds examined. Two metrics are used to evaluate the cost- effectiveness of the emissions threshold. The first is the average cost per metric ton of emissions reported ($/metric ton CO2e).

The second metric for evaluating the threshold option is the incremental cost of reporting emissions. The incremental cost is calculated as the additional (incremental) cost per metric ton starting with the least stringent option and moving successively from one threshold option to the next. For more information about the first year capital costs (unamortized), project lifetime and the amortized

(annualized) costs for each subpart, please refer to section 4 of the

RIA for the final rule and the RIA cost appendix. Not all subparts require capital expenditures but those that do

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are clearly documented in the RIA for the final rule.

Table VII-1--Estimated Covered Entities, Emissions and Costs by Subpart (2006$)

Downstream emissions

First year capital

First year total

Number ------------------------

costs

annualized costs \2\

Subpart

covered of

----------------------------------------------- entities

(Million

Share of MtCO2e) (percent) (Million) (percent) (Million) (percent)

Subpart A--General

0.0

$0.0

Provisions.................

Subpart B--Reserved.........

0.0

Subpart C--General

3,000

220.0

10.5

25.8

Stationary Fuel Combustion

Sources....................

Subpart D--Electricity

1,108

2262.0

0.0

3.3

Generation.................

Subpart E--Adipic Acid

9.3

0.0

0.1

Production.................

Subpart F--Aluminum

6.4

0.0

0.2

Production.................

Subpart G--Ammonia

12.9

0.0

0.4

Manufacturing..............

Subpart H--Cement Production

107

86.8

5.4

6.8

Subpart K--Ferroalloy

2.3

0.0

0.1

Production.................

Subpart N--Glass Production.

2.2

0.0

0.5

Subpart O--HCFC-22

13.8

0.0

Production.................

Subpart P--Hydrogen

15.0

0.0

0.4

Production.................

Subpart Q--Iron and Steel

121

85.0

0.0

3.7

Production.................

Subpart R--Lead Production..

0.8

0.0

0.1

Subpart S--Lime

25.4

4.9

5.3

Manufacturing..............

Subpart U--Miscellaneous

0.0

Uses of Carbonates.........

Subpart V--Nitric Acid

17.7

0.2

0.9

Production.................

Subpart X--Petrochemical

54.4

0.0

2.2

Production.................

Subpart Y--Petroleum

150

204.7

1.6

6.1

Refineries.................

Subpart Z--Phosphoric Acid

3.8

0.8

Production.................

Subpart AA--Pulp and Paper

425

57.7

14.8

8.6

Manufacturing..............

Subpart BB--Silicon Carbide

0.1

0.0

Production.................

Subpart CC--Soda Ash

3.1

0.0

0.1

Manufacturing..............

Subpart EE--Titanium Dioxide

3.7

0.0

0.1

Production.................

Subpart GG--Zinc Production.

0.8

0.0

0.1

Subpart HH--Landfills.......

2,551

91.1

1.3

12.4

Subpart JJ--Manure

107

4.5

0.0

0.3

Management.................

Subpart LL -Suppliers of

315

0.0

3.7

Coal & Subpart MM--

Suppliers of Petroleum

Products...................

Subpart NN--Suppliers of

1,502

0.0

6.8

Natural Gas and Natural Gas

Liquids....................

Subpart OO--Suppliers of

167

643.4

0.0

0.5

Industrial Greenhouse Gases

Subpart PP--Suppliers of

0.0

Carbon Dioxide (CO2).......

Subpart QQ--Motor Vehicle

317

0.0

8.6

7 and Engine Manufacturers...

Coverage Determination Costs

17.2

13 for Non-Reporters..........

Private Sector, Total.......

10,152

3,827

100

39.6

100

115.0

Public Sector, Total........

17.0

Total...................

10,152

3,827

100

39.6

100

132.0

100

\1\ Emissions from upstream facilities are excluded from these estimates to avoid double counting.

\2\ Total costs include labor and capital costs incurred in the first year. Capital Costs are annualized using appropriate equipment lifetime and interest rate (see additional details in section 4 of the RIA for the final rule).

Table VII-2--Threshold Cost-Effectiveness Analysis (2006$)

Percentage

Total

Downstream of total

Average

Facilities costs

emissions downstream reporting Incremental

Threshold (tons CO2e)

required

(million reported emissions

cost

cost ($/ to report

$2006)

(MtCO2e/ reported

($2006/ metric ton) year)

(percent)

ton)

100,000..................................

6,269

$89

3,738

$0.02 25,000...................................

10,152

132

3,827

0.03

0.49 10,000...................................

16,718

160

3,861

0.04

0.83 1,000....................................

54,229

398

3,926

0.10

3.67

* Cost per metric ton relative to the selected option.

Note: Does not include emissions for Motor Vehicle and Engine Manufacturers (Subpart QQ).

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Table VII-3 of this preamble presents costs broken out by upstream and downstream sources. Upstream sources include the fuel suppliers and industrial GHG suppliers. Downstream suppliers include combustion sources, industrial processes, and biological processes. Most upstream facilities (e.g., refineries) are also direct emitters of GHGs and are included in the downstream side of the table. As shown in Table VII-3 of this preamble, over 99 percent of industrial processes emissions are covered at the 25,000 metric tons CO2e threshold for a cost of approximately $36 million. However, it should be noted that due to data limitations the coverage estimates for upstream and downstream source categories are approximations.

Table VII-3--Upstream Versus Downstream Costs

Upstream 1

Downstream 2 3 4

Emissions First year

No. of

Emissions First year

Source category

No. of coverage

cost

Source category

reporters coverage 3 cost 3 reporters

(%) 10 (millions)

7 10 (%) (millions)

Coal Supply....................................

$0.00 Coal 5 6 Combustion...............

N/A

99.0

N/A

Petroleum Supply...............................

315

100

3.66 Petroleum 5 Combustion 9..........

N/A

20.0

N/A

Natural Gas Supply.............................

1,502

6.76 Natural Gas 5 Combustion..........

N/A

23.0

N/A

......... ......... .......... Sub Total Combustion..............

4,108

N/A

$29.04

Industrial Gas Supply..........................

167

100

0.52 Industrial Gas Consumption........

0.24

......... ......... .......... Industrial Processes..............

1,068

99.6

36.2

......... ......... .......... Fugitive Emissions (coal, oil and

0.00 gas).

......... ......... .......... Biological Processes..............

2,658

12.77

......... ......... .......... Vehicle 8 and Engine Manufacturers

317

8.61

Notes 1 Most upstream facilities (e.g., refineries) are also direct emitters of greenhouse gases, and are included in the downstream side of the table. 2 Estimating the total number of downstream reporters by summing the rows will result in double-counting because some facilities are included in more than one row due to multiple types of emissions (e.g., facilities that burn fossil fuel and have process/fugitive/biological emissions will be included in each downstream category). 3 The coverage and costs for downstream reporters apply to the specific source category, i.e., the fixed costs are not ``double-counted'' in both stationary combustion and industrial processes for the same facility. 4 The thresholds used to determine covered facilities are additive, i.e., all of the source categories located at a facility (e.g., stationary combustion and process emissions) are added together to determine whether a facility meets the threshold (e.g., 25,000 metric tons of CO2e/yr). 5 Estimates for the number of reporters and total cost for downstream stationary combustion do not distinguish between fuels. National level data on the number of reporters could be estimated. However, estimating the number of reporters by fuel was not possible because a single facility can combust multiple fuels. For these reasons there is not a reliable estimate of the total of the emissions coverage from the downstream stationary combustion. 6 Approximately 90 percent of downstream coal combustion emissions are already reported to EPA through requirements for electricity generating units under the ARP. 7 Due to data limitations, the coverage for downstream sources for fuel and industrial gas consumption in this table does not take into account thresholds. Assuming full emissions coverage for each source slightly over-states the actual coverage that will result from this rule. To estimate total emissions coverage downstream, by fuel, we added total emissions resulting from the respective fuel combusted in the industrial and electricity generation sectors and divided that by total national GHG emissions from the combustion of that fuel. 8 The percent of coverage here is percentage of total heavy-duty highway vehicles and engines, motorcycles, and nonroad engine sales covered by manufacturer reporting in this proposal rather than emissions coverage. The ``threshold'' for mobile sources is based on manufacturer size rather than total emissions. In this rule, all heavy-duty highway and nonroad vehicle and engine manufacturers, except those that meet EPA's definition of ``small business'' or ``small volume manufacturers'', would report emissions rates of CO2, CH4, and N2O from the products they supply. This source category is neither upstream nor downstream, but is included in the downstream column for illustrative purposes. 9 The emissions coverage for petroleum combustion includes combustion of fuel by transportation sources as well as other uses of petroleum (e.g., home heating oil). It cannot be broken out by transportation versus other uses as there are difficulties associated with tracking which products from petroleum refiners are used for transportation fuel and which were not. We know that although refiners make these designations for the products leaving their gate, the actual end use can and does change in the market. For example, designated transportation fuel can always be used as home heating oil. 10 Emissions coverage from the combustion of fossil fuels upstream represents CO2 emissions only. It is not possible to estimate nitrous oxide and methane emissions without knowing where and how the fuel is combusted. In the case of downstream emissions from stationary combustion of fossil fuels, nitrous oxide and methane emissions are included in the emissions coverage estimate. They represent approximately one percent of the total emissions. 2. Summary of Comments and Responses

Comment: EPA received comments on source specific cost data reflected in the engineering cost analysis presented in section 4 of the RIA for the proposed rule (EPA-HQ-OAR-2008-0318-002). Some commenters asked EPA to not overly burden entities that may be required to report and to balance reporting costs with the need for accurate reporting of GHG emissions.

Additional comments received questioned EPA's estimate of the costs associated with third party verification, as well as the estimated burden to the Federal government for self certification with EPA verification.

Response: EPA considered all relevant comments regarding source specific cost data developed in the engineering cost analysis and used in the RIA for the proposed rule. In some cases, we revised our cost estimates, and in some cases we revised monitoring and reporting requirements in ways which reduced burden. Please see source specific comments and responses in Section III of this preamble and the relevant volume of ``Mandatory Greenhouse Gas Reporting Rule: EPA's Response to

Public Comments''.

EPA believes the selected option for the mandatory GHG reporting rule strikes a balance between impacts on small entities, consistency with other programs, costs incurred by the reporting entities, and emissions coverage. Section 5 of the RIA for the

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final rule provides cost comparisons for each alternative evaluated.

In evaluating the costs of self certification with EPA verification and third party verification, EPA conducted a thorough review of relevant cost information available. EPA also considered cost data submitted in public comments on the proposed rule. EPA's review of verification costs included examining estimated Agency costs for other

EPA based reporting programs, as well as a study conducted by the

California Air Resources Board (CARB). The results of EPA's review of verification costs can be found in the Memo on Verification Costs in the docket. The final rule retains self-certification with EPA verification. EPA's estimated cost for verification activities is $7 million per year. Additional comments and responses on third party verification can be found in Section II.N of this preamble. Section 5.1.6 of the RIA for the final rule contains the full economic analysis of verification costs and options.

C. What are the economic impacts of the rule? 1. Summary of Economic Impacts

EPA prepared an economic impact analysis to evaluate the impacts of the rule on affected industries and economic sectors. In evaluating the various reporting options considered, EPA conducted a cost- effectiveness analysis, comparing the cost per metric ton of GHG emissions across reporting options. EPA used this information to identify the preferred options described in today's rule.

To estimate the economic impacts of the rule, EPA first conducted a screening assessment, comparing the estimated total annualized compliance costs by industry, where industry is defined in terms of

North American Industry Classification System (NAICS) code, with industry average revenues. Overall national costs of the rule are significant because there is a large number of affected entities, but per-entity costs are low. Average cost-to-sales ratios for establishments in affected NAICS codes are uniformly less than 0.8 percent.

These low average cost-to-sales ratios indicate that the rule is unlikely to result in significant changes in firms' production decisions or other behavioral changes, and thus unlikely to result in significant changes in prices or quantities in affected markets. Thus,

EPA followed its Guidelines for Preparing Economic Analyses (EPA, 2002, p.124-125) and used the engineering cost estimates to measure the social cost of the rule, rather than modeling market responses and using the resulting measures of social cost. Table VII-4 of this preamble summarizes cost-to-sales ratios for affected industries.

Table VII-4--Estimated Cost-to-Sales Ratios for Affected Entities

Average cost Average entity per entity

cost-to-sales

NAICS

NAICS description

($1,000/

ratio \1\ entity)

(percent)

211........................................... Oil and Gas Extraction..........

2e threshold because it sufficiently captures the majority of GHG emissions in the U.S., while excluding smaller facilities and sources. For small facilities that are covered by the rule, EPA has included simplified emission estimation methods in the rule where feasible (e.g., stationary combustion equipment under a certain rating can use a simplified calculation approach as opposed to more rigorous direct monitoring) to keep the burden of reporting as low as possible. We received many comments related to monitoring and reporting requirements in specific source categories, and made many changes in response to reduce burden on reporters. For information on these issues, refer to the discussion of each source category in this preamble and the relevant volume of ``Mandatory Greenhouse Gas

Reporting Rule: EPA's Response to Public Comments.'' For further detail on the rationale for excluding small entities through threshold selection please see the Thresholds TSD (EPA-HQ-OAR-2008-0508-046) and

Section III.C.3 of this preamble.

EPA conducted a screening assessment comparing compliance costs for affected industry sectors to industry-specific receipts data for establishments owned by small businesses. This ratio constitutes a

``sales'' test that computes the annualized compliance costs of this rule as a percentage of sales and determines whether the ratio exceeds some level (e.g., one percent or three percent).\32\ The cost-to-sales ratios were constructed at the establishment level (average reporting program costs per establishment/average establishment receipts) for several business size ranges. This allowed EPA to account for receipt differences between establishments owned by large and small businesses and differences in small business definitions across affected industries. The results of the screening assessment are shown in Table

VII-5 of this preamble.

\32\ EPA's RFA guidance for rule writers suggests the ``sales'' test continues to be the preferred quantitative metric for economic impact screening analysis.

Table VII-5--Estimated Cost-to-Sales Ratios by Industry and Enterprise Size a

Owned by enterprises with:

Average

-----------------------------------------------------------------

SBA size standard

cost per

All

2e reported of $0.07.

As shown, the cost-to-sales ratios are less than one percent for establishments owned by small businesses that EPA considers most likely to be covered by the reporting program (e.g., establishments owned by businesses with 20 or more employees).

EPA acknowledges that several enterprise categories have ratios that exceed this threshold (e.g., enterprise with one to 20 employees).

EPA took a conservative approach with the model entity analysis.

Although the appropriate SBA size definition should be applied at the parent company (enterprise) level, data limitations allowed us only to compute and compare ratios for a model establishment within several enterprise size ranges. To assess the likelihood that

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these small businesses will be covered by the rule, we performed several case studies for manufacturing industries where the cost-to- receipt ratio exceeded one percent. For each industry, we used and applied emission data from a recent study examining emission thresholds

\33\. This study provides industry-average CO2emission rates (e.g., tons per employee) for these manufacturing industries.

\33\ Nicholas Institute for Environmental Policy Solutions, Duke

University. 2008. Size Thresholds for Greenhouse Gas Regulation: Who

Would be Affected by a 10,000-ton CO2Emissions Rule?

Available at: http://www.nicholas.duke.edu/institute/10Kton.pdf.

The case studies showed two industries (cement and lime manufacturing) where emission rates suggest small businesses of this employment size could potentially be covered by the rule. As a result,

EPA examined corporate structures and ultimate parent companies were identified using industry surveys and the latest private databases such as Dun & Bradstreet. The results of this analysis show cost to sales ratios below one percent.

For the other enterprise categories identified with ratios between one percent and three percent EPA examined industry specific bottom up databases and previous industry specific studies to ensure that no entities with less than 20 employees are captured under the rule.

Although this rule will not have a significant economic impact on a substantial number of small entities, the Agency nonetheless tried to reduce the impact of this rule on small entities, including seeking input from a wide range of private- and public-sector stakeholders.

When developing the rule, the Agency took special steps to ensure that the burdens imposed on small entities were minimal. The Agency conducted several meetings with industry trade associations to discuss regulatory options and the corresponding burden on industry, such as recordkeeping and reporting. The Agency investigated alternative thresholds and analyzed the marginal costs associated with requiring smaller entities with lower emissions to report. The Agency also recommended a hybrid method for reporting, which provides flexibility to entities and helps minimize reporting costs.

Additional analysis for a model small government also showed that the annualized reporting program costs were less than one percent of revenue. These impacts are likely representative of ratios in industries where data limitations do not allow EPA to compute sales tests (e.g., general stationary combustion and manure management).

Potential impacts of the rule on small governments were assessed separately from impacts on Federal Agencies. Small governments and small non-profit organizations may be affected if they own affected stationary combustion sources, landfills, or natural gas suppliers.

However, the estimated costs under the rule are estimated to be small enough that no small government or small non-profit is estimated to incur significant impacts. For example, from the 2002 Census (in

$2006), revenues for small governments (counties and municipalities) with populations fewer than 10,000 are $3 million, and revenues for local governments with populations less than 50,000 is $7 million. As an upper bound estimate, summing typical per-respondent costs of combustion plus landfills plus natural gas suppliers yields a cost of approximately $18,000 per local government. Thus, for the smallest group of local governments (2e level would disproportionately affect small businesses. Another commenter stated that small businesses are not well equipped to handle detailed requirements for reporting and that the proposed rule would impose a large burden for monitoring, recordkeeping, and reporting activities.

Additional comments received requested that EPA establish a SBREFA process to investigate the impacts that the proposed rule would have on small businesses.

Response: As summarized above, EPA investigated alternative thresholds and analyzed the marginal costs associated with requiring smaller entities with lower emissions to report. EPA recognized the additional burden placed on small entities at lower thresholds, and had retained the hybrid method for reporting that includes a 25,000 metric ton CO2e level threshold. Under this threshold, EPA has assessed the economic impact of the final rule on small entities and concluded that this action will not have a significant economic impact on a substantial number of small entities.

For this reason, EPA did not establish a SBREFA panel process for the rulemaking. The summary of the factual basis for the certification is provided in the preamble for the rule. Complete documentation of the analysis can be found in Section 5.2 of the RIA for the final rule.

E. What are the benefits of the rule for society? 1. Summary of Method Used To Estimate Compliance Costs

EPA examined the potential benefits of the GHG reporting rule. The benefits of a reporting system are based on their relevance to policy making, transparency issues, and market efficiency. Benefits are very difficult to quantify and monetize. Instead of a quantitative analysis of the benefits, EPA conducted a systematic literature review of existing studies including government, consulting, and scholarly reports.

A mandatory reporting system will benefit the public by increased transparency of facility emissions data. Transparent, public data on emissions allows for accountability of polluters to the public stakeholders who bear the cost of the pollution. Citizens, community groups, and labor unions have made use of data from Pollutant Release and Transfer Registers to negotiate directly with polluters to lower emissions, circumventing greater government regulation. Publicly available emissions data also will allow individuals to alter their consumption habits based on the GHG emissions of producers.

The greatest benefit of mandatory reporting of industry GHG emissions to government will be realized in developing future GHG policies. For example, in the EU's Emissions Trading System, a lack of accurate monitoring at the facility level before establishing

CO2allowance permits resulted in allocation of permits for emissions levels an average of 15 percent above actual levels in every country except the United Kingdom.

Benefits to industry of GHG emissions monitoring include the value of having independent, verifiable data to present to the public to demonstrate appropriate environmental stewardship, and a better understanding of their emission levels and sources to identify opportunities to reduce emissions. Such monitoring allows for inclusion of standardized GHG data into environmental management systems, providing the necessary information to achieve and

Page 56369

disseminate their environmental achievements.

Standardization will also be a benefit to industry, once facilities invest in the institutional knowledge and systems to report emissions, the cost of monitoring should fall and the accuracy of the accounting should improve. A standardized reporting program will also allow for facilities to benchmark themselves against similar facilities to understand better their relative standing within their industry. 2. Summary of Comments and Responses

Comment: Comments received on the benefits of the mandatory reporting program focused on the potential future uses of the collected data. Additional comments on the benefits of the program were concerned that the benefits of the rule are not quantified.

Response: The data collected under this rule will provide comprehensive and accurate data to inform future climate change policies. Potential future CAA and other climate policies include research and development initiatives, economic incentives, new or expanded voluntary programs, adaptation strategies, emission standards, a carbon tax, or a cap-and-trade program. Because EPA does not know at this time the specific policies that may be adopted, the data reported through this rule should be of sufficient quality to support a range of approaches.

Section VI of the RIA for the final rule summarizes the anticipated benefits of the rule, which include providing the government with sound data on which to base future policies and providing industry and the public independently verified information documenting firms' environmental performance. While EPA has not quantified the benefits of the mandatory reporting rule, EPA believes that they are substantial and outweigh the estimated costs.

VIII. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

Under section 3(f)(1) of EO 12866 (58 FR 51735, October 4, 1993), this action is an ``economically significant regulatory action'' because it is likely to have an annual effect on the economy of $100 million or more. Accordingly, EPA submitted this action to the OMB for review under EO 12866 and any changes made in response to OMB recommendations have been documented in the docket for this action.

In addition, EPA prepared an analysis of the potential costs and benefits associated with this action. A copy of the analysis is available in Docket No. EPA-HQ-OAR-2008-0508, the RIA for the final rule, and is briefly summarized in Section VII of this preamble.

B. Paperwork Reduction Act

The information collection requirements in this rule have been submitted for approval to the Office of Management and Budget (OMB) under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The information collection requirements are not enforceable until OMB approves them. The ICR document prepared by EPA has been assigned EPA

ICR number 2300.03.

EPA plans to collect complete and accurate economy-wide data on facility-level GHG emissions. Accurate and timely information on GHG emissions is essential for informing future climate change policy decisions. Through data collected under this rule, EPA will gain a better understanding of the relative emissions of specific industries, and the distribution of emissions from individual facilities within those industries. The facility-specific data will also improve our understanding of the factors that influence GHG emission rates and actions that facilities are already taking to reduce emissions.

Additionally, EPA will be able to track the trend of emissions from industries and facilities within industries over time, particularly in response to policies and potential regulations. The data collected by this rule will improve EPA's ability to formulate climate change policy options and to assess which industries would be affected, and how these industries would be affected by the options.

This information collection is mandatory and will be carried out under CAA sections 114 and 208. Information identified and marked as

CBI will not be disclosed except in accordance with procedures set forth in 40 CFR part 2. However, emissions data collected under CAA sections 114 and 208 cannot generally be claimed as CBI and will be made public.\34\

\34\ Although CBI determinations are usually made on a case-by- case basis, EPA has issued guidance in an earlier Federal Register notice on what constitutes emissions data that cannot be considered

CBI (956 FR 7042-7043, February 21, 1991). As discussed in Section

II.R of this preamble, EPA will be initiating a separate notice and comment process to make CBI determinations for the data collected under this rulemaking.

The projected cost and hour burden for non-Federal respondents is

$86.3 million and 1.21 million hours per year. The estimated average burden per response is two hours; the frequency of response is annual for all respondents that must comply with the rule's reporting requirements, except for electricity generating units that are already required to report quarterly under 40 CFR part 75 (EPA Acid Rain

Program); and the estimated average number of likely respondents per year is 16,725 \35\. The cost burden to respondents resulting from the collection of information includes the total capital cost annualized over the equipment's expected useful life (averaging $9.1 million), a total operation and maintenance component (averaging $11.0 million per year), and a labor cost component (averaging $66.1 million per year).

Burden is defined at 5 CFR 1320.3(b). These cost numbers differ from those shown elsewhere in the RIA for the final rule because the ICR costs represent the average cost over the first three years of the rule, but costs are reported elsewhere in the RIA for the final rule for the first year of the rule and for subsequent years of the rule. In addition, the ICR focuses on respondent burden, while the RIA for the final rule includes EPA Agency costs.

\35\ EPA estimates that 30,000 facilities are potentially affected by the rule. Of these, EPA estimates that 10,152 facilities across various sectors will be over their sector-specific reporting threshold and thus required to report; the remaining 19,848 will determine during the first year that they are beneath the threshold and do not need to report. The average number of respondents is thus

(30,000+10,152+10,152)/3 = 16,768; excluding 43 Federal facilities, the number of private respondents is 16,725.

An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for EPA's regulations in 40 CFR are listed in 40 CFR part 9. When this ICR is approved by OMB, the Agency will publish a technical amendment to 40

CFR part 9 in the Federal Register to display the OMB control number for the approved information collection requirements contained in this final rule.

C. Regulatory Flexibility Act (RFA)

The RFA generally requires an agency to prepare a regulatory flexibility analysis of any rule subject to notice and comment rulemaking requirements under the Administrative Procedure Act or any other statute unless the agency certifies that the rule will not have a significant economic impact on a substantial number of small entities.

Small entities include small businesses, small organizations, and small governmental jurisdictions.

For purposes of assessing the impacts of today's rule on small entities, small entity is defined as: (1) A small business

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as defined by the Small Business Administration's regulations at 13 CFR 121.201; (2) a small governmental jurisdiction that is a government of a city, county, town, school district or special district with a population of less than 50,000; and (3) a small organization that is any not-for-profit enterprise which is independently owned and operated and is not dominant in its field.

After considering the economic impacts of today's final rule on small entities, I therefore certify that this final rule will not have a significant economic impact on a substantial number of small entities.

The small entities directly regulated by this final rule include small businesses across all sectors encompassed by the rule, small governmental jurisdictions and small non-profits. We have determined that some small businesses will be affected because their production processes emit GHGs that must be reported, because they have stationary combustion units on site that emit GHGs that must be reported, or because they have fuel supplier operations for which supply quantities and GHG data must be reported. Small governments and small non-profits are generally affected because they have regulated landfills or stationary combustion units on site, or because they own an LDC.

For affected small entities, EPA conducted a screening assessment comparing compliance costs for affected industry sectors to industry- specific data on revenues for small businesses. This ratio constitutes a ``sales'' test that computes the annualized compliance costs of this final rule as a percentage of sales and determines whether the ratio exceeds some level (e.g., one percent or three percent). The cost-to- sales ratios were constructed at the establishment level (average compliance cost for the establishment/average establishment revenues).

As shown in Table VII-5 of this preamble, the cost-to-sales ratios are less than one percent for establishments owned by small businesses that

EPA considers most likely to be covered by the reporting program, those with more than 20 employees.\36\ For the few sectors where the preliminary screening showed a cost-to-sales ratio exceeding one percent, EPA's examination of firm-specific sales information showed that no affected entity was likely to incur costs exceeding one percent of sales.

\36\ U.S. Small Business Administration (SBA). 2008. Firm Size

Data from the Statistics of U.S. Businesses: U.S. Detail Employment

Sizes: 2002. http://www.census.gov/csd/susb/download_susb02.htm.

The screening analysis thus indicates that the final rule will not have a significant economic impact on a substantial number of small entities. See Table VII-5 of this preamble for sector-specific results.

The screening assessment for small governments compared the sum of average costs of compliance for combustion, local distribution companies, and landfills to average revenues for small governments.

Even for a small government owning all three source types, the costs constitute less than one percent of average revenues for the smallest category of governments (those with fewer than 10,000 people).

Although this final rule will not have a significant economic impact on a substantial number of small entities, EPA nonetheless took several steps to reduce the impact of this rule on small entities. For example, EPA determined appropriate thresholds that reduce the number of small businesses reporting. In addition, EPA is not requiring facilities to install CEMS if they do not already have them. Facilities without CEMS can calculate emissions using readily available data or data that are less expensive to collect such as process data or material consumption data. For some source categories, EPA developed tiered methods that are simpler and less burdensome. Also, EPA is requiring annual instead of more frequent reporting.

Through comprehensive outreach activities prior to proposal of the rule, EPA held approximately 100 meetings and/or conference calls with representatives of the primary audience groups, including numerous trade associations and industries that include small business members.

EPA's outreach activities prior to proposal of the rule are documented in the memorandum, ``Summary of EPA Outreach Activities for Developing the Greenhouse Gas Reporting Rule,'' located in Docket No. EPA-HQ-OAR- 2008-0508-055. After proposal, EPA posted a guide for small businesses on EPA's GHG reporting rule Web site, along with a general fact sheet for the rule, information sheets for every source category, and an FAQ document. EPA also operated a hotline to answer questions about the proposed rule. We continued to meet with stakeholders and entered documentation of all meetings into the docket. We considered public comments, including comments from small businesses and organizations that include small business members, in developing the final rule.

During rule implementation, EPA will maintain an ``open door'' policy for stakeholders to ask questions about the rule or provide suggestions to EPA about the types of compliance assistance that would be useful to small businesses. EPA intends to develop a range of compliance assistance tools and materials and conduct extensive outreach for the final rule.

D. Unfunded Mandates Reform Act (UMRA)

Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2

U.S.C. 1531-1538, requires Federal agencies, unless otherwise prohibited by law, to assess the effects of their regulatory actions on

State, local, and Tribal governments and the private sector.

EPA has developed this regulation under authority of CAA sections 114 and 208. The required activities under this Federal mandate include monitoring, recordkeeping, and reporting of GHG emissions from multiple source categories (e.g., combustion, process, and biologic). This rule contains a Federal mandate that may result in expenditures of $100 million for the private sector in any one year. As described below, we have determined that the expenditures for State, local, and Tribal governments, in the aggregate, will be approximately $12.1 million per year, based on average costs over the first three years of the rule, including approximately $2 million during the first year of the rule for governments to make a reporting determination and subsequently determine that their emissions are below the threshold and thus, they are not required to report their emissions. Accordingly, EPA has prepared under section 202 of the UMRA a written statement which is summarized below.

Consistent with the intergovernmental consultation provisions of section 204 of the UMRA, EPA initiated an outreach effort with the governmental entities affected by this rule including State, local, and

Tribal officials. EPA maintained an ``open door'' policy for stakeholders to provide input on key issues and to help inform EPA's understanding of issues, including impacts to State, local and Tribal governments. The outreach audience included State environmental protection agencies, regional and Tribal organizations, and other State and local government organizations. EPA contacted several States and

State and regional organizations already involved in GHG emissions reporting. EPA also conducted several conference calls with Tribal organizations during the proposal phase. For example, EPA staff provided information to tribes through conference calls with multiple

Tribal working groups and organizations at EPA and

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through individual calls with two Tribal board members of TRI. In addition, EPA held meetings and conference calls with groups such as

TRI, National Association of Clean Air Agencies (NACAA), ECOS, and with

State members of RGGI, the Midwestern GHG Reduction Accord, and WCI.

See the ``Summary of EPA Outreach Activities for Developing the

Greenhouse Gas Reporting Rule,'' in Docket No. EPA-HQ-OAR-2008-0508-055 for a complete list of organizations and groups that EPA contacted.

At proposal of the rule, EPA posted a guide for State and local agencies on the Web site, along with other information sheets, to communicate key aspects of the proposed rule to these agencies. Several

State and local agencies and three Tribal organizations or communities submitted written public comments, and EPA carefully considered these comments in developing the final rule. EPA also continued to meet with government agencies or organizations with State members such as

California ARB, Connecticut DEP, New Jersey DEP, New Mexico ED,

Washington DE, Massachusetts DEP, Illinois EPA, Iowa DNR, and TCR These meetings are documented in the docket. EPA intends to continue to work closely with State, local, and Tribal agencies during rule implementation.

Consistent with section 205 of the UMRA, EPA has identified and considered a reasonable number of regulatory alternatives. EPA carefully examined regulatory alternatives, and selected the lowest cost/least burdensome alternative that EPA deems adequate to address

Congressional concerns and to provide a consistent, comprehensive source of information about emissions of GHGs. EPA has considered the costs and benefits of the GHG reporting rule, and has concluded that the costs will fall mainly on the private sector (approximately $77 million), with some costs incurred by State, local, and Tribal governments that must report their emissions (less than $10.1 million) that own and operate stationary combustion units, landfills, or natural gas local distribution companies (LDCs). EPA estimates that an additional 2,034 facilities owned by State, local, or Tribal governments will incur approximately $2.0 million in costs during the first year of the rule to make a reporting determination and subsequently determine that their emissions are below the threshold and thus, they are not required to report their emissions. Furthermore, we think it is unlikely that State, local, and Tribal governments would begin operating large industrial facilities, similar to those affected by this rulemaking operated by the private sector.

Initially, EPA estimates that costs of complying with the final rule will be widely dispersed throughout many sectors of the economy.

Although EPA acknowledges that over time changes in the patterns of economic activity may mean that GHG generation and thus reporting costs will change, data are inadequate for projecting these changes. Thus,

EPA assumes that costs averaged over the first three years of the program are typical of ongoing costs of compliance. EPA estimates that future compliance costs will total approximately $104 million per year.

EPA examined the distribution of these costs between private owners and

State, local, and Tribal governments owning GHG emitters. In addition,

EPA examined, within the private sector, the impacts on various industries. In general, estimated cost per entity represents less than 0.1 percent of company sales in affected industries. These costs are broadly distributed to a variety of economic sectors and represent approximately 0.001 percent of 2008 Gross Domestic Product; overall,

EPA does not believe the final rule will have a significant macroeconomic impact on the national economy. Therefore, this rule is not subject to the requirements of section 203 of UMRA because it contains no regulatory requirements that might significantly or uniquely affect small governments.

EPA does not anticipate that substantial numbers of either public or private sector entities will incur significant economic impacts as a result of this final rule. EPA further expects that benefits of the final rule will include more and better information for EPA and the private sector about emissions of GHGs. This improved information will enhance EPA's ability to develop sound future climate policies, and may encourage GHG emitters to develop voluntary plans to reduce their emissions.

This regulation applies directly to facilities that supply fuel or chemicals that when used emit greenhouse gases, to motor vehicle manufacturers, and to facilities that directly emit greenhouses gases.

It does not apply to governmental entities unless the government entity owns a facility that directly emits GHGs above threshold levels such as a landfill or large stationary combustion source, or LDC. In addition, this rule does not impose any implementation responsibilities on State, local, or Tribal governments and it is not expected to increase the cost of existing regulatory programs managed by those governments.

Thus, the impact on governments affected by the rule is expected to be minimal.

E. Executive Order 13132: Federalism

EO 13132, entitled ``Federalism'' (64 FR 43255, August 10, 1999), requires EPA to develop an accountable process to ensure ``meaningful and timely input by State and local officials in the development of regulatory policies that have Federalism implications.'' ``Policies that have Federalism implications'' is defined in the EO to include regulations that have ``substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government.''

This final rule does not have Federalism implications. It will not have substantial direct effects on the States, on the relationship between the national government and the States, or on the distribution of power and responsibilities among the various levels of government, as specified in EO 13132. However, for a more detailed discussion about how this final rule relates to existing State programs, please see

Section II of the proposal preamble (74 FR 16457 to 16461, April 10, 2009) and Sections I.E. and II.C.2 of this preamble.

This regulation applies directly to facilities that supply fuel or chemicals that when used emit greenhouse gases, motor vehicle manufacturers, or facilities that directly emit greenhouses gases. It does not apply to governmental entities unless the government entity owns a facility that directly emits GHGs above threshold levels such as a landfill, large stationary combustion source, or LDC, so relatively few government facilities would be affected. This regulation also does not limit the power of States or localities to collect GHG data and/or regulate GHG emissions. Thus, EO 13132 does not apply to this rule.

In the spirit of Executive Order 13132, and consistent with EPA policy to promote communications between EPA and State and local governments, EPA specifically solicited comments on the proposed rule from State and local officials. See Section VIII.D above, for discussion of outreach activities to State, local, or Tribal organizations.

F. Executive Order 13175: Consultation and Coordination With Indian

Tribal Governments

This final rule does not have Tribal implications, as specified in

EO 13175 (65 FR 67249, November 9, 2000). This

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regulation applies directly to facilities that supply fuel or chemicals that when used emit GHGs or facilities that directly emit greenhouses gases. Facilities expected to be affected by the final rule are not expected to be owned by Tribal governments. Thus, Executive Order 13175 does not apply to this final rule.

Although EO 13175 does not apply to this final rule, EPA sought opportunities to provide information to Tribal governments and representatives during development of the rule. In consultation with

EPA's American Indian Environment Office, EPA's outreach plan included tribes. EPA conducted several conference calls with Tribal organizations during the proposal phase. For example, EPA staff provided information to tribes through conference calls with multiple

Indian working groups and organizations at EPA that interact with tribes and through individual calls with two Tribal board members of

TCR. In addition, EPA prepared a short article on the GHG reporting rule that appeared on the front page a Tribal newsletter--Tribal Air

News--that was distributed to EPA/OAQPS's network of Tribal organizations. EPA gave a presentation on various climate efforts, including the mandatory reporting rule, at the National Tribal

Conference on Environmental Management on June 24-26, 2008. In addition, EPA had copies of a short information sheet distributed at a meeting of the National Tribal Caucus. See the ``Summary of EPA

Outreach Activities for Developing the GHG reporting rule,'' in Docket

No. EPA-HQ-OAR-2008-0508-055 for a complete list of Tribal contacts.

EPA participated in a conference call with Tribal air coordinators in

April 2009 and prepared a guidance sheet for Tribal governments on the proposed rule. It was posted on the MRR Web site and published in the

Tribal Air Newsletter.

G. Executive Order 13045: Protection of Children From Environmental

Health Risks and Safety Risks

EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying only to those regulatory actions that concern health or safety risks, such that the analysis required under section 5-501 of the EO has the potential to influence the regulation. This action is not subject to EO 13045 because it does not establish an environmental standard intended to mitigate health or safety risks.

H. Executive Order 13211: Actions That Significantly Affect Energy

Supply, Distribution, or Use

This final rule is not a ``significant energy action'' as defined in EO 13211 (66 FR 28355, May 22, 2001) because it is not likely to have a significant adverse effect on the supply, distribution, or use of energy. Further, we have concluded that this rule is not likely to have any adverse energy effects. This final rule relates to monitoring, reporting and recordkeeping at facilities that supply fuel or chemicals that when used emit GHGs or facilities that directly emit greenhouses gases and does not impact energy supply, distribution or use.

Therefore, we conclude that this rule is not likely to have any adverse effects on energy supply, distribution, or use.

I. National Technology Transfer and Advancement Act

Section 12(d) of the National Technology Transfer and Advancement

Act of 1995 (NTTAA), Public Law 104-113 (15 U.S.C. 272 note) directs

EPA to use voluntary consensus standards in its regulatory activities unless to do so would be inconsistent with applicable law or otherwise impractical. Voluntary consensus standards are technical standards

(e.g., materials specifications, test methods, sampling procedures, and business practices) that are developed or adopted by voluntary consensus standards bodies. NTTAA directs EPA to provide Congress, through OMB, explanations when the Agency decides not to use available and applicable voluntary consensus standards.

This rulemaking involves technical standards. EPA will use more than 60 voluntary consensus standards from 10 different voluntary consensus standards bodies, including the following: ASTM, ASME, ISO,

Gas Processors Association, American Gas Association, and National Lime

Association. These voluntary consensus standards will help facilities monitor, report, and keep records of GHG emissions. No new test methods were developed for this rule. Instead, from existing rules for source categories and voluntary GHG programs, EPA identified existing means of monitoring, reporting, and keeping records of GHG emissions. The existing methods (voluntary consensus standards) include a broad range of measurement techniques, including many for combustion sources such as methods to analyze fuel and measure its heating value; methods to measure gas or liquid flow; and methods to gauge and measure petroleum and petroleum products. The test methods are incorporated by reference into the final rule and are available as specified in 40 CFR 98.7.

By incorporating voluntary consensus standards into this final rule, EPA is both meeting the requirements of the NTTAA and presenting multiple options and flexibility for measuring GHG emissions.

J. Executive Order 12898: Federal Actions To Address Environmental

Justice in Minority Populations and Low-Income Populations

EO 12898 (59 FR 7629, February 16, 1994) establishes Federal executive policy on environmental justice. Its main provision directs

Federal agencies, to the greatest extent practicable and permitted by law, to make environmental justice part of their mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of their programs, policies, and activities on minority populations and low-income populations in the

U.S.

EPA has determined that this final rule will not have disproportionately high and adverse human health or environmental effects on minority or low-income populations because it does not affect the level of protection provided to human health or the environment. This final rule does not affect the level of protection provided to human health or the environment because it is a rule addressing information collection and reporting procedures.

K. Congressional Review Act

The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the

Small Business Regulatory Enforcement Fairness Act of 1996, generally provides that before a rule may take effect, the agency promulgating the rule must submit a rule report, which includes a copy of the rule, to each House of the Congress and to the Comptroller General of the

United States. EPA will submit a report containing this rule and other required information to the U.S. Senate, the U.S. House of

Representatives, and the Comptroller General of the U.S. prior to publication of the rule in the Federal Register. A major rule cannot take effect until 60 days after it is published in the Federal

List of Subjects 40 CFR Part 86

Environmental protection, Administrative practice and procedure,

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Air pollution control, Reporting and recordkeeping requirements, Motor vehicle pollution. 40 CFR Part 87

Environmental protection, Air pollution control, Aircraft,

Incorporation by reference. 40 CFR Part 89

Environmental protection, Administrative practice and procedure,

Confidential business information, Imports, Labeling, Motor vehicle pollution, Reporting and recordkeeping requirements, Research, Vessels,

Warranty. 40 CFR Part 90

Environmental protection, Administrative practice and procedure,

Confidential business information, Imports, Labeling, Reporting and recordkeeping requirements, Research, Warranty. 40 CFR Part 94

Environmental protection, Administrative practice and procedure,

Air pollution control, Confidential business information, Imports,

Incorporation by reference, Labeling, Penalties, Vessels, Reporting and recordkeeping requirements, Warranties. 40 CFR Part 98

Environmental protection, Administrative practice and procedure,

Greenhouse gases, Incorporation by reference, Suppliers, Reporting and recordkeeping requirements. 40 CFR Part 1033

Environmental protection, Administrative practice and procedure,

Confidential business information, Incorporation by reference,

Labeling, Penalties, Railroads, Reporting and recordkeeping requirements. 40 CFR Part 1039

Environmental protection, Administrative practice and procedure,

Air pollution control, Confidential business information, Imports,

Incorporation by reference, Labeling, Penalties, Reporting and recordkeeping requirements, Warranties. 40 CFR Part 1042

Environmental protection, Administrative practice and procedure,

Air pollution control, Confidential business information, Imports,

Incorporation by reference, Labeling, Penalties, Vessels, Reporting and recordkeeping requirements, Warranties. 40 CFR Parts 1045, 1048, 1051, and 1054

Environmental protection, Administrative practice and procedure,

Air pollution control, Confidential business information, Imports,

Incorporation by reference, Labeling, Penalties, Reporting and recordkeeping requirements, Warranties. 40 CFR Part 1065

Environmental protection, Administrative practice and procedure,

Incorporation by reference, Reporting and recordkeeping requirements,

Research.

Dated: September 22, 2009.

Lisa P. Jackson,

Administrator. 0

For the reasons stated in the preamble, title 40, chapter I, of the

Code of Federal Regulations is amended as follows:

PART 86--[AMENDED] 0 1. The authority citation for part 86 continues to read as follows:

Authority: 42 U.S.C. 7401-7671q.

Subpart A--[Amended] 0 2. Section 86.007-23 is amended by adding paragraph (n) to read as follows:

Sec. 86.007-23 Required data.

* * * * *

(n) Measure CO2, N2O, and CH4with each low-hour certification test for heavy-duty engines using the procedures specified in 40 CFR part 1065 as specified in this paragraph

(n). Report these values in your application for certification. The requirements of this paragraph (n) apply starting with model year 2011 for CO2and 2012 for CH4. The requirements of this paragraph (n) related to N2O emissions apply for engine families that depend on NOxaftertreatment to meet emission standards starting with model year 2013. These measurements are not required for NTE testing. Use the same units and calculations as for your other results to report a single weighted value for

CO2, N2O, and CH4for each test. Round the final values as follows:

(1) Round CO2to the nearest 1 g/bhp-hr.

(2) Round N2O to the nearest 0.001 g/bhp-hr.

(3) Round CH4to the nearest 0.001 g/bhp-hr. 0 3. Section 86.078-3 is amended by removing the paragraph designation

``(a)'' and adding the abbreviations CH4and N2O in alphanumeric order to read as follows:

Sec. 86.078-3 Abbreviations.

* * * * *

CH4methane.

* * * * *

N2O nitrous oxide.

* * * * *

Subpart E--[Amended] 0 4. Section 86.403-78 is amended by adding the abbreviations

CH4and N2O in alphanumeric order to read as follows:

Sec. 86.403-78 Abbreviations.

* * * * *

CH4methane.

* * * * *

N2O nitrous oxide.

* * * * * 0 5. Section 86.431-78 is amended by adding paragraph (e) to read as follows:

Sec. 86.431-78 Data submission.

* * * * *

(e) Measure CO2, N2O, and CH4as described in this paragraph (e) with each zero kilometer certification test (if one is conducted) and with each test conducted at the applicable minimum test distance as defined in Sec. 86.427-78. Use the analytical equipment and procedures specified in 40 CFR part 1065 as needed to measure N2O and CH4. Report these values in your application for certification. The requirements of this paragraph (e) apply starting with model year 2011 for CO2 and 2012 for CH4. The requirements of this paragraph (e) related to N2O emissions apply for engine families that depend on NOXaftertreatment to meet emission standards starting with model year 2013. Small-volume manufacturers (as defined in Sec. 86.410-2006(e)) may omit measurement of N2O and

CH4; other manufacturers may provide appropriate data and/or information and omit measurement of N2O and CH4 as described in 40 CFR 1065.5. Use the same measurement methods as for your other results to report a single value for CO2,

N2O, and CH4. Round the final values as follows:

(1) Round CO2to the nearest 1 g/km.

(2) Round N2O to the nearest 0.001 g/km.

(3) Round CH4to the nearest 0.001 g/km.

PART 87--[AMENDED] 0 6. The authority citation for part 87 is revised to read as follows:

Authority: 42 U.S.C. 7401-7671q.

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Subpart A--[Amended] 0 7. Section 87.2 is amended by revising the section heading and adding the abbreviation CO2in alphanumeric order to read as follows:

Sec. 87.2 Acronyms and abbreviations.

* * * * *

CO2Carbon dioxide.

* * * * * 0 8. Section 87.64 is revised to read as follows:

Sec. 87.64 Sampling and analytical procedures for measuring gaseous exhaust emissions.

(a) The system and procedures for sampling and measurement of gaseous emissions shall be as specified by Appendices 3 and 5 to ICAO

Annex 16 (incorporated by reference in Sec. 87.8).

(b) Starting January 1, 2011, report CO2values along with your emission levels of regulated NOXto the

Administrator for engines of a type or model of which the date of manufacture of the first individual production model was on or after

January 1, 2011. By January 1, 2011, report CO2values along with your emission levels of regulated NOXto the

Administrator for engines currently in production and of a type or model for which the date of manufacture of the individual engine was before January 1, 2011. Round CO2to the nearest 1 g/ kilonewton rO.

(c) Report CO2by calculation from fuel mass flow rate measurements in Appendices 3 and 5 to ICAO Annex 16, volume II or alternatively, according to the measurement criteria of CO2 in Appendices 3 and 5 to ICAO Annex 16, volume II.

PART 89--[AMENDED] 0 9. The authority citation for part 89 continues to read as follows:

Authority: 42 U.S.C. 7401-7671q.

Subpart B--[Amended] 0 10. Section 89.115 is amended by revising paragraph (d)(9) to read as follows:

Sec. 89.115 Application for certificate.

* * * * *

(d) * * *

(9) All test data obtained by the manufacturer on each test engine, including CO2as specified in Sec. 89.407(d)(1);

* * * * *

Subpart E--[Amended] 0 11. Section 89.407 is amended by revising paragraph (d)(1) to read as follows:

Sec. 89.407 Engine dynamometer test run.

* * * * *

(d) * * *

(1) Measure HC, CO, CO2, and NOx concentrations in the exhaust sample. Use the same units and modal calculations as for your other results to report a single weighted value for CO2; round CO2to the nearest 1 g/kW- hr.

* * * * *

PART 90--[AMENDED] 0 12. The authority citation for part 90 continues to read as follows:

Authority: 42 U.S.C. 7401-7671q.

Subpart B--[Amended] 0 13. Section 90.107 is amended by revising paragraph (d)(8) to read as follows:

Sec. 90.107 Application for certification.

* * * * *

(d) * * *

(8) All test data obtained by the manufacturer on each test engine, including CO2as specified in Sec. 90.409(c)(1);

* * * * *

Subpart E--[Amended] 0 14. Section 90.409 is amended by revising paragraph (c)(1) to read as follows:

Sec. 90.409 Engine dynamometer test run.

* * * * *

(1) Measure HC, CO, CO2, and NOX concentrations in the exhaust sample. Use the same units and modal calculations as for your other results to report a single weighted value for CO2; round CO2to the nearest 1 g/kW- hr.

* * * * *

PART 94--[AMENDED] 0 15. The authority citation for part 94 continues to read as follows:

Authority: 42 U.S.C. 7401-7671q.

Subpart A--[Amended] 0 16. Section 94.3 is amended by adding the abbreviation CH4 in alphanumeric order to read as follows:

Sec. 94.3 Abbreviations.

* * * * *

CH4methane.

* * * * *

Subpart B--[Amended] 0 17. Section 94.103 is amended by adding paragraph (c) to read as follows:

Sec. 94.103 Test procedures for Category 1 marine engines.

* * * * *

(c) Measure CH4as specified in 40 CFR 1042.235 starting in the 2012 model year. 0 18. Section 94.104 is amended by adding paragraph (e) to read as follows:

Sec. 94.104 Test procedures for Category 2 marine engines.

* * * * *

(e) Measure CO2as described in 40 CFR 92.129 through the 2010 model year. Measure CO2as specified in 40 CFR 1042.235 starting in the 2011 model year. Measure CH4as specified in 40 CFR 1042.235 starting in the 2012 model year.

Subpart C--[Amended] 0 19. Section 94.203 is amended by revising paragraph (d)(10) to read as follows:

Sec. 94.203 Application for certification.

* * * * *

(d) * * *

(10) All test data obtained by the manufacturer on each test engine, including CO2and CH4as specified in 40

CFR 89.407(d)(1) and Sec. 94.103(c) for Category 1 engines, Sec. 94.104(e) for Category 2 engines, and Sec. 94.109(d) for Category 3 engines. Small-volume manufacturers may omit measurement and reporting of CH4.

* * * * * 0 20. Add part 98 to read as follows:

PART 98--MANDATORY GREENHOUSE GAS REPORTING

Sec.

Subpart A--General Provisions 98.1 Purpose and scope. 98.2 Who must report? 98.3 What are the general monitoring, reporting, recordkeeping and verification requirements of this part? 98.4 Authorization and responsibilities of the designated representative. 98.5 How is the report submitted? 98.6 Definitions. 98.7 What standardized methods are incorporated by reference into this part? 98.8 What are the compliance and enforcement provisions of this part? 98.9 Addresses.

Table A-1 to Subpart A of Part 98--Global Warming Potentials (100-

Year Time Horizon)

Table A-2 to Subpart A of Part 98--Units of Measure Conversions

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Subpart B--[RESERVED]

Subpart C--General Stationary Fuel Combustion Sources 98.30 Definition of the source category. 98.31 Reporting threshold. 98.32 GHGs to report. 98.33 Calculating GHG emissions. 98.34 Monitoring and QA/QC requirements. 98.35 Procedures for estimating missing data. 98.36 Data reporting requirements. 98.37 Records that must be retained. 98.38 Definitions.

Table C-1 to Subpart C of Part 98--Default CO2Emission

Factors and High Heat Values for Various Types of Fuel

Table C-2 to Subpart C of Part 98--Default CH4and

N2O Emission Factors for Various Types of Fuel

Subpart D--Electricity Generation 98.40 Definition of the source category. 98.41 Reporting threshold. 98.42 GHGs to report. 98.43 Calculating GHG emissions. 98.44 Monitoring and QA/QC requirements 98.45 Procedures for estimating missing data. 98.46 Data reporting requirements. 98.47 Records that must be retained. 98.48 Definitions.

Subpart E--Adipic Acid Production 98.50 Definition of source category. 98.51 Reporting threshold. 98.52 GHGs to report. 98.53 Calculating GHG emissions. 98.54 Monitoring and QA/QC requirements 98.55 Procedures for estimating missing data. 98.56 Data reporting requirements. 98.57 Records that must be retained. 98.58 Definitions.

Subpart F--Aluminum Production 98.60 Definition of the source category. 98.61 Reporting threshold. 98.62 GHGs to report. 98.63 Calculating GHG emissions. 98.64 Monitoring and QA/QC requirements. 98.65 Procedures for estimating missing data. 98.66 Data reporting requirements. 98.67 Records that must be retained. 98.68 Definitions.

Table F-1 to Subpart F of Part 98--Slope and Overvoltage

Coefficients for the Calculation of PFC Emissions From Aluminum

Production

Table F-2 to Subpart F of Part 98--Default Data Sources for

Parameters Used for CO2Emissions

Subpart G--Ammonia Manufacturing 98.70 Definition of source category. 98.71 Reporting threshold. 98.72 GHGs to report. 98.73 Calculating GHG emissions. 98.74 Monitoring and QA/QC requirements. 98.75 Procedures for estimating missing data. 98.76 Data reporting requirements. 98.77 Records that must be retained. 98.78 Definitions.

Subpart H--Cement Production 98.80 Definition of the source category. 98.81 Reporting threshold. 98.82 GHGs to report. 98.83 Calculating GHG emissions. 98.84 Monitoring and QA/QC requirements. 98.85 Procedures for estimating missing data. 98.86 Data reporting requirements. 98.87 Records that must be retained. 98.88 Definitions.

Subpart I--[RESERVED]

Subpart J--[RESERVED]

Subpart K--Ferroalloy Production 98.110 Definition of the source category. 98.111 Reporting threshold. 98.112 GHGs to report. 98.113 Calculating GHG emissions. 98.114 Monitoring and QA/QC requirements. 98.115 Procedures for estimating missing data. 98.116 Data reporting requirements. 98.117 Records that must be retained. 98.118 Definitions.

Table K-1 to Subpart K of Part 98--Electric Arc Furnace (EAF) CH4

Emission Factors

Subpart L--[RESERVED]

Subpart M--[RESERVED]

Subpart N--Glass Production 98.140 Definition of the source category. 98.141 Reporting threshold. 98.142 GHGs to report. 98.143 Calculating GHG emissions. 98.144 Monitoring and QA/QC requirements. 98.145 Procedures for estimating missing data. 98.146 Data reporting requirements. 98.147 Records that must be retained. 98.148 Definitions.

Table N-1 to Subpart N of Part 98--CO2Emission Factors for Carbonate-Based Raw Materials

Subpart O--HCFC-22 Production and HFC-23 Destruction 98.150 Definition of the source category. 98.151 Reporting threshold. 98.152 GHGs to report. 98.153 Calculating GHG emissions. 98.154 Monitoring and QA/QC requirements. 98.155 Procedures for estimating missing data. 98.156 Data reporting requirements. 98.157 Records that must be retained. 98.158 Definitions.

Table O-1 to Subpart O of Part 98--Emission Factors for Equipment

Leaks

Subpart P--Hydrogen Production 98.160 Definition of the source category. 98.161 Reporting threshold. 98.162 GHGs to report. 98.163 Calculating GHG emissions. 98.164 Monitoring and QA/QC requirements. 98.165 Procedures for estimating missing data. 98.166 Data reporting requirements. 98.167 Records that must be retained. 98.168 Definitions.

Subpart Q--Iron and Steel Production 98.170 Definition of the source category. 98.171 Reporting threshold. 98.172 GHGs to report. 98.173 Calculating GHG emissions. 98.174 Monitoring and QA/QC requirements. 98.175 Procedures for estimating missing data. 98.176 Data reporting requirements. 98.177 Records that must be retained. 98.178 Definitions.

Subpart R--Lead Production 98.180 Definition of the source category. 98.181 Reporting threshold. 98.182 GHGs to report. 98.183 Calculating GHG emissions. 98.184 Monitoring and QA/QC requirements. 98.185 Procedures for estimating missing data. 98.186 Data reporting procedures. 98.187 Records that must be retained. 98.188 Definitions.

Subpart S--Lime Manufacturing 98.190 Definition of the source category. 98.191 Reporting threshold. 98.192 GHGs to report. 98.193 Calculating GHG emissions. 98.194 Monitoring and QA/QC requirements. 98.195 Procedures for estimating missing data. 98.196 Data reporting requirements. 98.197 Records that must be retained. 98.198 Definitions.

Table S-1 to Subpart S of Part 98--Basic Parameters for the

Calculation of Emission Factors for Lime Production

Subpart T--[RESERVED]

Subpart U--Miscellaneous Uses of Carbonate 98.210 Definition of the source category. 98.211 Reporting threshold. 98.212 GHGs to report. 98.213 Calculating GHG emissions. 98.214 Monitoring and QA/QC requirements. 98.215 Procedures for estimating missing data. 98.216 Data reporting requirements. 98.217 Records that must be retained. 98.218 Definitions.

Table U-1 to Subpart U of Part 98--CO2Emission Factors for Common Carbonates

Subpart V--Nitric Acid Production 98.220 Definition of source category. 98.221 Reporting threshold. 98.222 GHGs to report. 98.223 Calculating GHG emissions. 98.224 Monitoring and QA/QC requirements. 98.225 Procedures for estimating missing data. 98.226 Data reporting requirements. 98.227 Records that must be retained. 98.228 Definitions.

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Subpart W--[RESERVED]

Subpart X--Petrochemical Production 98.240 Definition of the source category. 98.241 Reporting threshold. 98.242 GHGs to report. 98.243 Calculating GHG emissions. 98.244 Monitoring and QA/QC requirements. 98.245 Procedures for estimating missing data. 98.246 Data reporting requirements. 98.247 Records that must be retained. 98.248 Definitions.

Subpart Y--Petroleum Refineries 98.250 Definition of source category. 98.251 Reporting threshold. 98.252 GHGs to report. 98.253 Calculating GHG emissions. 98.254 Monitoring and QA/QC requirements. 98.255 Procedures for estimating missing data. 98.256 Data reporting requirements. 98.257 Records that must be retained. 98.258 Definitions.

Subpart Z--Phosphoric Acid Production 98.260 Definition of the source category. 98.261 Reporting threshold. 98.262 GHGs to report. 98.263 Calculating GHG emissions. 98.264 Monitoring and QA/QC requirements. 98.265 Procedures for estimating missing data. 98.266 Data reporting requirements. 98.267 Records that must be retained. 98.268 Definitions.

Table Z-1 to Subpart Z of Part 98--Default Chemical Composition of

Phosphate Rock by Origin

Subpart AA--Pulp and Paper Manufacturing 98.270 Definition of source category. 98.271 Reporting threshold. 98.272 GHGs to report. 98.273 Calculating GHG emissions. 98.274 Monitoring and QA/QC requirements. 98.275 Procedures for estimating missing data. 98.276 Data reporting requirements. 98.277 Records that must be retained. 98.278 Definitions.

Table AA-1 to Subpart AA of Part 98--Kraft Pulping Liquor Emissions

Factors for Biomass-Based CO2, CH4, and

N2O

Table AA-2 to Subpart AA of Part 98--Kraft Lime Kiln and Calciner

Emissions Factors for Fossil Fuel-Based CO2,

CH4, and N2O

Subpart BB--Silicon Carbide Production 98.280 Definition of the source category. 98.281 Reporting threshold. 98.282 GHGs to report. 98.283 Calculating GHG emissions. 98.284 Monitoring and QA/QC requirements. 98.285 Procedures for estimating missing data. 98.286 Data reporting requirements. 98.287 Records that must be retained. 98.288 Definitions.

Subpart CC--Soda Ash Manufacturing 98.290 Definition of the source category. 98.291 Reporting threshold. 98.292 GHGs to report. 98.293 Calculating GHG emissions. 98.294 Monitoring and QA/QC requirements. 98.295 Procedures for estimating missing data. 98.296 Data reporting requirements. 98.297 Records that must be retained. 98.298 Definitions.

Subpart DD--[RESERVED]

Subpart EE--Titanium Dioxide Production 98.310 Definition of the source category. 98.311 Reporting threshold. 98.312 GHGs to report. 98.313 Calculating GHG emissions. 98.314 Monitoring and QA/QC requirements. 98.315 Procedures for estimating missing data. 98.316 Data reporting requirements. 98.317 Records that must be retained. 98.318 Definitions.

Subpart FF--[RESERVED]

Subpart GG--Zinc Production 98.330 Definition of the source category. 98.331 Reporting threshold. 98.332 GHGs to report. 98.333 Calculating GHG emissions. 98.334 Monitoring and QA/QC requirements. 98.335 Procedures for estimating missing data. 98.336 Data reporting requirements. 98.337 Records that must be retained. 98.338 Definitions.

Subpart HH--Municipal Solid Waste Landfills 98.340 Definition of the source category. 98.341 Reporting threshold. 98.342 GHGs to report. 98.343 Calculating GHG emissions. 98.344 Monitoring and QA/QC requirements. 98.345 Procedures for estimating missing data. 98.346 Data reporting requirements. 98.347 Records that must be retained. 98.348 Definitions.

Table HH-1 to Subpart HH of Part 98--Emissions Factors, Oxidation

Factors and Methods

Table HH-2 to Subpart HH of Part 98--U.S. Per Capita Waste Disposal

Rates

Table HH-3 to Subpart HH of Part 98--Landfill Gas Collection

Efficiencies

Subpart II--[RESERVED]

Subpart JJ--Manure Management 98.360 Definition of the source category. 98.361 Reporting threshold. 98.362 GHGs to report. 98.363 Calculating GHG emissions. 98.364 Monitoring and QA/QC requirements. 98.365 Procedures for estimating missing data. 98.366 Data reporting requirements. 98.367 Records that must be retained. 98.368 Definitions.

Table JJ-1 to Subpart JJ of Part 98--Animal Population Threshold

Level Below which Facilities are not required to report Emissions under Subpart JJ

Table JJ-2 to Subpart JJ of Part 98--Waste Characteristics Data

Table JJ-3 to Subpart JJ of Part 98--State-Specific Volatile Solids

(VS) and Nitrogen (N) Excretion Rates for Cattle

Table JJ-4 to Subpart JJ of Part 98--Volatile Solids and Nitrogen

Removal through Solids Separation

Table JJ-5 to Subpart JJ of Part 98--Methane Conversion Factors

Table JJ-6 to Subpart JJ of Part 98--Collection Efficiencies of

Anaerobic Digesters

Table JJ-7 to Subpart JJ of Part 98--Nitrous Oxide Emission Factors

(kg N2O-N/kg Kjdl N)

Subpart KK--[RESERVED]

Subpart LL--Suppliers of Coal-based Liquid Fuels 98.380 Definition of the source category. 98.381 Reporting threshold. 98.382 GHGs to report. 98.383 Calculating GHG emissions. 98.384 Monitoring and QA/QC requirements. 98.385 Procedures for estimating missing data. 98.386 Data reporting requirements. 98.387 Records that must be retained. 98.388 Definitions.

Subpart MM--Suppliers of Petroleum Products 98.390 Definition of the source category. 98.391 Reporting threshold. 98.392 GHGs to report. 98.393 Calculating GHG emissions. 98.394 Monitoring and QA/QC requirements. 98.395 Procedures for estimating missing data. 98.396 Data reporting requirements. 98.397 Records that must be retained. 98.398 Definitions.

Table MM-1 to Subpart MM--Default CO2Factors for

Petroleum Products

Table MM-2 to Subpart MM--Default Factors for Biomass-Based Fuels and Biomass

Subpart NN--Suppliers of Natural Gas and Natural Gas Liquids 98.400 Definition of the source category. 98.401 Reporting threshold. 98.402 GHGs to report. 98.403 Calculating GHG emissions. 98.404 Monitoring and QA/QC requirements. 98.405 Procedures for estimating missing data. 98.406 Data reporting requirements. 98.407 Records that must be retained. 98.408 Definitions.

Table NN-1 to Subpart NN of Part 98--Default Factors for Calculation

Methodology 1 of this Subpart

Table NN-2 to Subpart NN of Part 98--Lookup Default Values for

Calculation Methodology 2 of this Subpart

Subpart OO--Suppliers of Industrial Greenhouse Gases 98.410 Definition of the source category.

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98.411 Reporting threshold. 98.412 GHGs to report. 98.413 Calculating GHG emissions. 98.414 Monitoring and QA/QC requirements. 98.415 Procedures for estimating missing data. 98.416 Data reporting requirements. 98.417 Records that must be retained. 98.418 Definitions.

Subpart PP--Suppliers of Carbon Dioxide 98.420 Definition of the source category. 98.421 Reporting threshold. 98.422 GHGs to report. 98.423 Calculating CO2supply. 98.424 Monitoring and QA/QC requirements. 98.425 Procedures for estimating missing data. 98.426 Data reporting requirements. 98.427 Records that must be retained. 98.428 Definitions.

Authority: 42 U.S.C. 7401, et seq.

Subpart A--General Provisions

Sec. 98.1 Purpose and scope.

(a) This part establishes mandatory greenhouse gas (GHG) reporting requirements for owners and operators of certain facilities that directly emit GHG as well as for certain fossil fuel suppliers and industrial GHG suppliers. For suppliers, the GHGs reported are the quantity that would be emitted from combustion or use of the products supplied.

(b) Owners and operators of facilities and suppliers that are subject to this part must follow the requirements of subpart A and all applicable subparts of this part. If a conflict exists between a provision in subpart A and any other applicable subpart, the requirements of the subparts B through PP of this part shall take precedence.

Sec. 98.2 Who must report?

(a) The GHG reporting requirements and related monitoring, recordkeeping, and reporting requirements of this part apply to the owners and operators of any facility that is located in the United

States and that meets the requirements of either paragraph (a)(1),

(a)(2), or (a)(3) of this section; and any supplier that meets the requirements of paragraph (a)(4) of this section:

(1) A facility that contains any source category (as defined in subparts C through JJ of this part) that is listed in this paragraph

(a)(1) in any calendar year starting in 2010. For these facilities, the annual GHG report must cover all source categories and GHGs for which calculation methodologies are provided in subparts C through JJ of this part.

(i) Electricity generation (units that report CO2 emissions year-round through 40 CFR part 75).

(ii) Adipic acid production.

(iii) Aluminum production.

(iv) Ammonia manufacturing.

(v) Cement production.

(vi) HCFC-22 production.

(vii) HFC-23 destruction processes that are not collocated with a

HCFC-22 production facility and that destroy more than 2.14 metric tons of HFC-23 per year.

(viii) Lime manufacturing.

(ix) Nitric acid production.

(x) Petrochemical production.

(xi) Petroleum refineries.

(xii) Phosphoric acid production.

(xiii) Silicon carbide production.

(xiv) Soda ash production.

(xv) Titanium dioxide production.

(xvi) Municipal solid waste landfills that generate CH4 in amounts equivalent to 25,000 metric tons CO2e or more per year, as determined according to subpart HH of this part.

(xvii) Manure management systems with combined CH4and

N2O emissions in amounts equivalent to 25,000 metric tons

CO2e or more per year, as determined according to subpart JJ of this part.

(2) A facility that contains any source category (as defined in subparts C through JJ of this part) that is listed in this paragraph

(a)(2) in any calendar year starting in 2010 and that emits 25,000 metric tons CO2e or more per year in combined emissions from stationary fuel combustion units, miscellaneous uses of carbonate, and all source categories that are listed in this paragraph. For these facilities, the annual GHG report must cover all source categories and

GHGs for which calculation methodologies are provided in subparts C through JJ of this part.

(i) Ferroalloy Production.

(ii) Glass Production.

(iii) Hydrogen Production.

(iv) Iron and Steel Production.

(v) Lead Production.

(vi) Pulp and Paper Manufacturing.

(vii) Zinc Production.

(3) A facility that in any calendar year starting in 2010 meets all three of the conditions listed in this paragraph (a)(3). For these facilities, the annual GHG report must cover emissions from stationary fuel combustion sources only.

(i) The facility does not meet the requirements of either paragraph

(a)(1) or (a)(2) of this section.

(ii) The aggregate maximum rated heat input capacity of the stationary fuel combustion units at the facility is 30 mmBtu/hr or greater.

(iii) The facility emits 25,000 metric tons CO2e or more per year in combined emissions from all stationary fuel combustion sources.

(4) A supplier (as defined in subparts KK through PP of this part) that provides products listed in this paragraph (a)(4) in any calendar year starting in 2010. For these suppliers, the annual GHG report must cover all applicable products for which calculation methodologies are provided in subparts KK through PP of this part.

(i) Coal-to-liquids suppliers, as specified in this paragraph

(a)(4)(i).

(A) All producers of coal-to-liquid products.

(B) Importers of an annual quantity of coal-to-liquid products that is equivalent to 25,000 metric tons CO2e or more.

(ii) Petroleum product suppliers, as specified in this paragraph

(a)(4)(ii):

(A) All petroleum refineries that distill crude oil.

(B) Importers of an annual quantity of petroleum products that is equivalent to 25,000 metric tons CO2e or more.

(iii) Natural gas and natural gas liquids suppliers, as specified in this paragraph (a)(4)(iii):

(A) All natural gas fractionators.

(B) All local natural gas distribution companies.

(iv) Industrial greenhouse gas suppliers, as specified in this paragraph (a)(4)(iv):

(A) All producers of industrial greenhouse gases.

(B) Importers of industrial greenhouse gases with annual bulk imports of N2O, fluorinated GHG, and CO2that in combination are equivalent to 25,000 metric tons CO2e or more.

(C) Exporters of industrial greenhouse gases with annual bulk exports of N2O, fluorinated GHG, and CO2that in combination are equivalent to 25,000 metric tons CO2e or more.

(v) Carbon dioxide suppliers, as specified in this paragraph

(a)(4)(v).

(A) All producers of CO2.

(B) Importers of CO2with annual bulk imports of

N2O, fluorinated GHG, and CO2that in combination are equivalent to 25,000 metric tons CO2e or more.

(5) Research and development activities are not considered to be part of any source category defined in this part.

(b) To calculate GHG emissions for comparison to the 25,000 metric ton CO2e per year emission threshold in paragraph (a)(2) of this section, the owner or operator shall calculate annual

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CO2e emissions, as described in paragraphs (b)(1) through

(b)(4) of this section.

(1) Calculate the annual emissions of CO2,

CH4, N2O,and each fluorinated GHG in metric tons from all applicable source categories listed in paragraph (a)(2) of this section. The GHG emissions shall be calculated using the calculation methodologies specified in each applicable subpart and available company records. Include emissions from only those gases listed in Table A-1 of this subpart.

(2) For each general stationary fuel combustion unit, calculate the annual CO2emissions in metric tons using any of the four calculation methodologies specified in Sec. 98.33(a). Calculate the annual CH4and N2O emissions from the stationary fuel combustion sources in metric tons using the appropriate equation in Sec. 98.33(c). Exclude carbon dioxide emissions from the combustion of biomass, but include emissions of CH4and N2O from biomass combustion.

(3) For miscellaneous uses of carbonate, calculate the annual

CO2emissions in metric tons using the procedures specified in subpart U of this part.

(4) Sum the emissions estimates from paragraphs (b)(1), (b)(2), and

(b)(3) of this section for each GHG and calculate metric tons of

CO2e using Equation A-1 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.000

Where:

CO2e = Carbon dioxide equivalent, metric tons/year.

GHGi= Mass emissions of each greenhouse gas listed in

Table A-1 of this subpart, metric tons/year.

GWPi= Global warming potential for each greenhouse gas from Table A-1 of this subpart. n = The number of greenhouse gases emitted.

(5) For purpose of determining if an emission threshold has been exceeded, include in the emissions calculation any CO2that is captured for transfer off site.

(c) To calculate GHG emissions for comparison to the 25,000 metric ton CO2e/year emission threshold for stationary fuel combustion under paragraph (a)(3) of this section, calculate

CO2, CH4, and N2O emissions from each stationary fuel combustion unit by following the methods specified in paragraph (b)(2) of this section. Then, convert the emissions of each

GHG to metric tons CO2e per year using Equation A-1 of this section, and sum the emissions for all units at the facility.

(d) To calculate GHG quantities for comparison to the 25,000 metric ton CO2per year threshold for importers and exporters of coal-to-liquid products under paragraph (a)(4)(i) of this section, calculate the mass in metric tons per year of CO2that would result from the complete combustion or oxidation of the quantity of coal-to-liquid products that are imported during the reporting year and that are exported during the reporting year. Calculate the emissions using the methodology specified in subpart LL of this part.

(e) To calculate GHG quantities for comparison to the 25,000 metric ton CO2e per year threshold for importers and exporters of petroleum products under paragraph (a)(4)(ii) of this section, calculate the mass in metric tons per year of CO2that would result from the complete combustion or oxidation of the volume of petroleum products and natural gas liquids that are imported during the reporting year and that are exported during the reporting year.

Calculate the emissions using the methodology specified in subpart MM of this part.

(f) To calculate GHG quantities for comparison to the 25,000 metric ton CO2e per year threshold under paragraph (a)(4) of this section for importers and exporters of industrial greenhouse gases and for importers and exporters of CO2,the owner or operator shall calculate the mass in metric tons per year of CO2e imports and exports as described in paragraphs (f)(1) through (f)(3) of this section.

(1) Calculate the mass in metric tons per year of CO2,

N2O, and each fluorinated GHG that is imported and the mass in metric tons per year of CO2, N2O, and each fluorinated GHG that is exported during the year. Include only those gases listed in Table A-1 of this subpart.

(2) Convert the mass of each imported and each GHG exported from paragraph (f)(1) of this section to metric tons of CO2e using Equation A-1 of this section.

(3) Sum the total annual metric tons of CO2e in paragraph (f)(2) of this section for all imported GHGs. Sum the total annual metric tons of CO2e in paragraph (f)(2) of this section for all exported GHGs.

(g) If a capacity or generation reporting threshold in paragraph

(a)(1) of this section applies, the owner or operator shall review the appropriate records and perform any necessary calculations to determine whether the threshold has been exceeded.

(h) An owner or operator of a facility or supplier that does not meet the applicability requirements of paragraph (a) of this section is not subject to this rule. Such owner or operator would become subject to the rule and reporting requirements Sec. 98.3(b)(3), if a facility or supplier exceeds the applicability requirements of paragraph (a) of this section at a later time. Thus, the owner or operator should reevaluate the applicability to this part (including the revising of any relevant emissions calculations or other calculations) whenever there is any change that could cause a facility or supplier to meet the applicability requirements of paragraph (a) of this section. Such changes include but are not limited to process modifications, increases in operating hours, increases in production, changes in fuel or raw material use, addition of equipment, and facility expansion.

(i) Except as provided in this paragraph, once a facility or supplier is subject to the requirements of this part, the owner or operator must continue for each year thereafter to comply with all requirements of this part, including the requirement to submit annual

GHG reports, even if the facility or supplier does not meet the applicability requirements in paragraph (a) of this section in a future year.

(1) If reported emissions are less than 25,000 metric tons

CO2e per year for five consecutive years, then the owner or operator may discontinue complying with this part provided that the owner or operator submits a notification to the Administrator that announces the cessation of reporting and explains the reasons for the reduction in emissions. The notification shall be submitted no later than March 31 of the year immediately following the fifth consecutive year of emissions less than 25,000 tons CO2e per year. The owner or operator must maintain the corresponding records required under Sec. 98.3(g) for each of the five consecutive years and retain such records for three years following the year that reporting was discontinued. The owner or operator must resume reporting if annual emissions in any future calendar year increase to 25,000 metric tons

CO2e per year or more.

(2) If reported emissions are less than 15,000 metric tons

CO2e per year for three consecutive years, then the owner or operator may discontinue complying with this part provided that the owner or operator submits a notification to the Administrator that announces the cessation of reporting and explains the reasons for the reduction in emissions. The notification shall be submitted no later than March 31 of the year immediately following the third consecutive year of emissions less than 15,000 tons CO2e per year. The owner or operator must maintain the corresponding records required under Sec. 98.3(g) for each of the three

Page 56379

consecutive years and retain such records for three years following the year that reporting was discontinued. The owner or operator must resume reporting if annual emissions in any future calendar year increase to 25,000 metric tons CO2e per year or more.

(3) If the operations of a facility or supplier are changed such that all applicable GHG-emitting processes and operations listed in paragraphs (a)(1) through (a)(4) of this section cease to operate, then the owner or operator is exempt from reporting in the years following the year in which cessation of such operations occurs, provided that the owner or operator submits a notification to the Administrator that announces the cessation of reporting and certifies to the closure of all GHG-emitting processes and operations. This paragraph (i)(2) does not apply to seasonal or other temporary cessation of operations. This paragraph (i)(2) does not apply to facilities with municipal solid waste landfills. The owner or operator must resume reporting for any future calendar year during which any of the GHG-emitting processes or operations resume operation.

(j) Table A-2 of this subpart provides a conversion table for some of the common units of measure used in part 98.

Sec. 98.3 What are the general monitoring, reporting, recordkeeping and verification requirements of this part?

The owner or operator of a facility or supplier that is subject to the requirements of this part must submit GHG reports to the

Administrator, as specified in this section.

(a) General. Except as provided in paragraph (d) of this section, follow the procedures for emission calculation, monitoring, quality assurance, missing data, recordkeeping, and reporting that are specified in each relevant subpart of this part.

(b) Schedule. The annual GHG report must be submitted no later than

March 31 of each calendar year for GHG emissions in the previous calendar year.

(1) For an existing facility or supplier that began operation before January 1, 2010, report emissions for calendar year 2010 and each subsequent calendar year.

(2) For a new facility or supplier that begins operation on or after January 1, 2010, report emissions beginning with the first operating month and ending on December 31 of that year. Each subsequent annual report must cover emissions for the calendar year, beginning on

January 1 and ending on December 31.

(3) For any facility or supplier that becomes subject to this rule because of a physical or operational change that is made after January 1, 2010, report emissions for the first calendar year in which the change occurs, beginning with the first month of the change and ending on December 31 of that year. For a facility or supplier that becomes subject to this rule solely because of an increase in hours of operation or level of production, the first month of the change is the month in which the increased hours of operation or level of production, if maintained for the remainder of the year, would cause the facility or supplier to exceed the applicable threshold. Each subsequent annual report must cover emissions for the calendar year, beginning on January 1 and ending on December 31.

(d) of this section, each annual GHG report shall contain the following information:

(1) Facility name or supplier name (as appropriate) and physical street address including the city, state, and zip code.

(2) Year and months covered by the report.

(3) Date of submittal.

(4) For facilities, report annual emissions of CO2,

CH4,N2O, and each fluorinated GHG (as defined in

Sec. 98.6) as follows:

(i) Annual emissions (excluding biogenic CO2) aggregated for all GHG from all applicable source categories in subparts C through

JJ of this part and expressed in metric tons of CO2e calculated using Equation A-1 of this subpart.

(ii) Annual emissions of biogenic CO2aggregated for all applicable source categories in subparts C through JJ of this part.

(iii) Annual emissions from each applicable source category in subparts C through JJ of this part, expressed in metric tons of each

GHG listed in paragraphs (c)(4)(iii)(A) through (c)(4)(iii)(E) of this section.

(A) Biogenic CO2.

(B) CO2(excluding biogenic CO2).

(D) N2O.

(E) Each fluorinated GHG (including those not listed in Table A-1 of this subpart).

(iv) Emissions and other data for individual units. processes, activities, and operations as specified in the ``Data reporting requirements'' section of each applicable subpart of this part.

(5) For suppliers, report annual quantities of CO2,

CH4,N2O, and each fluorinated GHG (as defined in

Sec. 98.6) that would be emitted from combustion or use of the products supplied, imported, and exported during the year. Calculate and report quantities at the following levels:

(i) Total quantity of GHG aggregated for all GHG from all applicable supply categories in subparts KK through PP of this part and expressed in metric tons of CO2e calculated using Equation

A-1 of this subpart.

(ii) Quantity of each GHG from each applicable supply category in subparts KK through PP of this part, expressed in metric tons of each

GHG. For fluorinated GHG, report emissions of all fluorinated GHG, including those not listed in Table A-1 of this subpart.

(iii) Any other data specified in the ``Data reporting requirements'' section of each applicable subpart of this part.

(6) A written explanation, as required under Sec. 98.3(e), if you change emission calculation methodologies during the reporting period.

(7) A brief description of each ``best available monitoring method'' used according to paragraph (d) of this section, the parameter measured using the method, and the time period during which the ``best available monitoring method'' was used.

(8) Each data element for which a missing data procedure was used according to the procedures of an applicable subpart and the total number of hours in the year that a missing data procedure was used for each data element.

(9) A signed and dated certification statement provided by the designated representative of the owner or operator, according to the requirements of Sec. 98.4(e)(1).

(d) Special provisions for reporting year 2010.

(1) Best available monitoring methods. During January 1, 2010 through March 31, 2010, owners or operators may use best available monitoring methods for any parameter (e.g., fuel use, daily carbon content of feedstock by process line) that cannot reasonably be measured according to the monitoring and QA/QC requirements of a relevant subpart. The owner or operator must use the calculation methodologies and equations in the ``Calculating GHG Emissions'' sections of each relevant subpart, but may use the best available monitoring method for any parameter for which it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment by January 1, 2010. Starting no later than April 1, 2010, the owner or operator must discontinue using best available methods and begin following all applicable monitoring and QA/QC requirements of this part, except as

Page 56380

provided in paragraphs (d)(2) and (d)(3) of this section. Best available monitoring methods means any of the following methods specified in this paragraph:

(i) Monitoring methods currently used by the facility that do not meet the specifications of an relevant subpart.

(ii) Supplier data.

(iii) Engineering calculations.

(iv) Other company records.

(2) Requests for extension of the use of best available monitoring methods. The owner or operator may submit a request to the

Administrator to use one or more best available monitoring methods beyond March 31, 2010.

(i) Timing of request. The extension request must be submitted to

EPA no later than 30 days after the effective date of the GHG reporting rule.

(ii) Content of request. Requests must contain the following information:

(A) A list of specific item of monitoring instrumentation for which the request is being made and the locations where each piece of monitoring instrumentation will be installed.

(B) Identification of the specific rule requirements (by rule subpart, section, and paragraph numbers) for which the instrumentation is needed.

(D) If the reason for the extension is that the equipment cannot be purchased and delivered by April 1, 2010, include supporting documentation such as the date the monitoring equipment was ordered, investigation of alternative suppliers and the dates by which alternative vendors promised delivery, backorder notices or unexpected delays, descriptions of actions taken to expedite delivery, and the current expected date of delivery.

(E) If the reason for the extension is that the equipment cannot be installed without a process unit shutdown, include supporting documentation demonstrating that it is not practicable to isolate the equipment and install the monitoring instrument without a full process unit shutdown. Include the date of the most recent process unit shutdown, the frequency of shutdowns for this process unit, and the date of the next planned shutdown during which the monitoring equipment can be installed. If there has been a shutdown or if there is a planned process unit shutdown between promulgation of this part and April 1, 2010, include a justification of why the equipment could not be obtained and installed during that shutdown.

(F) A description of the specific actions the facility will take to obtain and install the equipment as soon as reasonably feasible and the expected date by which the equipment will be installed and operating.

(iii) Approval criteria. To obtain approval, the owner or operator must demonstrate to the Administrator's satisfaction that it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment by April 1, 2010. The use of best available methods will not be approved beyond December 31, 2010.

(3) Abbreviated emissions report for facilities containing only general stationary fuel combustion sources. In lieu of the report required by paragraph (c) of this section, the owner or operator of an existing facility that is in operation on January 1, 2010 and that meets the conditions of Sec. 98.2 (a)(3) may submit an abbreviated GHG report for the facility for GHGs emitted in 2010. The abbreviated report must be submitted by March 31, 2011. An owner or operator that submits an abbreviated report must submit a full GHG report according to the requirements of paragraph (c) of this section beginning in calendar year 2011. The abbreviated facility report must include the following information:

(i) Facility name and physical street address including the city, state and zip code.

(ii) The year and months covered by the report.

(iii) Date of submittal.

(iv) Total facility GHG emissions aggregated for all stationary fuel combustion units calculated according to any method specified in

Sec. 98.33(a) and expressed in metric tons of CO2,

CH4,N2O, and CO2e.

(v) Any facility operating data or process information used for the

GHG emission calculations.

(vi) A signed and dated certification statement provided by the designated representative of the owner or operator, according to the requirements of paragraph (e)(1) of this section.

(e) Emission calculations. In preparing the GHG report, you must use the calculation methodologies specified in the relevant subparts, except as specified in paragraph (d) of this section. For each source category, you must use the same calculation methodology throughout a reporting period unless you provide a written explanation of why a change in methodology was required.

(f) Verification. To verify the completeness and accuracy of reported GHG emissions, the Administrator may review the certification statements described in paragraphs (c)(8) and (d)(3)(vi) of this section and any other credible evidence, in conjunction with a comprehensive review of the GHG reports and periodic audits of selected reporting facilities. Nothing in this section prohibits the

Administrator from using additional information to verify the completeness and accuracy of the reports.

(g) Recordkeeping. An owner or operator that is required to report

GHGs under this part must keep records as specified in this paragraph.

Retain all required records for at least 3 years. The records shall be kept in an electronic or hard-copy format (as appropriate) and recorded in a form that is suitable for expeditious inspection and review. Upon request by the Administrator, the records required under this section must be made available to EPA. Records may be retained off site if the records are readily available for expeditious inspection and review.

For records that are electronically generated or maintained, the equipment or software necessary to read the records shall be made available, or, if requested by EPA, electronic records shall be converted to paper documents. You must retain the following records, in addition to those records prescribed in each applicable subpart of this part:

(1) A list of all units, operations, processes, and activities for which GHG emission were calculated.

(2) The data used to calculate the GHG emissions for each unit, operation, process, and activity, categorized by fuel or material type.

These data include but are not limited to the following information in this paragraph (g)(2):

(i) The GHG emissions calculations and methods used.

(ii) Analytical results for the development of site-specific emissions factors.

(iii) The results of all required analyses for high heat value, carbon content, and other required fuel or feedstock parameters.

(iv) Any facility operating data or process information used for the GHG emission calculations.

(3) The annual GHG reports.

(4) Missing data computations. For each missing data event, also retain a record of the duration of the event, actions taken to restore malfunctioning monitoring equipment, the cause of the event, and the actions taken to prevent or minimize occurrence in the future.

(5) A written GHG Monitoring Plan.

(i) At a minimum, the GHG Monitoring Plan shall include the elements listed in this paragraph (g)(5)(i).

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(A) Identification of positions of responsibility (i.e., job titles) for collection of the emissions data.

(B) Explanation of the processes and methods used to collect the necessary data for the GHG calculations.

(C) Description of the procedures and methods that are used for quality assurance, maintenance, and repair of all continuous monitoring systems, flow meters, and other instrumentation used to provide data for the GHGs reported under this part.

(ii) The GHG Monitoring Plan may rely on references to existing corporate documents (e.g., standard operating procedures, quality assurance programs under appendix F to 40 CFR part 60 or appendix B to 40 CFR part 75, and other documents) provided that the elements required by paragraph (g)(5)(i) of this section are easily recognizable.

(iii) The owner or operator shall revise the GHG Monitoring Plan as needed to reflect changes in production processes, monitoring instrumentation, and quality assurance procedures; or to improve procedures for the maintenance and repair of monitoring systems to reduce the frequency of monitoring equipment downtime.

(iv) Upon request by the Administrator, the owner or operator shall make all information that is collected in conformance with the GHG

Monitoring Plan available for review during an audit. Electronic storage of the information in the plan is permissible, provided that the information can be made available in hard copy upon request during an audit.

(6) The results of all required certification and quality assurance tests of continuous monitoring systems, fuel flow meters, and other instrumentation used to provide data for the GHGs reported under this part.

(7) Maintenance records for all continuous monitoring systems, flow meters, and other instrumentation used to provide data for the GHGs reported under this part.

(h) Annual GHG report revisions. The owner or operator shall submit a revised report within 45 days of discovering or being notified by EPA of errors in an annual GHG report. The revised report must correct all identified errors. The owner or operator shall retain documentation for 3 years to support any revisions made to an annual GHG report.

(i) Calibration accuracy requirements. The owner or operator of a facility or supplier that is subject to the requirements of this part must meet the calibration accuracy requirements of this paragraph (i).

(1) Except as provided paragraphs (i)(4) through (i)(6) of this section, flow meters and other devices (e.g., belt scales) that measure data used to calculate GHG emissions shall be calibrated prior to April 1, 2010 using the procedures specified in this paragraph and each relevant subpart of this part. All measurement devices must be calibrated according to the manufacturer's recommended procedures, an appropriate industry consensus standard, or a method specified in a relevant subpart of this part. All measurement devices shall be calibrated to an accuracy of 5 percent. For facilities and suppliers that become subject to this part after April 1, 2010, the initial calibration shall be conducted on the date that data collection is required to begin. Subsequent calibrations shall be performed at the frequency specified in each applicable subpart.

(2) For flow meters, perform all calibrations at measurement points that are representative of normal operation of the meter. Except for the orifice, nozzle, and venturi flow meters described in paragraph

(i)(3) of this section, calculate the calibration error at each measurement point using Equation A-2 of this section. The terms ``R'' and ``A'' in Equation A-2 must be expressed in consistent units of measure (e.g., gallons/minute, ft \3\/min). The calibration error at each measurement point shall not exceed 5.0 percent of the reference value.

GRAPHIC

TIFF OMITTED TR30OC09.001

Where:

CE = Calibration error (%)

R = Reference value

A = Flow meter response to the reference value

(3) For orifice, nozzle, and venturi flow meters, the initial quality assurance consists of in-situ calibration of the differential pressure (delta-P), total pressure, and temperature transmitters.

Calibrate each transmitter at a zero point and at least one upscale point. Fixed reference points, such as the freezing point of water, may be used for temperature transmitter calibrations. Calculate the calibration error of each transmitter at each measurement point, using

Equation A-3 of this subpart. The terms ``R'', ``A'', and ``FS'' in

Equation A-3 of this subpart must be in consistent units of measure

(e.g., milliamperes, inches of water, psi, degrees). For each transmitter, the CE value at each measurement point shall not exceed 2.0 percent of full-scale. Alternatively, the results are acceptable if the sum of the calculated CE values for the three transmitters at each calibration level (i.e., at the zero level and at each upscale level) does not exceed 5.0 percent.

GRAPHIC

TIFF OMITTED TR30OC09.002

Where:

CE = Calibration error (%)

R = Reference value

A = Transmitter response to the reference value

FS = Full-scale value of the transmitter

(4) Fuel billing meters are exempted from the calibration requirements of this section, provided that the fuel supplier and any unit combusting the fuel do not have any common owners and are not owned by subsidiaries or affiliates of the same company.

(5) For a flow meter or other measurement device that has been previously calibrated in accordance with this part, an initial calibration is not required by the date specified in paragraph (i)(1) of this section if, as of the date required for the initial calibration, the previous calibration is still active (i.e., the device is not yet due for recalibration because the time interval between successive calibrations, as required by this part, has not elapsed).

(6) For units and processes that operate continuously with infrequent outages, it may not be possible to meet the April 1, 2010 deadline for the initial calibration of a flow meter or other measurement device without removing the device from service and shipping it to a remote location, thereby disrupting normal process operation. In such cases, the owner or operator may postpone the initial calibration until the next scheduled maintenance outage, and may similarly postpone the subsequent recalibrations. Such postponements shall be documented in the monitoring plan that is required under Sec. 98.3(g)(5).

Sec. 98.4 Authorization and responsibilities of the designated representative.

(a) General. Except as provided under paragraph (f) of this section, each facility, and each supplier, that is subject to this part, shall have one and only one designated representative, who shall be responsible for certifying, signing, and submitting GHG emissions reports and any other submissions for such facility and supplier respectively to the Administrator under this part. If the facility is required under any other part of title 40 of the Code of Federal

Regulations to submit to the Administrator any other emission report that is subject to any requirement in 40

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CFR part 75, the same individual shall be the designated representative responsible for certifying, signing, and submitting the GHG emissions reports and all such other emissions reports under this part.

(b) Authorization of a designated representative. The designated representative of the facility or supplier shall be an individual selected by an agreement binding on the owners and operators of such facility or supplier and shall act in accordance with the certification statement in paragraph (i)(4)(iv) of this section.

(c) Responsibility of the designated representative. Upon receipt by the Administrator of a complete certificate of representation under this section for a facility or supplier, the designated representative identified in such certificate of representation shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each owner and operator of such facility or supplier in all matters pertaining to this part, notwithstanding any agreement between the designated representative and such owners and operators.

The owners and operators shall be bound by any decision or order issued to the designated representative by the Administrator or a court.

(d) Timing. No GHG emissions report or other submissions under this part for a facility or supplier will be accepted until the

Administrator has received a complete certificate of representation under this section for a designated representative of the facility or supplier. Such certificate of representation shall be submitted at least 60 days before the deadline for submission of the facility's or supplier's initial emission report under this part.

(e) Certification of the GHG emissions report. Each GHG emission report and any other submission under this part for a facility or supplier shall be certified, signed, and submitted by the designated representative or any alternate designated representative of the facility or supplier in accordance with this section and Sec. 3.10 of this chapter.

(1) Each such submission shall include the following certification statement signed by the designated representative or any alternate designated representative: ``I am authorized to make this submission on behalf of the owners and operators of the facility or supplier, as applicable, for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.''

(2) The Administrator will accept a GHG emission report or other submission for a facility or supplier under this part only if the submission is certified, signed, and submitted in accordance with this section.

(f) Alternate designated representative. A certificate of representation under this section for a facility or supplier may designate one alternate designated representative, who shall be an individual selected by an agreement binding on the owners and operators, and may act on behalf of the designated representative, of such facility or supplier. The agreement by which the alternate designated representative is selected shall include a procedure for authorizing the alternate designated representative to act in lieu of the designated representative.

(1) Upon receipt by the Administrator of a complete certificate of representation under this section for a facility or supplier identifying an alternate designated representative.

(i) The alternate designated representative may act on behalf of the designated representative for such facility or supplier.

(ii) Any representation, action, inaction, or submission by the alternate designated representative shall be deemed to be a representation, action, inaction, or submission by the designated representative.

(2) Except in this section, whenever the term ``designated representative'' is used in this part, the term shall be construed to include the designated representative or any alternate designated representative.

(g) Changing a designated representative or alternate designated representative. The designated representative or alternate designated representative identified in a complete certificate of representation under this section for a facility or supplier received by the

Administrator may be changed at any time upon receipt by the

Administrator of another later signed, complete certificate of representation under this section for the facility or supplier.

Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous designated representative or the previous alternate designated representative of the facility or supplier before the time and date when the Administrator receives such later signed certificate of representation shall be binding on the new designated representative and the owners and operators of the facility or supplier.

(h) Changes in owners and operators. In the event an owner or operator of the facility or supplier is not included in the list of owners and operators in the certificate of representation under this section for the facility or supplier, such owner or operator shall be deemed to be subject to and bound by the certificate of representation, the representations, actions, inactions, and submissions of the designated representative and any alternate designated representative of the facility or supplier, as if the owner or operator were included in such list. Within 90 days after any change in the owners and operators of the facility or supplier (including the addition of a new owner or operator), the designated representative or any alternate designated representative shall submit a certificate of representation that is complete under this section except that such list shall be amended to reflect the change. If the designated representative or alternate designated representative determines at any time that an owner or operator of the facility or supplier is not included in such list and such exclusion is not the result of a change in the owners and operators, the designated representative or any alternate designated representative shall submit, within 90 days of making such determination, a certificate of representation that is complete under this section except that such list shall be amended to include such owner or operator.

(i) Certificate of representation. A certificate of representation shall be complete if it includes the following elements in a format prescribed by the Administrator in accordance with this section:

(1) Identification of the facility or supplier for which the certificate of representation is submitted.

(2) The name, address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the designated representative and any alternate designated representative.

(3) A list of the owners and operators of the facility or supplier identified in paragraph (i)(1) of this section, provided that, if the list includes the operators of the facility or supplier and the owners with control of the facility or supplier, the failure to include any other owners shall not make the certificate of representation incomplete.

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(4) The following certification statements by the designated representative and any alternate designated representative:

(i) ``I certify that I was selected as the designated representative or alternate designated representative, as applicable, by an agreement binding on the owners and operators of the facility or supplier, as applicable.''

(ii) ``I certify that I have all the necessary authority to carry out my duties and responsibilities under 40 CFR part 98 on behalf of the owners and operators of the facility or supplier, as applicable, and that each such owner and operator shall be fully bound by my representations, actions, inactions, or submissions.''

(iii) ``I certify that the owners and operators of the facility or supplier, as applicable, shall be bound by any order issued to me by the Administrator or a court regarding the facility or supplier.''

(iv) ``If there are multiple owners and operators of the facility or supplier, as applicable, I certify that I have given a written notice of my selection as the `designated representative' or `alternate designated representative', as applicable, and of the agreement by which I was selected to each owner and operator of the facility or supplier.''

(5) The signature of the designated representative and any alternate designated representative and the dates signed.

(j) Documents of agreement. Unless otherwise required by the

Administrator, documents of agreement referred to in the certificate of representation shall not be submitted to the Administrator. The

Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.

(k) Binding nature of the certificate of representation. Once a complete certificate of representation under this section for a facility or supplier has been received, the Administrator will rely on the certificate of representation unless and until a later signed, complete certificate of representation under this section for the facility or supplier is received by the Administrator.

(l) Objections Concerning a Designated Representative

(1) Except as provided in paragraph (g) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission, of the designated representative or alternate designated representative shall affect any representation, action, inaction, or submission of the designated representative or alternate designated representative, or the finality of any decision or order by the

Administrator under this part.

(2) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any designated representative or alternate designated representative.

(m) Delegation by designated representative and alternate designated representative.

(1) A designated representative or an alternate designated representative may delegate his or her own authority, to one or more individuals, to submit an electronic submission to the Administrator provided for or required under this part, except for a submission under this paragraph.

(2) In order to delegate his or her own authority, to one or more individuals, to submit an electronic submission to the Administrator in accordance with paragraph (m)(1) of this section, the designated representative or alternate designated representative must submit electronically to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:

(i) The name, address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of such designated representative or alternate designated representative.

(ii) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such individual

(referred to as an ``agent'').

(iii) For each such individual, a list of the type or types of electronic submissions under paragraph (m)(1) of this section for which authority is delegated to him or her.

(iv) For each type of electronic submission listed in accordance with paragraph (m)(2)(iii) of this section, the facility or supplier for which the electronic submission may be made.

(v) The following certification statements by such designated representative or alternate designated representative:

(A) ``I agree that any electronic submission to the Administrator that is by an agent identified in this notice of delegation and of a type listed, and for a facility or supplier designated, for such agent in this notice of delegation and that is made when I am a designated representative or alternate designated representative, as applicable, and before this notice of delegation is superseded by another notice of delegation under Sec. 98.4(m)(3) shall be deemed to be an electronic submission certified, signed, and submitted by me.''

(B) ``Until this notice of delegation is superseded by a later signed notice of delegation under Sec. 98.4(m)(3), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under Sec. 98.4(m) is terminated.''

(vi) The signature of such designated representative or alternate designated representative and the date signed.

(3) A notice of delegation submitted in accordance with paragraph

(m)(2) of this section shall be effective, with regard to the designated representative or alternate designated representative identified in such notice, upon receipt of such notice by the

Administrator and until receipt by the Administrator of another such notice that was signed later by such designated representative or alternate designated representative, as applicable. The later signed notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.

(4) Any electronic submission covered by the certification in paragraph (m)(2)(iv)(A) of this section and made in accordance with a notice of delegation effective under paragraph (m)(3) of this section shall be deemed to be an electronic submission certified, signed, and submitted by the designated representative or alternate designated representative submitting such notice of delegation.

Sec. 98.5 How is the report submitted?

Each GHG report and certificate of representation for a facility or supplier must be submitted electronically in accordance with the requirements of Sec. 98.4 and in a format specified by the

Administrator.

Sec. 98.6 Definitions.

All terms used in this part shall have the same meaning given in the Clean Air Act and in this section.

Accuracy of a measurement at a specified level (e.g., one percent of full scale or one percent of the value measured) means that the mean of repeat measurements made by a device or technique are within 95 percent of the range bounded by the true value plus or minus the specified level.

Acid Rain Program means the program established under title IV of the Clean Air Act, and implemented under parts 72 through 78 of this chapter for the reduction of sulfur dioxide and nitrogen oxides emissions.

Administrator means the Administrator of the United States

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Environmental Protection Agency or the Administrator's authorized representative.

AGA means the American Gas Association

Alkali bypass means a duct between the feed end of the kiln and the preheater tower through which a portion of the kiln exit gas stream is withdrawn and quickly cooled by air or water to avoid excessive buildup of alkali, chloride and/or sulfur on the raw feed. This may also be referred to as the ``kiln exhaust gas bypass.''

Anaerobic digester means the system where wastes are collected and anaerobically digested in large containment vessels or covered lagoons.

Anaerobic digesters stabilize waste by the microbial reduction of complex organic compounds to CO2 and CH4, which is captured and may be flared or used as fuel. Anaerobic digestion systems, include but are not limited to covered lagoon, complete mix, plug flow, and fixed film digesters.

Anaerobic lagoon means a type of liquid storage system component, either at manure management system or a wastewater treatment system, that is designed and operated to stabilize wastes using anaerobic microbial processes. Anaerobic lagoons may be designed for combined stabilization and storage with varying lengths of retention time (up to a year or greater), depending on the climate region, the volatile solids loading rate, and other operational factors.

Anode effect is a process upset condition of an aluminum electrolysis cell caused by too little alumina dissolved in the electrolyte. The anode effect begins when the voltage rises rapidly and exceeds a threshold voltage, typically 8 volts.

Anode Effect Minutes per Cell Day (24 hours) are the total minutes during which an electrolysis cell voltage is above the threshold voltage, typically 8 volts.

ANSI means the American National Standards Institute.

API means the American Petroleum Institute.

Argon-oxygen decarburization (AOD) vessel means any closed-bottom, refractory-lined converter vessel with submerged tuyeres through which gaseous mixtures containing argon and oxygen or nitrogen may be blown into molten steel for further refining to reduce the carbon content of the steel.

ASABE means the American Society of Agricultural and Biological

Engineers.

ASME means the American Society of Mechanical Engineers.

ASTM means the American Society of Testing and Materials.

Asphalt means a dark brown-to-black cement-like material obtained by petroleum processing and containing bitumens as the predominant component. It includes crude asphalt as well as the following finished products: cements, fluxes, the asphalt content of emulsions (exclusive of water), and petroleum distillates blended with asphalt to make cutback asphalts.

Aviation Gasoline means a complex mixture of volatile hydrocarbons, with or without additives, suitably blended to be used in aviation reciprocating engines. Specifications can be found in ASTM

Specification D910-07a, Standard Specification for Aviation Gasolines

(incorporated by reference, see Sec. 98.7).

B0means the maximum CH4producing capacity of a waste stream, kg CH4/kg COD.

Basic oxygen furnace means any refractory-lined vessel in which high-purity oxygen is blown under pressure through a bath of molten iron, scrap metal, and fluxes to produce steel. bbl means barrel.

Biodiesel means a mono-akyl ester derived from biomass and conforming to ASTM D6751-08, Standard Specification for Biodiesel Fuel

Blend Stock (B100) for Middle Distillate Fuels.

Biogenic CO2means carbon dioxide emissions generated as the result of biomass combustion from combustion units for which emission calculations are required by an applicable part 98 subpart.

Biomass means non-fossilized and biodegradable organic material originating from plants, animals or micro-organisms, including products, by-products, residues and waste from agriculture, forestry and related industries as well as the non-fossilized and biodegradable organic fractions of industrial and municipal wastes, including gases and liquids recovered from the decomposition of non-fossilized and biodegradable organic material.

Blast furnace means a furnace that is located at an integrated iron and steel plant and is used for the production of molten iron from iron ore pellets and other iron bearing materials.

Blendstocks are petroleum products used for blending or compounding into finished motor gasoline. These include RBOB (reformulated blendstock for oxygenate blending) and CBOB (conventional blendstock for oxygenate blending), but exclude oxygenates, butane, and pentanes plus.

Blendstocks--Others are products used for blending or compounding into finished motor gasoline that are not defined elsewhere. Excludes

Gasoline Treated as Blendstock (GTAB), Diesel Treated as Blendstock

(DTAB), conventional blendstock for oxygenate blending (CBOB), reformulated blendstock for oxygenate blending (RBOB), oxygenates (e.g. fuel ethanol and methyl tertiary butyl ether), butane, and pentanes plus.

Blowdown mean the act of emptying or depressuring a vessel. This may also refer to the discarded material such as blowdown water from a boiler or cooling tower.

British Thermal Unit or Btu means the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit at about 39.2 degrees Fahrenheit.

Bulk, with respect to industrial GHG suppliers and CO2 suppliers, means the transfer of a product inside containers, including but not limited to tanks, cylinders, drums, and pressure vessels.

Bulk natural gas liquid or NGL refers to mixtures of hydrocarbons that have been separated from natural gas as liquids through the process of absorption, condensation, adsorption, or other methods at lease separators and field facilities. Generally, such liquids consist of ethane, propane, butanes, and pentanes plus. Bulk NGL is sold to fractionators or to refineries and petrochemical plants where the fractionation takes place.

Butane, or n-Butane, is a paraffinic straight-chain hydrocarbon with molecular formula C4H10.

Butylene, or n-Butylene, is an olefinic straight-chain hydrocarbon with molecular formula C4H8.

By-product coke oven battery means a group of ovens connected by common walls, where coal undergoes destructive distillation under positive pressure to produce coke and coke oven gas from which by- products are recovered.

Calcination means the process of thermally treating minerals to decompose carbonates from ore.

Calculation methodology means a methodology prescribed under the section ``Calculating GHG Emissions'' in any subpart of part 98.

Carbon dioxide equivalent or CO2e means the number of metric tons of CO2emissions with the same global warming potential as one metric ton of another greenhouse gas, and is calculated using Equation A-1 of this subpart.

Carbon dioxide production well means any hole drilled in the earth for the primary purpose of extracting carbon dioxide from a geologic formation or group of formations which contain deposits of carbon dioxide.

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Carbon dioxide production well facility means one or more carbon dioxide production wells that are located on one or more contiguous or adjacent properties, which are under the control of the same entity.

Carbon dioxide production wells located on different oil and gas leases, mineral fee tracts, lease tracts, subsurface or surface unit areas, surface fee tracts, surface lease tracts, or separate surface sites, whether or not connected by a road, waterway, power line, or pipeline, shall be considered part of the same CO2 production well facility if they otherwise meet the definition.

Carbon dioxide stream means carbon dioxide that has been captured from an emission source (e.g. a power plant or other industrial facility) or extracted from a carbon dioxide production well plus incidental associated substances either derived from the source materials and the capture process or extracted with the carbon dioxide.

Carbon share means the percent of total mass that carbon represents in any product.

Carbonate means compounds containing the radical

CO3-2. Upon calcination, the carbonate radical decomposes to evolve carbon dioxide (CO2). Common carbonates consumed in the mineral industry include calcium carbonate

(CaCO3) or calcite; magnesium carbonate (MgCO3) or magnesite; and calcium-magnesium carbonate

(CaMg(CO3)2) or dolomite.

Carbonate-based mineral means any of the following minerals used in the manufacture of glass: Calcium carbonate (CaCO3), calcium magnesium carbonate (CaMg(CO3)2), and sodium carbonate (Na2CO3).

Carbonate-based mineral mass fraction means the following: For limestone, the mass fraction of CaCO3in the limestone; for dolomite, the mass fraction of CaMg(CO3)2in the dolomite; and for soda ash, the mass fraction of

Na2CO3in the soda ash.

Carbonate-based raw material means any of the following materials used in the manufacture of glass: Limestone, dolomite, and soda ash.

Catalytic cracking unit means a refinery process unit in which petroleum derivatives are continuously charged and hydrocarbon molecules in the presence of a catalyst are fractured into smaller molecules, or react with a contact material suspended in a fluidized bed to improve feedstock quality for additional processing and the catalyst or contact material is continuously regenerated by burning off coke and other deposits. Catalytic cracking units include both fluidized bed systems, which are referred to as fluid catalytic cracking units (FCCU), and moving bed systems, which are also referred to as thermal catalytic cracking units. The unit includes the riser, reactor, regenerator, air blowers, spent catalyst or contact material stripper, catalyst or contact material recovery equipment, and regenerator equipment for controlling air pollutant emissions and for heat recovery.

Deep bedding systems for cattle swine means a manure management system in which, as manure accumulates, bedding is continually added to absorb moisture over a production cycle and possibly for as long as 6 to 12 months. This manure management system also is known as a bedded pack manure management system and may be combined with a dry lot or pasture.

CBOB-Summer (conventional blendstock for oxygenate blending) means a petroleum product which, when blended with a specified type and percentage of oxygenate, meets the definition of Conventional-Summer.

CBOB-Winter (conventional blendstock for oxygenate blending) means a petroleum product which, when blended with a specified type and percentage of oxygenate, meets the definition of Conventional-Winter.

Certified standards means calibration gases certified by the manufacturer of the calibration gases to be accurate to within 2 percent of the value on the label or calibration gases.

CH4means methane.

Chemical recovery combustion unit means a combustion device, such as a recovery furnace or fluidized-bed reactor where spent pulping liquor from sulfite or semi-chemical pulping processes is burned to recover pulping chemicals.

Chemical recovery furnace means an enclosed combustion device where concentrated spent liquor produced by the kraft or soda pulping process is burned to recover pulping chemicals and produce steam. Includes any recovery furnace that burns spent pulping liquor produced from both the kraft and soda pulping processes.

Chloride process means a production process where titanium dioxide is produced using calcined petroleum coke and chlorine as raw materials.

City gate means a location at which natural gas ownership or control passes from one party to another, neither of which is the ultimate consumer. In this rule, in keeping with common practice, the term refers to a point or measuring station at which a local gas distribution utility receives gas from a natural gas pipeline company or transmission system. Meters at the city gate station measure the flow of natural gas into the local distribution company system and typically are used to measure local distribution company system sendout to customers.

CO2 means carbon dioxide.

Coal means all solid fuels classified as anthracite, bituminous, sub-bituminous, or lignite by the American Society for Testing and

Materials Designation ASTM D388-05 Standard Classification of Coals by

Rank (incorporated by reference, see Sec. 98.7).

COD means the chemical oxygen demand as determined using methods specified pursuant to 40 CFR part 136.

Coke burn-off means the coke removed from the surface of a catalyst by combustion during catalyst regeneration. Coke burn-off also means the coke combusted in fluid coking unit burner.

Cokemaking means the production of coke from coal in either a by- product coke oven battery or a non-recovery coke oven battery.

Commercial applications means executing a commercial transaction subject to a contract. A commercial application includes transferring custody of a product from one facility to another if it otherwise meets the definition.

Company records means, in reference to the amount of fuel consumed by a stationary combustion unit (or by a group of such units), a complete record of the methods used, the measurements made, and the calculations performed to quantify fuel usage. Company records may include, but are not limited to, direct measurements of fuel consumption by gravimetric or volumetric means, tank drop measurements, and calculated values of fuel usage obtained by measuring auxiliary parameters such as steam generation or unit operating hours. Fuel billing records obtained from the fuel supplier qualify as company records.

Connector means to flanged, screwed, or other joined fittings used to connect pipe line segments, tubing, pipe components (such as elbows, reducers, ``T's'' or valves) or a pipe line and a piece of equipment or an instrument to a pipe, tube or piece of equipment. A common connector is a flange. Joined fittings welded completely around the circumference of the interface are not considered connectors for the purpose of this part.

Container glass means glass made of soda-lime recipe, clear or colored, which is pressed and/or blown into bottles, jars, ampoules, and other products listed in North American Industry Classification

System 327213 (NAICS 327213).

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Continuous emission monitoring system or CEMS means the total equipment required to sample, analyze, measure, and provide, by means of readings recorded at least once every 15 minutes, a permanent record of gas concentrations, pollutant emission rates, or gas volumetric flow rates from stationary sources.

Continuous glass melting furnace means a glass melting furnace that operates continuously except during periods of maintenance, malfunction, control device installation, reconstruction, or rebuilding.

Conventional-Summer refers to finished gasoline formulated for use in motor vehicles, the composition and properties of which do not meet the requirements of the reformulated gasoline regulations promulgated by the U.S. Environmental Protection Agency under 40 CFR 80.40, but which meet summer RVP standards required under 40 CFR 80.27 or as specified by the state. Note: This category excludes conventional gasoline for oxygenate blending (CBOB) as well as other blendstock.

Conventional-Winter refers to finished gasoline formulated for use in motor vehicles, the composition and properties of which do not meet the requirements of the reformulated gasoline regulations promulgated by the U.S. Environmental Protection Agency under 40 CFR 80.40 or the summer RVP standards required under 40 CFR 80.27 or as specified by the state. Note: This category excludes conventional blendstock for oxygenate blending (CBOB) as well as other blendstock.

Crude oil means a mixture of hydrocarbons that exists in the liquid phase in the underground reservoir and remains liquid at atmospheric pressure after passing through surface separating facilities.

Daily spread means a manure management system component in which manure is routinely removed from a confinement facility and is applied to cropland or pasture within 24 hours of excretion.

Day means any consistently designated 24 hour period during which an emission unit is operated.

Degradable organic carbon (DOC) means the fraction of the total mass of a waste material that can be biologically degraded.

Delayed coking unit means one or more refinery process units in which high molecular weight petroleum derivatives are thermally cracked and petroleum coke is produced in a series of closed, batch system reactors. A delayed coking unit consists of the coke drums and ancillary equipment associated with a single fractionator.

Density means the mass contained in a given unit volume (mass/ volume).

Destruction means:

(1) With respect to landfills and manure management, the combustion of methane in any on-site or off-site combustion technology. Destroyed methane includes, but is not limited to, methane combusted by flaring, methane destroyed by thermal oxidation, methane combusted for use in on-site energy or heat production technologies, methane that is conveyed through pipelines (including natural gas pipelines) for off- site combustion, and methane that is collected for any other on-site or off-site use as a fuel.

(2) With respect to fluorinated GHGs, the expiration of a fluorinated GHG to the destruction efficiency actually achieved. Such destruction does not result in a commercially useful end product.

Destruction Efficiency means the efficiency with which a destruction device reduces the GWP-weighted mass of greenhouse gases fed into the device, considering the GWP-weighted masses of both the greenhouse gases fed into the device and those exhausted from the device. Destruction efficiency, or flaring destruction efficiency, refers to the fraction of the gas that leaves the flare partially or fully oxidized. The Destruction Efficiency is expressed in Equation A-2 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.003

Where:

DE = Destruction Efficiency tCO2eIN= The GWP-weighted mass of GHGs fed into the destruction device tCO2eOUT= The GWP-weighted mass of GHGs exhausted from the destruction device, including GHGs formed during the destruction process

Diesel--Other is any distillate fuel oil not defined elsewhere, including Diesel Treated as Blendstock (DTAB).

DIPE (diisopropyl ether,

(CH3)2CHOCH(CH3)2) is an ether as described in ``Oxygenates.''

Direct liquefaction means the conversion of coal directly into liquids, rather than passing through an intermediate gaseous state.

Direct reduction furnace means a high temperature furnace typically fired with natural gas to produce solid iron from iron ore or iron ore pellets and coke, coal, or other carbonaceous materials.

Distillate Fuel Oil means a classification for one of the petroleum fractions produced in conventional distillation operations and from crackers and hydrotreating process units. The generic term distillate fuel oil includes kerosene, diesel fuels (Diesel Fuels No. 1, No. 2, and No. 4), and fuel oils (Fuel Oils No. 1, No. 2, and No. 4).

Distillate Fuel No. 1 has a maximum distillation temperature of 550

deg

F at the 90 percent recovery point and a minimum flash point of 100 [deg]F and includes fuels commonly known as Diesel Fuel No. 1 and

Fuel Oil No. 1, but excludes kerosene. This fuel is further subdivided into categories of sulfur content: High Sulfur (greater than 500 ppm),

Low Sulfur (less than or equal to 500 ppm and greater than 15 ppm), and

Ultra Low Sulfur (less than or equal to 15 ppm).

Distillate Fuel No. 2 has a minimum and maximum distillation temperature of 540 [deg]F and 640 [deg]F at the 90 percent recovery point, respectively, and includes fuels commonly known as Diesel Fuel

No. 2 and Fuel Oil No. 2. This fuel is further subdivided into categories of sulfur content: High Sulfur (greater than 500 ppm), Low

Sulfur (less than or equal to 500 ppm and greater than 15 ppm), and

Ultra Low Sulfur (less than or equal to 15 ppm).

Distillate Fuel No. 4 is a distillate fuel oil made by blending distillate fuel oil and residual fuel oil, with a minimum flash point of 131 [deg]F.

DOCfmeans the fraction of DOC that actually decomposes under the (presumably anaerobic) conditions within the landfill.

Dry lot means a manure management system component consisting of a paved or unpaved open confinement area without any significant vegetative cover where accumulating manure may be removed periodically.

Electric arc furnace (EAF) means a furnace that produces molten alloy metal and heats the charge materials with electric arcs from carbon electrodes.

Electric arc furnace steelmaking means the production of carbon, alloy, or specialty steels using an EAF. This definition excludes EAFs at steel foundries and EAFs used to produce nonferrous metals.

Electrothermic furnace means a furnace that heats the charged materials with electric arcs from carbon electrodes.

Emergency generator means a stationary combustion device, such as a reciprocating internal combustion engine or turbine that serves solely as a secondary source of mechanical or electrical power whenever the primary energy supply is disrupted or discontinued during power outages or natural disasters that are beyond the control of the owner or operator of a

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facility. An emergency generator operates only during emergency situations, for training of personnel under simulated emergency conditions, as part of emergency demand response procedures, or for standard performance testing procedures as required by law or by the generator manufacturer. A generator that serves as a back-up power source under conditions of load shedding, peak shaving, power interruptions pursuant to an interruptible power service agreement, or scheduled facility maintenance shall not be considered an emergency generator.

Emergency equipment means any auxiliary fossil fuel-powered equipment, such as a fire pump, that is used only in emergency situations.

ETBE (ethyl tertiary butyl ether,

(CH3)3COC2H) is an ether as described in ``Oxygenates.''

Ethane is a paraffinic hydrocarbon with molecular formula

C2H6.

Ethanol is an anhydrous alcohol with molecular formula

C2H5OH.

Ethylene is an olefinic hydrocarbon with molecular formula

C2H4.

Ex refinery gate means the point at which a petroleum product leaves the refinery.

Experimental furnace means a glass melting furnace with the sole purpose of operating to evaluate glass melting processes, technologies, or glass products. An experimental furnace does not produce glass that is sold (except for further research and development purposes) or that is used as a raw material for non-experimental furnaces.

Export means to transport a product from inside the United States to persons outside the United States, excluding any such transport on behalf of the United States military including foreign military sales under the Arms Export Control Act.

Exporter means any person, company or organization of record that transfers for sale or for other benefit, domestic products from the

United States to another country or to an affiliate in another country, excluding any such transfers on behalf of the United States military or military purposes including foreign military sales under the Arms

Export Control Act. An exporter is not the entity merely transporting the domestic products, rather an exporter is the entity deriving the principal benefit from the transaction.

Facility means any physical property, plant, building, structure, source, or stationary equipment located on one or more contiguous or adjacent properties in actual physical contact or separated solely by a public roadway or other public right-of-way and under common ownership or common control, that emits or may emit any greenhouse gas. Operators of military installations may classify such installations as more than a single facility based on distinct and independent functional groupings within contiguous military properties.

Feed means the prepared and mixed materials, which include but are not limited to materials such as limestone, clay, shale, sand, iron ore, mill scale, cement kiln dust and flyash, that are fed to the kiln.

Feed does not include the fuels used in the kiln to produce heat to form the clinker product.

Feedstock means raw material inputs to a process that are transformed by reaction, oxidation, or other chemical or physical methods into products and by-products. Supplemental fuel burned to provide heat or thermal energy is not a feedstock.

Fischer-Tropsch process means a catalyzed chemical reaction in which synthesis gas, a mixture of carbon monoxide and hydrogen, is converted into liquid hydrocarbons of various forms.

Flare means a combustion device, whether at ground level or elevated, that uses an open flame to burn combustible gases with combustion air provided by uncontrolled ambient air around the flame.

Flat glass means glass made of soda-lime recipe and produced into continuous flat sheets and other products listed in NAICS 327211.

Flowmeter means a device that measures the mass or volumetric rate of flow of a gas, liquid, or solid moving through an open or closed conduit (e.g. flowmeters include, but are not limited to, rotameters, turbine meters, coriolis meters, orifice meters, ultra-sonic flowmeters, and vortex flowmeters).

Fluid coking unit means one or more refinery process units in which high molecular weight petroleum derivatives are thermally cracked and petroleum coke is continuously produced in a fluidized bed system. The fluid coking unit includes equipment for controlling air pollutant emissions and for heat recovery on the fluid coking burner exhaust vent. There are two basic types of fluid coking units: A traditional fluid coking unit in which only a small portion of the coke produced in the unit is burned to fuel the unit and the fluid coking burner exhaust vent is directed to the atmosphere (after processing in a CO boiler or other air pollutant control equipment) and a flexicoking unit in which an auxiliary burner is used to partially combust a significant portion of the produced petroleum coke to generate a low value fuel gas that is used as fuel in other combustion sources at the refinery.

Fluorinated greenhouse gas means sulfur hexafluoride

(SF6), nitrogen trifluoride (NF3), and any fluorocarbon except for controlled substances as defined at 40 CFR part 82, subpart A and substances with vapor pressures of less than 1 mm of

Hg absolute at 25 degrees C. With these exceptions, ``fluorinated GHG'' includes but is not limited to any hydrofluorocarbon, any perfluorocarbon, any fully fluorinated linear, branched or cyclic alkane, ether, tertiary amine or aminoether, any perfluoropolyether, and any hydrofluoropolyether.

Fossil fuel means natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material, including for example, consumer products that are derived from such materials and are combusted.

Fossil fuel-fired means powered by combustion of fossil fuel, alone or in combination with any other fuel, regardless of the percentage of fossil fuel consumed.

Fractionators means plants that produce fractionated natural gas liquids (NGLs) extracted from produced natural gas and separate the

NGLs individual component products: ethane, propane, butanes and pentane-plus (C5+). Plants that only process natural gas but do not fractionate NGLs further into component products are not considered fractionators. Some fractionators do not process production gas, but instead fractionate bulk NGLs received from natural gas processors.

Some fractionators both process natural gas and fractionate bulk NGLs received from other plants.

Fuel means solid, liquid or gaseous combustible material.

Fuel gas means gas generated at a petroleum refinery, petrochemical plant, or similar industrial process unit, and that is combusted separately or in any combination with any type of gas.

Fuel gas system means a system of compressors, piping, knock-out pots, mix drums, and, if necessary, units used to remove sulfur contaminants from the fuel gas (e.g., amine scrubbers) that collects fuel gas from one or more sources for treatment, as necessary, and transport to a stationary combustion unit. A fuel gas system may have an overpressure vent to a flare but the primary purpose for a fuel gas system is to provide fuel to the various combustion units at the refinery or petrochemical plant.

Gas collection system or landfill gas collection system means a system of pipes used to collect landfill gas from different locations in the landfill to a

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single location for treatment (thermal destruction) or use. Landfill gas collection systems may also include knock-out or separator drums and/or a compressor.

Gas-fired unit means a stationary combustion unit that derives more than 50 percent of its annual heat input from the combustion of gaseous fuels, and the remainder of its annual heat input from the combustion of fuel oil or other liquid fuels.

Gas monitor means an instrument that continuously measures the concentration of a particular gaseous species in the effluent of a stationary source.

Gaseous fuel means a material that is in the gaseous state at standard atmospheric temperature and pressure conditions and that is combusted to produce heat and/or energy.

Gasification means the conversion of a solid or liquid raw material into a gas.

Gasoline--Other is any gasoline that is not defined elsewhere, including GTAB (gasoline treated as blendstock).

Glass melting furnace means a unit comprising a refractory-lined vessel in which raw materials are charged and melted at high temperature to produce molten glass.

Glass produced means the weight of glass exiting a glass melting furnace.

Global warming potential or GWP means the ratio of the time- integrated radiative forcing from the instantaneous release of one kilogram of a trace substance relative to that of one kilogram- of a reference gas, i.e., CO2.

GPA means the Gas Processors Association.

Greenhouse gas or GHG means carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O), sulfur hexafluoride (SF6), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and other fluorinated greenhouse gases as defined in this section.

GTBA (gasoline-grade tertiary butyl alcohol,

(CH3)3COH), or t-butanol, is an alcohol as described in ``Oxygenates.''

Heavy Gas Oils are petroleum distillates with an approximate boiling range from 651 [deg]F to 1,000 [deg]F.

Heel means the amount of gas that remains in a shipping container after it is discharged or off-loaded (that is no more than ten percent of the volume of the container).

High heat value or HHV means the high or gross heat content of the fuel with the heat of vaporization included. The water is assumed to be in a liquid state.

Hydrofluorocarbons or HFCs means a class of GHGs consisting of hydrogen, fluorine, and carbon.

Import means, to land on, bring into, or introduce into, any place subject to the jurisdiction of the United States whether or not such landing, bringing, or introduction constitutes an importation within the meaning of the customs laws of the United States, with the following exemptions:

(1) Off-loading used or excess fluorinated GHGs or nitrous oxide of

U.S. origin from a ship during servicing.

(2) Bringing fluorinated GHGs or nitrous oxide into the U.S. from

Mexico where the fluorinated GHGs or nitrous oxide had been admitted into Mexico in bond and were of U.S. origin.

(3) Bringing fluorinated GHGs or nitrous oxide into the U.S. when transported in a consignment of personal or household effects or in a similar non-commercial situation normally exempted from U.S. Customs attention.

(4) Bringing fluorinated GHGs or nitrous into U.S. jurisdiction exclusively for U. S. military purposes.

Importer means any person, company, or organization of record that for any reason brings a product into the United States from a foreign country, excluding introduction into U.S. jurisdiction exclusively for

United States military purposes. An importer is the person, company, or organization primarily liable for the payment of any duties on the merchandise or an authorized agent acting on their behalf. The term includes, as appropriate:

(1) The consignee.

(2) The importer of record.

(3) The actual owner.

(4) The transferee, if the right to draw merchandise in a bonded warehouse has been transferred.

Indurating furnace means a furnace where unfired taconite pellets, called green balls, are hardened at high temperatures to produce fired pellets for use in a blast furnace. Types of indurating furnaces include straight gate and grate kiln furnaces.

Industrial greenhouse gases means nitrous oxide or any fluorinated greenhouse gas.

In-line kiln/raw mill means a system in a portland cement production process where a dry kiln system is integrated with the raw mill so that all or a portion of the kiln exhaust gases are used to perform the drying operation of the raw mill, with no auxiliary heat source used. In this system the kiln is capable of operating without the raw mill operating, but the raw mill cannot operate without the kiln gases, and consequently, the raw mill does not generate a separate exhaust gas stream.

Isobutane is a paraffinic branch chain hydrocarbon with molecular formula C4H10.

Isobutylene is an olefinic branch chain hydrocarbon with molecular formula C4H8.

Kerosene is a light petroleum distillate with a maximum distillation temperature of 400 [deg]F at the 10-percent recovery point, a final maximum boiling point of 572 [deg]F, a minimum flash point of 100 [deg]F, and a maximum freezing point of -22 [deg]F.

Included are No. 1-K and No. 2-K, distinguished by maximum sulfur content (0.04 and 0.30 percent of total mass, respectively), as well as all other grades of kerosene called range or stove oil. Excluded is kerosene-type jet fuel (see definition herein).

Kerosene-type jet fuel means a kerosene-based product used in commercial and military turbojet and turboprop aircraft. The product has a maximum distillation temperature of 400 [deg]F at the 10 percent recovery point and a final maximum boiling point of 572 [deg]F.

Included are Jet A, Jet A-1, JP-5, and JP-8.

Kiln means an oven, furnace, or heated enclosure used for thermally processing a mineral or mineral-based substance.

Landfill means an area of land or an excavation in which wastes are placed for permanent disposal and that is not a land application unit, surface impoundment, injection well, or waste pile as those terms are defined under 40 CFR 257.2.

Landfill gas means gas produced as a result of anaerobic decomposition of waste materials in the landfill. Landfill gas generally contains 40 to 60 percent methane on a dry basis, typically less than 1 percent non-methane organic chemicals, and the remainder being carbon dioxide.

Lime is the generic term for a variety of chemical compounds that are produced by the calcination of limestone or dolomite. These products include but are not limited to calcium oxide, high-calcium quicklime, calcium hydroxide, hydrated lime, dolomitic quicklime, and dolomitic hydrate.

Liquid/Slurry means a manure management component in which manure is stored as excreted or with some minimal addition of water to facilitate handling and is stored in either tanks or earthen ponds, usually for periods less than one year.

Lubricants include all grades of lubricating oils, from spindle oil to cylinder oil to those used in greases. Petroleum lubricants may be produced from distillates or residues.

Makeup chemicals means carbonate chemicals (e.g., sodium and calcium carbonates) that are added to the chemical recovery areas of chemical

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pulp mills to replace chemicals lost in the process.

Manure composting means the biological oxidation of a solid waste including manure usually with bedding or another organic carbon source typically at thermophilic temperatures produced by microbial heat production. There are four types of composting employed for manure management: Static, in vessel, intensive windrow and passive windrow.

Static composting typically occurs in an enclosed channel, with forced aeration and continuous mixing. In vessel composting occurs in piles with forced aeration but no mixing. Intensive windrow composting occurs in windrows with regular turning for mixing and aeration. Passive windrow composting occurs in windrows with infrequent turning for mixing and aeration.

Maximum rated heat input capacity means the hourly heat input to a unit (in mmBtu/hr), when it combusts the maximum amount of fuel per hour that it is capable of combusting on a steady state basis, as of the initial installation of the unit, as specified by the manufacturer.

Maximum rated input capacity means the maximum charging rate of a municipal waste combustor unit expressed in tons per day of municipal solid waste combusted, calculated according to the procedures under 40

CFR 60.58b(j).

Mcf means thousand cubic feet.

Methane conversion factor means the extent to which the

CH4producing capacity (Bo) is realized in each type of treatment and discharge pathway and system. Thus, it is an indication of the degree to which the system is anaerobic.

Methane correction factor means an adjustment factor applied to the methane generation rate to account for portions of the landfill that remain aerobic. The methane correction factor can be considered the fraction of the total landfill waste volume that is ultimately disposed of in an anaerobic state. Managed landfills that have soil or other cover materials have a methane correction factor of 1.

Methanol (CH3OH) is an alcohol as described in

``Oxygenates.''

Midgrade gasoline has an octane rating greater than or equal to 88 and less than or equal to 90. This definition applies to the midgrade categories of Conventional-Summer, Conventional-Winter, Reformulated-

Summer, and Reformulated-Winter. For midgrade categories of RBOB-

Summer, RBOB-Winter, CBOB-Summer, and CBOB-Winter, this definition refers to the expected octane rating of the finished gasoline after oxygenate has been added to the RBOB or CBOB.

Miscellaneous products include all refined petroleum products not defined elsewhere. It includes, but is not limited to, naphtha-type jet fuel (Jet B and JP-4), petrolatum lube refining by-products (aromatic extracts and tars), absorption oils, ram-jet fuel, petroleum rocket fuels, synthetic natural gas feedstocks, waste feedstocks, and specialty oils. It excludes organic waste sludges, tank bottoms, spent catalysts, and sulfuric acid.

MMBtu means million British thermal units.

Motor gasoline (finished) means a complex mixture of volatile hydrocarbons, with or without additives, suitably blended to be used in spark ignition engines. Motor gasoline includes conventional gasoline, reformulated gasoline, and all types of oxygenated gasoline. Gasoline also has seasonal variations in an effort to control ozone levels. This is achieved by lowering the Reid Vapor Pressure (RVP) of gasoline during the summer driving season. Depending on the region of the country the RVP is lowered to below 9.0 psi or 7.8 psi. The RVP may be further lowered by state regulations.

Mscf means million standard cubic feet.

MTBE (methyl tertiary butyl ether,

(CH3)3COCH3) is an ether as described in ``Oxygenates.''

Municipal solid waste landfill or MSW landfill means an entire disposal facility in a contiguous geographical space where household waste is placed in or on land. An MSW landfill may also receive other types of RCRA Subtitle D wastes (40 CFR 257.2) such as commercial solid waste, nonhazardous sludge, conditionally exempt small quantity generator waste, and industrial solid waste. Portions of an MSW landfill may be separated by access roads, public roadways, or other public right-of-ways. An MSW landfill may be publicly or privately owned.

Municipal solid waste or MSW means solid phase household, commercial/retail, and/or institutional waste, such as, but not limited to, yard waste and refuse.

N2O means nitrous oxide.

Naphthas (401 [deg]F) are oils with a boiling range equal to or greater than 401 [deg]F that are generally intended for use as a petrochemical feedstock and are not defined elsewhere.

Owner means any person who has legal or equitable title to, has a leasehold interest in, or control of a facility or supplier, except a person whose legal or equitable title to or leasehold interest in the facility or supplier arises solely because the person is a limited partner in a partnership that has legal or equitable title to, has a leasehold interest in, or control of the facility or supplier shall not be considered an ``owner'' of the facility or supplier.

Oxygenates means substances which, when added to gasoline, increase the oxygen content of the gasoline. Common oxygenates are ethanol, methyl tertiary butyl ether (MTBE), ethyl tertiary butyl ether (ETBE), tertiary amyl methyl ether (TAME), diisopropyl ether (DIPE), and methanol.

Pasture/Range/Paddock means the manure from pasture and range grazing animals is allowed to lie as deposited, and is not managed.

Pentanes plus, or C5+, is a mixture of hydrocarbons that is a liquid at ambient temperature and pressure, and consists mostly of pentanes (five carbon chain) and higher carbon number hydrocarbons.

Pentanes plus includes, but is not limited to, normal pentane, isopentane, hexanes-plus (natural gasoline), and plant condensate.

Perfluorocarbons or PFCs means a class of greenhouse gases consisting on the molecular level of carbon and fluorine.

Petrochemical means methanol, acrylonitrile, ethylene, ethylene oxide, ethylene dichloride, and any form of carbon black.

Petrochemical feedstocks means feedstocks derived from petroleum for the manufacture of chemicals, synthetic rubber, and a variety of plastics. This category is usually divided into naphthas less than 401

deg

F and other oils greater than 401 [deg]F.

Petroleum means oil removed from the earth and the oil derived from tar sands and shale.

Petroleum coke means a black solid residue, obtained mainly by cracking and carbonizing of petroleum derived feedstocks, vacuum bottoms, tar and pitches in processes such as delayed coking or fluid coking. It consists mainly of carbon (90 to 95 percent), has low ash content, and may be used as a feedstock in coke ovens. This product is also known as marketable coke or catalyst coke.

Petroleum product means all refined and semi-refined products that are produced at a refinery by processing crude oil and other petroleum- based feedstocks, including petroleum products derived from co- processing biomass and petroleum feedstock together, but not including plastics or plastic products. Petroleum products may be combusted for energy use, or they may be used either for non-energy processes or as non-energy products. The definition of petroleum product for importers and exporters excludes waxes.

Pit storage below animal confinement (deep pits) means the collection and storage of manure typically below a slatted floor in an enclosed animal confinement facility. This usually occurs with little or no added water for periods less than one year.

Portable means designed and capable of being carried or moved from one location to another. Indications of portability include but are not limited to wheels, skids, carrying handles, dolly, trailer, or platform. Equipment is not portable if any one of the following conditions exists:

(1) The equipment is attached to a foundation.

(2) The equipment or a replacement resides at the same location for more than 12 consecutive months.

(3) The equipment is located at a seasonal facility and operates during the full annual operating period of the seasonal facility, remains at the facility for at least two years, and operates at that facility for at least three months each year.

(4) The equipment is moved from one location to another in an attempt to circumvent the portable residence time requirements of this definition.

Poultry manure with litter means a manure management system component that is similar to cattle and swine deep bedding except usually not combined with a dry lot or pasture. The system is typically used for poultry breeder flocks and for the production of meat type chickens (broiler) and other fowl.

Poultry manure without litter means a manure management system component that may manage manure in a liquid form, similar to open pits in enclosed animal confinement facilities. These systems may alternatively be designed and operated to dry manure as it accumulates.

The latter is known as a high-rise manure management system and is a form of passive windrow manure composting when designed and operated properly.

Precision of a measurement at a specified level (e.g., one percent of full scale or one percent of the value measured) means that 95 percent of repeat measurements made by a device or technique are within the range bounded by the mean of the measurements plus or minus the specified level.

Premium grade gasoline is gasoline having an antiknock index, i.e., octane rating, greater than 90. This definition applies to the premium grade categories of Conventional-Summer, Conventional-Winter,

Reformulated-Summer, and Reformulated-Winter. For premium grade categories of RBOB-Summer, RBOB-Winter, CBOB-Summer, and CBOB-Winter, this definition refers to the expected octane rating of the finished gasoline after oxygenate has been added to the RBOB or CBOB.

Pressed and blown glass means glass which is pressed, blown, or both, into products such as light bulbs, glass fiber, technical glass, and other products listed in NAICS 327212.

Pressure relief device or pressure relief valve or pressure safety valve means a safety device used to prevent operating pressures from exceeding the maximum allowable working pressure of the process equipment. A common pressure relief device is but not limited to a spring-loaded pressure relief valve. Devices that are actuated either by a pressure of less than or equal to 2.5 psig or by a vacuum are not pressure relief devices.

Process emissions means the emissions from industrial processes

(e.g., cement production, ammonia production) involving chemical or physical transformations other than fuel combustion. For example, the calcination of carbonates in a kiln during cement production or the oxidation of methane in an ammonia process results in the release of process CO2emissions to the atmosphere. Emissions from fuel combustion to provide process heat are not part of process emissions, whether the combustion is internal or external to the process equipment.

Process unit means the equipment assembled and connected by pipes and ducts to process raw materials and to manufacture either a final product or an intermediate used in the onsite production of other products. The process unit also includes the purification of recovered byproducts.

Process vent means means a gas stream that: Is discharged through a conveyance to the atmosphere either directly or after passing through a

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control device; originates from a unit operation, including but not limited to reactors (including reformers, crackers, and furnaces, and separation equipment for products and recovered byproducts); and contains or has the potential to contain GHG that is generated in the process. Process vent does not include safety device discharges, equipment leaks, gas streams routed to a fuel gas system or to a flare, discharges from storage tanks.

Propane is a paraffinic hydrocarbon with molecular formula

C3H8.

Propylene is an olefinic hydrocarbon with molecular formula

C3H6.

Pulp mill lime kiln means the combustion units (e.g., rotary lime kiln or fluidized bed calciner) used at a kraft or soda pulp mill to calcine lime mud, which consists primarily of calcium carbonate, into quicklime, which is calcium oxide.

Pushing means the process of removing the coke from the coke oven at the end of the coking cycle. Pushing begins when coke first begins to fall from the oven into the quench car and ends when the quench car enters the quench tower.

Raw mill means a ball and tube mill, vertical roller mill or other size reduction equipment, that is not part of an in-line kiln/raw mill, used to grind feed to the appropriate size. Moisture may be added or removed from the feed during the grinding operation. If the raw mill is used to remove moisture from feed materials, it is also, by definition, a raw material dryer. The raw mill also includes the air separator associated with the raw mill.

RBOB-Summer (reformulated blendstock for oxygenate blending) means a petroleum product which, when blended with a specified type and percentage of oxygenate, meets the definition of Reformulated-Summer.

RBOB-Winter (reformulated blendstock for oxygenate blending) means a petroleum product which, when blended with a specified type and percentage of oxygenate, meets the definition of Reformulated-Winter.

Reformulated-Summer refers to finished gasoline formulated for use in motor vehicles, the composition and properties of which meet the requirements of the reformulated gasoline regulations promulgated by the U.S. Environmental Protection Agency under 40 CFR 80.40 and 40 CFR 80.41, and summer RVP standards required under 40 CFR 80.27 or as specified by the state. Reformulated gasoline excludes Reformulated

Blendstock for Oxygenate Blending (RBOB) as well as other blendstock.

Reformulated-Winter refers to finished gasoline formulated for use in motor vehicles, the composition and properties of which meet the requirements of the reformulated gasoline regulations promulgated by the U.S. Environmental Protection Agency under 40 CFR 80.40 and 40 CFR 80.41, but which do not meet summer RVP standards required under 40 CFR 80.27 or as specified by the state. Note: This category includes

Oxygenated Fuels Program Reformulated Gasoline (OPRG). Reformulated gasoline excludes Reformulated Blendstock for Oxygenate Blending (RBOB) as well as other blendstock.

Regular grade gasoline is gasoline having an antiknock index, i.e., octane rating, greater than or equal to 85 and less than 88. This definition applies to the regular grade categories of Conventional-

Summer, Conventional-Winter, Reformulated-Summer, and Reformulated-

Winter. For regular grade categories of RBOB-Summer, RBOB-Winter, CBOB-

Summer, and CBOB-Winter, this definition refers to the expected octane rating of the finished gasoline after oxygenate has been added to the

RBOB or CBOB.

Rendered animal fat, or tallow, means fats extracted from animals which are generally used as a feedstock in making biodiesel.

Research and development means those activities conducted in process units or at laboratory bench-scale settings whose purpose is to conduct research and development for new processes, technologies, or products and whose purpose is not for the manufacture of products for commercial sale, except in a de minimis manner.

Residual Fuel Oil No. 5 (Navy Special) is a classification for the heavier fuel oil generally used in steam powered vessels in government service and inshore power plants. It has a minimum flash point of 131

deg

Residual Fuel Oil No. 6 (a.k.a. Bunker C) is a classification for the heavier fuel oil generally used for the production of electric power, space heating, vessel bunkering and various industrial purposes.

It has a minimum flash point of 140 [deg]F.

Residuum is residue from crude oil after distilling off all but the heaviest components, with a boiling range greater than 1,000 [deg]F.

Road oil is any heavy petroleum oil, including residual asphaltic oil used as a dust palliative and surface treatment on roads and highways. It is generally produced in six grades, from 0, the most liquid, to 5, the most viscous.

Rotary lime kiln means a unit with an inclined rotating drum that is used to produce a lime product from limestone by calcination.

Safety device means a closure device such as a pressure relief valve, frangible disc, fusible plug, or any other type of device which functions exclusively to prevent physical damage or permanent deformation to a unit or its air emission control equipment by venting gases or vapors directly to the atmosphere during unsafe conditions resulting from an unplanned, accidental, or emergency event. A safety device is not used for routine venting of gases or vapors from the vapor headspace underneath a cover such as during filling of the unit or to adjust the pressure in response to normal daily diurnal ambient temperature fluctuations. A safety device is designed to remain in a closed position during normal operations and open only when the internal pressure, or another relevant parameter, exceeds the device threshold setting applicable to the air emission control equipment as determined by the owner or operator based on manufacturer recommendations, applicable regulations, fire protection and prevention codes and practices, or other requirements for the safe handling of flammable, combustible, explosive, reactive, or hazardous materials.

Semi-refined petroleum product means all oils requiring further processing. Included in this category are unfinished oils which are produced by the partial refining of crude oil and include the following: Naphthas and lighter oils; kerosene and light gas oils; heavy gas oils; and residuum, and all products that require further processing or the addition of blendstocks.

Sendout means, in the context of a local distribution company, the total deliveries of natural gas to customers over a specified time interval (typically hour, day, month, or year). Sendout is the sum of gas received through the city gate, gas withdrawn from on-system storage or peak shaving plants, and gas produced and delivered into the distribution system; and is net of any natural gas injected into on- system storage. It comprises gas sales, exchange, deliveries, gas used by company, and unaccounted for gas. Sendout is measured at the city gate station, and other on-system receipt points from storage, peak shaving, and production.

Sensor means a device that measures a physical quantity/quality or the change in a physical quantity/quality, such as temperature, pressure, flow rate, pH, or liquid level.

SF6 means sulfur hexafluoride.

Page 56392

Shutdown means the cessation of operation of an emission source for any purpose.

Silicon carbide means an artificial abrasive produced from silica sand or quartz and petroleum coke.

Sinter process means a process that produces a fused aggregate of fine iron-bearing materials suited for use in a blast furnace. The sinter machine is composed of a continuous traveling grate that conveys a bed of ore fines and other finely divided iron-bearing material and fuel (typically coke breeze), a burner at the feed end of the grate for ignition, and a series of downdraft windboxes along the length of the strand to support downdraft combustion and heat sufficient to produce a fused sinter product.

Site means any combination of one or more graded pad sites, gravel pad sites, foundations, platforms, or the immediate physical location upon which equipment is physically located.

Smelting furnace means a furnace in which lead-bearing materials, carbon-containing reducing agents, and fluxes are melted together to form a molten mass of material containing lead and slag.

Solid storage is the storage of manure, typically for a period of several months, in unconfined piles or stacks. Manure is able to be stacked due to the presence of a sufficient amount of bedding material or loss of moisture by evaporation.

Sour gas means any gas that contains significant concentrations of hydrogen sulfide. Sour gas may include untreated fuel gas, amine stripper off-gas, or sour water stripper gas.

Special naphthas means all finished products with the naphtha boiling range (290 [deg] to 470 [deg]F) that are generally used as paint thinners, cleaners or solvents. These products are refined to a specified flash point. Special naphthas include all commercial hexane and cleaning solvents conforming to ASTM Specification D1836-07,

Standard Specification for Commercial Hexanes, and D235-02 (Reapproved 2007), Standard Specification for Mineral Spirits (Petroleum Spirits)

(Hydrocarbon Dry Cleaning Solvent), respectively. Naphthas to be blended or marketed as motor gasoline or aviation gasoline, or that are to be used as petrochemical and synthetic natural gas (SNG) feedstocks are excluded.

Spent liquor solids means the dry weight of the solids in the spent pulping liquor that enters the chemical recovery furnace or chemical recovery combustion unit.

Spent pulping liquor means the residual liquid collected from on- site pulping operations at chemical pulp facilities that is subsequently fired in chemical recovery furnaces at kraft and soda pulp facilities or chemical recovery combustion units at sulfite or semi- chemical pulp facilities.

Standard conditions or standard temperature and pressure (STP) means 68 degrees Fahrenheit and 14.7 pounds per square inch absolute.

Steam reforming means a catalytic process that involves a reaction between natural gas or other light hydrocarbons and steam. The result is a mixture of hydrogen, carbon monoxide, carbon dioxide, and water.

Still gas means any form or mixture of gases produced in refineries by distillation, cracking, reforming, and other processes. The principal constituents are methane, ethane, ethylene, normal butane, butylene, propane, and propylene.

Storage tank means a vessel (excluding sumps) that is designed to contain an accumulation of crude oil, condensate, intermediate hydrocarbon liquids, or produced water and that is constructed entirely of non-earthen materials (e.g., wood, concrete, steel, plastic) that provide structural support.

Sulfur recovery plant means all process units which recover sulfur or produce sulfuric acid from hydrogen sulfide (H2S) and/or sulfur dioxide (SO2) from a common source of sour gas at a petroleum refinery. The sulfur recovery plant also includes sulfur pits used to store the recovered sulfur product, but it does not include secondary sulfur storage vessels or loading facilities downstream of the sulfur pits. For example, a Claus sulfur recovery plant includes:

Reactor furnace and waste heat boiler, catalytic reactors, sulfur pits, and, if present, oxidation or reduction control systems, or incinerator, thermal oxidizer, or similar combustion device. Multiple sulfur recovery units are a single sulfur recovery plant only when the units share the same source of sour gas. Sulfur recovery units that receive source gas from completely segregated sour gas treatment systems are separate sulfur recovery plants.

Supplemental fuel means a fuel burned within a petrochemical process that is not produced within the process itself.

Supplier means a producer, importer, or exporter of a fossil fuel or an industrial greenhouse gas.

Taconite iron ore processing means an industrial process that separates and concentrates iron ore from taconite, a low grade iron ore, and heats the taconite in an indurating furnace to produce taconite pellets that are used as the primary feed material for the production of iron in blast furnaces at integrated iron and steel plants.

TAME means tertiary amyl methyl ether,

(CH3)2(C2H5)COCH3

Trace concentrations means concentrations of less than 0.1 percent by mass of the process stream.

Transform means to use and entirely consume (except for trace concentrations) nitrous oxide or fluorinated GHGs in the manufacturing of other chemicals for commercial purposes. Transformation does not include burning of nitrous oxide.

Transshipment means the continuous shipment of nitrous oxide or a fluorinated GHG from a foreign state of origin through the United

States or its territories to a second foreign state of final destination, as long as the shipment does not enter into United States jurisdiction. A transshipment, as it moves through the United States or its territories, cannot be re-packaged, sorted or otherwise changed in condition.

Trona means the raw material (mineral) used to manufacture soda ash; hydrated sodium bicarbonate carbonate (e.g.,

Na2CO3.NaHCO3.2H2O).

Ultimate analysis means the determination of the percentages of carbon, hydrogen, nitrogen, sulfur, and chlorine and (by difference) oxygen in the gaseous products and ash after the complete combustion of a sample of an organic material.

Unfinished oils are all oils requiring further processing, except those requiring only mechanical blending.

United States means the 50 states, the District of Columbia, and

U.S. possessions and territories.

Unstabilized crude oil means, for the purposes of this part, crude oil that is pumped from the well to a pipeline or pressurized storage vessel for transport to the refinery without intermediate storage in a storage tank at atmospheric pressures. Unstabilized crude oil is characterized by having a true vapor pressure of 5 pounds per square inch absolute (psia) or greater.

Valve means any device for halting or regulating the flow of a liquid or gas through a passage, pipeline, inlet, outlet, or orifice; including, but not limited to, gate, globe, plug, ball, butterfly and needle valves.

Vegetable oil means oils extracted from vegetation that are generally used as a feedstock in making biodiesel.

Volatile solids are the organic material in livestock manure and consist of both biodegradable and non-biodegradable fractions.

Waelz kiln means an inclined rotary kiln in which zinc-containing materials are charged together with a carbon

Page 56393

reducing agent (e.g., petroleum coke, metallurgical coke, or anthracite coal).

Waxes means a solid or semi-solid material at 77 [deg]F consisting of a mixture of hydrocarbons obtained or derived from petroleum fractions, or through a Fischer-Tropsch type process, in which the straight chained paraffin series predominates. This includes all marketable wax, whether crude or refined, with a congealing point between 80 (or 85) and 240 [deg]F and a maximum oil content of 50 weight percent.

Wool fiberglass means fibrous glass of random texture, including fiberglass insulation, and other products listed in NAICS 327993.

You means an owner or operator subject to Part 98.

Zinc smelters means a facility engaged in the production of zinc metal, zinc oxide, or zinc alloy products from zinc sulfide ore concentrates, zinc calcine, or zinc-bearing scrap and recycled materials through the use of pyrometallurgical techniques involving the reduction and volatization of zinc-bearing feed materials charged to a furnace.

Sec. 98.7 What standardized methods are incorporated by reference into this part?

The materials listed in this section are incorporated by reference in the corresponding sections noted. These incorporations by reference were approved by the Director of Federal Register in accordance with 5

U.S.C. 552(a) and 1 CFR part 51. These materials are incorporated as they exist on the date of approval, and a notice of any change in the materials will be published in the Federal Register. The materials are available for purchase at the corresponding address in this section.

The materials are available for inspection at the EPA Docket Center,

Public Reading Room, EPA West Building, Room 3334, 1301 Constitution

Avenue, NW., Washington, DC, phone (202) 566-1744 and at the National

Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202-741-6030, or go to: http://www.archives.gov/federal_register/code_of_federal_ regulations/ibr_locations.html.

(a) The following material is available for purchase from the

Association of Fertilizer and Phosphate Chemists (AFPC), P.O. Box 1645,

Bartow, Florida 33831, http://afpc.net.

(1) Phosphate Mining States Methods Used and Adopted by the

Association of Fertilizer and Phosphate Chemists AFPC Manual 10th

Edition 2009--Version 1.9, incorporation by reference (IBR) approved for Sec. 98.264(a) and Sec. 98.264(b).

(2) [Reserved]

(b) The following material is available for purchase from the

American Gas Association (AGA), 400 North Capitol Street, NW., 4th

Floor, Washington, DC 20001, (202) 824-7000, http://www.aga.org.

(1) AGA Report No. 3 Orifice Metering of Natural Gas and Other

Related Hydrocarbon Fluids Part 1: General Equations & Uncertainty

Guidelines (1990), incorporation by reference (IBR) approved for Sec. 98.34(b) and Sec. 98.244(b).

(2) AGA Report No. 3 Orifice Metering of Natural Gas and Other

Related Hydrocarbon Fluids Part 2: Specification and Installation

Requirements (2000), IBR approved for Sec. 98.34(b) and Sec. 98.244(b).

(3) AGA Report No. 11 Measurement of Natural Gas by Coriolis Meter

(2003), IBR approved for Sec. 98.244(b) and Sec. 98.254(c).

(4) AGA Transmission Measurement Committee Report No. 7 Measurement of Natural Gas by Turbine Meter (2006)/February, IBR approved for Sec. 98.34(b) and Sec. 98.244(b).

International, 9639 Kinsman Road, Materials Park, OH 44073, (440) 338- 5151, http://www.asminternational.org.

(1) ASM CS-104 UNS No. G10460--Alloy Digest April 1985 (Carbon

Steel of Medium Carbon Content), incorporation by reference (IBR) approved for Sec. 98.174(b).

(2) [Reserved]

(d) The following material is available for purchase from the

American Society of Mechanical Engineers (ASME), Three Park Avenue, New

York, NY 10016-5990, (800) 843-2763, http://www.asme.org.

(1) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using

Orifice, Nozzle, and Venturi, incorporation by reference (IBR) approved for Sec. 98.34(b), Sec. 98.244(b), Sec. 98.254(c), Sec. 98.344(c), and Sec. 98.364(e).

(2) ASME MFC-4M-1986 (Reaffirmed 1997) Measurement of Gas Flow by

Turbine Meters, IBR approved for Sec. 98.34(b), Sec. 98.244(b), Sec. 98.254(c), Sec. 98.344(c), and Sec. 98.364(e).

(3) ASME MFC-5M-1985 (Reaffirmed 1994) Measurement of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flowmeters, IBR approved for Sec. 98.34(b) and Sec. 98.244(b).

(4) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using

Vortex Flowmeters, IBR approved for Sec. 98.34(b), Sec. 98.244(b),

Sec. 98.254(c), Sec. 98.344(c), and Sec. 98.364(e).

(5) ASME MFC-7M-1987 (Reaffirmed 1992) Measurement of Gas Flow by

Means of Critical Flow Venturi Nozzles, IBR approved for Sec. 98.34(b), Sec. 98.244(b), Sec. 98.254(c), Sec. 98.344(c), and Sec. 98.364(e).

(6) ASME MFC-9M-1988 (Reaffirmed 2001) Measurement of Liquid Flow in Closed Conduits by Weighing Method, IBR approved for Sec. 98.34(b) and Sec. 98.244(b).

(7) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of

Coriolis Mass Flowmeters, IBR approved for Sec. 98.244(b), Sec. 98.254(c), and Sec. 98.344(c).

(8) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore

Precision Orifice Meters, IBR approved for Sec. 98.244(b), Sec. 98.254(c), Sec. 98.344(c), and Sec. 98.364(e).

(9) ASME MFC-16-2007 Measurement of Liquid Flow in Closed Conduits with Electromagnetic Flowmeters, IBR approved for Sec. 98.244(b).

(10) ASME MFC-18M-2001 Measurement of Fluid Flow Using Variable

Area Meters, IBR approved for Sec. 98.244(b), Sec. 98.254(c),Sec. 98.344(c), and Sec. 98.364(e).

(11) ASME MFC-22-2007 Measurement of Liquid by Turbine Flowmeters,

IBR approved for Sec. 98.244(b).

(e) The following material is available for purchase from the

American Society for Testing and Material (ASTM), 100 Barr Harbor

Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959,

(800) 262-1373, http://www.astm.org.

(1) ASTM C25-06 Standard Test Method for Chemical Analysis of

Limestone, Quicklime, and Hydrated Lime, incorporation by reference

(IBR) approved for Sec. 98.114(b), Sec. 98.174(b), Sec. 98.184(b),

Sec. 98.194(c), and Sec. 98.334(b).

(2) ASTM C114-09 Standard Test Methods for Chemical Analysis of

Hydraulic Cement, IBR approved for Sec. 98.84(a), Sec. 98.84(b), and

Sec. 98.84(c).

(3) ASTM D235-02 (Reapproved 2007) Standard Specification for

Mineral Spirits (Petroleum Spirits) (Hydrocarbon Dry Cleaning Solvent),

IBR approved for Sec. 98.6.

(4) ASTM D240-02 (Reapproved 2007) Standard Test Method for Heat of

Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR approved for Sec. 98.34(a) and Sec. 98.254(e).

(5) ASTM D388-05 Standard Classification of Coals by Rank, IBR approved for Sec. 98.6.

(6) ASTM D910-07a Standard Specification for Aviation Gasolines,

IBR approved for Sec. 98.6.

(7) ASTM D1298-99 (Reapproved 2005) Standard Test Method for

Density,

Page 56394

Relative Density (Specific Gravity), or API Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method, IBR approved for

Sec. 98.33(a).

(8) ASTM D1826-94 (Reapproved 2003) Standard Test Method for

Calorific (Heating) Value of Gases in Natural Gas Range by Continuous

Recording Calorimeter, IBR approved for Sec. 98.34(a) and Sec. 98.254(e).

(9) ASTM D1836-07 Standard Specification for Commercial Hexanes,

IBR approved for Sec. 98.6.

(10) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas by Gas Chromatography, IBR approved for Sec. 98.34(b), Sec. 98.74(c),

Sec. 98.164(b), Sec. 98.244(b), Sec. 98.254(d), and Sec. 98.344(b).

(11) ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis of Reformed Gas by Gas Chromatography, IBR approved for Sec. 98.34(b),

Sec. 98.74(c), Sec. 98.164(b), Sec. 98.254(d), Sec. 98.344(b), and

Sec. 98.364(c).

(12) ASTM D2013-07 Standard Practice for Preparing Coal Samples for

Analysis, IBR approved for Sec. 98.164(b).

(13) ASTM D2234/D2234M-07 Standard Practice for Collection of a

Gross Sample of Coal, IBR approved for Sec. 98.164(b).

(14) ASTM D2502-04 Standard Test Method for Estimation of Mean

Relative Molecular Mass of Petroleum Oils From Viscosity Measurements,

IBR approved for Sec. 98.34(b) and Sec. 98.74(c).

(15) ASTM D2503-92 (Reapproved 2007) Standard Test Method for

Relative Molecular Mass (Molecular Weight) of Hydrocarbons by

Thermoelectric Measurement of Vapor Pressure, IBR approved for Sec. 98.34(b) and Sec. 98.74(c).

(16) ASTM D2505-88 (Reapproved 2004)e1 Standard Test Method for

Ethylene, Other Hydrocarbons, and Carbon Dioxide in High-Purity

Ethylene by Gas Chromatography, IBR approved for Sec. 98.244(b).

(17) ASTM D2597-94 (Reapproved 2004) Standard Test Method for

Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing

Nitrogen and Carbon Dioxide by Gas Chromatography, IBR approved for

Sec. 98.164(b).

(18) ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate

Analysis of Coal and Coke, IBR approved for Sec. 98.74(c), Sec. 98.164(b), Sec. 98.244(b), Sec. 98.254(i), Sec. 98.284(c), Sec. 98.284(d), Sec. 98.314(c), Sec. 98.314(d), and Sec. 98.314(f).

(19) ASTM D3238-95 (Reapproved 2005) Standard Test Method for

Calculation of Carbon Distribution and Structural Group Analysis of

Petroleum Oils by the n-d-M Method, IBR approved for Sec. 98.34(b),

Sec. 98.74(c), and Sec. 98.164(b).

(20) ASTM D3588-98 (Reapproved 2003) Standard Practice for

Calculating Heat Value, Compressibility Factor, and Relative Density of

Gaseous Fuels, IBR approved for Sec. 98.34(a) and Sec. 98.254(e).

(21) ASTM D3682-01 (Reapproved 2006) Standard Test Method for Major and Minor Elements in Combustion Residues from Coal Utilization

Processes, IBR approved for Sec. 98.144(b).

(22) ASTM D4057-06 Standard Practice for Manual Sampling of

Petroleum and Petroleum Products, IBR approved for Sec. 98.164(b).

(23) ASTM D4177-95 (Reapproved 2005) Standard Practice for

Automatic Sampling of Petroleum and Petroleum Products, IBR approved for Sec. 98.164(b).

(24) ASTM D4809-06 Standard Test Method for Heat of Combustion of

Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), IBR approved for Sec. 98.34(a) and Sec. 98.254(e).

(25) ASTM D4891-89 (Reapproved 2006), Standard Test Method for

Heating Value of Gases in Natural Gas Range by Stoichiometric

Combustion, IBR approved for Sec. 98.34(a) and Sec. 98.254(e).

(26) ASTM D5291-02 (Reapproved 2007) Standard Test Methods for

Instrumental Determination of Carbon, Hydrogen, and Nitrogen in

Petroleum Products and Lubricants, IBR approved for Sec. 98.34(b),

Sec. 98.74(c), Sec. 98.164(b), Sec. 98.244(b), Sec. 98.254(i).

(27) ASTM D5373-08 Standard Test Methods for Instrumental

Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal, IBR approved for Sec. 98.34(b), Sec. 98.74(c), Sec. 98.114(b), Sec. 98.164(b), Sec. 98.174(b), Sec. 98.184(b), Sec. 98.244(b), Sec. 98.254(i), Sec. 98.274(b), Sec. 98.284(c), Sec. 98.284(d), Sec. 98.314(c), Sec. 98.314(d), Sec. 98.314(f), and Sec. 98.334(b).

(28) ASTM D5865-07a Standard Test Method for Gross Calorific Value of Coal and Coke, IBR approved for Sec. 98.34(a).

(29) ASTM D6060-96 (Reapproved 2001) Standard Practice for Sampling of Process Vents With a Portable Gas Chromatograph, IBR approved for

Sec. 98.244(b).

(30) ASTM D6348-03 Standard Test Method for Determination of

Gaseous Compounds by Extractive Direct Interface Fourier Transform

Infrared (FTIR) Spectroscopy, IBR approved for Sec. 98.54(b) and Sec. 98.224(b).

(31) ASTM D6609-08 Standard Guide for Part-Stream Sampling of Coal,

IBR approved for Sec. 98.164(b).

(32) ASTM D6751-08 Standard Specification for Biodiesel Fuel Blend

Stock (B100) for Middle Distillate Fuels, IBR approved for Sec. 98.6.

(33) ASTM D6866-08 Standard Test Methods for Determining the

Biobased Content of Solid, Liquid, and Gaseous Samples Using

Radiocarbon Analysis, IBR approved for Sec. 98.33(e), Sec. 98.34(d),

Sec. 98.34(e), and Sec. 98.36(e).

(34) ASTM D6883-04 Standard Practice for Manual Sampling of

Stationary Coal from Railroad Cars, Barges, Trucks, or Stockpiles, IBR approved for Sec. 98.164(b).

(35) ASTM D7430-08ae1 Standard Practice for Mechanical Sampling of

Coal, IBR approved for Sec. 98.164(b).

(36) ASTM D7459-08 Standard Practice for Collection of Integrated

Samples for the Speciation of Biomass (Biogenic) and Fossil-Derived

Carbon Dioxide Emitted from Stationary Emissions Sources, IBR approved for Sec. 98.33(e), Sec. 98.34(d), Sec. 98.34(e), and Sec. 98.36(e).

(37) ASTM E359-00 (Reapproved 2005)e1 Standard Test Methods for

Analysis of Soda Ash (Sodium Carbonate), IBR approved for Sec. 98.294(a) and Sec. 98.294(b).

(38) ASTM E1019-08 Standard Test Methods for Determination of

Carbon, Sulfur, Nitrogen, and Oxygen in Steel, Iron, Nickel, and Cobalt

Alloys by Various Combustion and Fusion Techniques, IBR approved for

Sec. 98.174(b).

(39) ASTM E1747-95 (Reapproved 2005) Standard Guide for Purity of

Carbon Dioxide Used in Supercritical Fluid Applications, IBR approved for 98.424(b).

(40) ASTM E1915-07a Standard Test Methods for Analysis of Metal

Bearing Ores and Related Materials by Combustion Infrared-Absorption

Spectrometry, IBR approved for Sec. 98.174(b).

(41) ASTM E1941-04 Standard Test Method for Determination of Carbon in Refractory and Reactive Metals and Their Alloys, IBR approved for

Sec. 98.114(b), Sec. 98.184(b), Sec. 98.334(b).

(42) ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography,

IBR approved for Sec. 98.164(b), Sec. 98.244(b), and Sec. 98.254(d), and Sec. 98.344(b).

(f) The following material is available for purchase from the Gas

Processors Association (GPA), 6526 East 60th Street, Tulsa, Oklahoma 74143, (918) 493-3872, http://www.gasprocessors.com.

(1) GPA 2172-09 Calculation of Gross Heating Value, Relative

Density, Compressibility and Theoretical Hydrocarbon Liquid Content for

Natural Gas Mixtures for Custody Transfer, IBR approved for Sec. 98.34(a).

(2) GPA 2261-00 Analysis for Natural Gas and Similar Gaseous

Mixtures by Gas Chromatography, IBR approved for

Page 56395

Sec. 98.34(a), Sec. 98.164(b), Sec. 98.254(d), and Sec. 98.344(b).

(g) The following material is available for purchase from the

International Standards Organization (ISO), 1, ch. de la Voie-Creuse,

Case postale 56, CH-1211 Geneva 20, Switzerland, +41 22 749 01 11, http://www.iso.org/iso/home.htm.

(1) ISO 3170: Petroleum liquids--Manual sampling--Third Edition 2004-02-01, IBR approved for Sec. 98.164(b).

(2) ISO 3171: Petroleum Liquids--Automatic pipeline sampling--

Second Edition 1988-12-01, IBR approved for Sec. 98.164(b).

(3) ISO 8316: Measurement of Liquid Flow in Closed Conduits--

Method by Collection of the Liquid in a Volumetric Tank (1987-10-01)--

First Edition, IBR approved for Sec. 98.244(b).

(4) ISO/TR 15349-1: 1998, Unalloyed steel--Determination of low carbon content. Part 1: Infrared absorption method after combustion in an electric resistance furnace (by peak separation) (1998-10-15)--First

Edition, IBR approved for Sec. 98.174(b).

(5) ISO/TR 15349-3: 1998, Unalloyed steel--Determination of low carbon content. Part 3: Infrared absorption method after combustion in an electric resistance furnace (with preheating) (1998-10-15)--First

Edition, IBR approved for Sec. 98.174(b).

(h) The following material is available for purchase from the

National Lime Association (NLA), 200 North Glebe Road, Suite 800,

Arlington, Virginia 22203, (703) 243-5463, http://www.lime.org.

(1) CO2Emissions Calculation Protocol for the Lime

Industry--English Units Version, February 5, 2008 Revision--National

Lime Association, incorporation by reference (IBR) approved for Sec. 98.194(c) and Sec. 98.194(e).

(2) [Reserved]

(i) The following material is available for purchase from the

National Institute of Standards and Technology (NIST), 100 Bureau

Drive, Stop 1070, Gaithersburg, MD 20899-1070, (800) 877-8339, http:// www.nist.gov/index.html.

(1) Specifications, Tolerances, and Other Technical Requirements

For Weighing and Measuring Devices, NIST Handbook 44 (2009), incorporation by reference (IBR) approved for Sec. 98.244(b), Sec. 98.254(h), and Sec. 98.344(a).

(2) [Reserved]

(j) The following material is available for purchase from the

Technical Association of the Pulp and Paper Industry (TAPPI), 15

Technology Parkway South, Norcross, GA 30092, (800) 332-8686, http:// www.tappi.org.

(1) T650 om-05 Solids Content of Black Liquor, TAPPI, incorporation by reference (IBR) approved for Sec. 98.276(c) and Sec. 98.277(d).

(2) T684 om-06 Gross Heating Value of Black Liquor, TAPPI, incorporation by reference (IBR) approved for Sec. 98.274(b).

Sec. 98.8 What are the compliance and enforcement provisions of this part?

Any violation of any requirement of this part shall be a violation of the Clean Air Act, including section 114 (42 U.S.C. 7414). A violation includes but is not limited to failure to report GHG emissions, failure to collect data needed to calculate GHG emissions, failure to continuously monitor and test as required, failure to retain records needed to verify the amount of GHG emissions, and failure to calculate GHG emissions following the methodologies specified in this part. Each day of a violation constitutes a separate violation.

Sec. 98.9 Addresses.

All requests, notifications, and communications to the

Administrator pursuant to this part, other than submittal of the annual

GHG report, shall be submitted to the following address:

(a) For U.S. mail. Director, Climate Change Division, 1200

Pennsylvania Ave., NW., Mail Code: 6207J, Washington, DC 20460.

(b) For package deliveries. Director, Climate Change Division, 1310

L St, NW., Washington, DC 20005.

Table A-1 to Subpart A of Part 98--Global Warming Potentials

100-Year Time Horizon

Global warming

Name

CAS No.

Chemical formula

potential (100 yr.)

Carbon dioxide..............................

124-38-9 CO2...........................

Methane.....................................

74-82-8 CH4...........................

Nitrous oxide...............................

10024-97-2 N2O...........................

310

HFC-23......................................

75-46-7 CHF3..........................

11,700

HFC-32......................................

75-10-5 CH2F2.........................

650

HFC-41......................................

593-53-3 CH3F..........................

150

HFC-125.....................................

354-33-6 C2HF5.........................

2,800

HFC-134.....................................

359-35-3 C2H2F4........................

1,000

HFC-134a....................................

811-97-2 CH2FCF3.......................

1,300

HFC-143.....................................

430-66-0 C2H3F3........................

300

HFC-143a....................................

420-46-2 C2H3F3........................

3,800

HFC-152.....................................

624-72-6 CH2FCH2F......................

HFC-152a....................................

75-37-6 CH3CHF2.......................

140

HFC-161.....................................

353-36-6 CH3CH2F.......................

HFC-227ea...................................

431-89-0 C3HF7.........................

2,900

HFC-236cb...................................

677-56-5 CH2FCF2CF3....................

1,340

HFC-236ea...................................

431-63-0 CHF2CHFCF3....................

1,370

HFC-236fa...................................

690-39-1 C3H2F6........................

6,300

HFC-245ca...................................

679-86-7 C3H3F5........................

560

HFC-245fa...................................

460-73-1 CHF2CH2CF3....................

1,030

HFC-365mfc..................................

406-58-6 CH3CF2CH2CF3..................

794

HFC-43-10mee................................

138495-42-8 CF3CFHCFHCF2CF3...............

1,300

Sulfur hexafluoride.........................

2551-62-4 SF6...........................

23,900

Trifluoromethyl sulphur pentafluoride.......

373-80-8 SF5CF3........................

17,700

Nitrogen trifluoride........................

7783-54-2 NF3...........................

17,200

PFC-14 (Perfluoromethane)...................

75-73-0 CF4...........................

6,500

PFC-116 (Perfluoroethane)...................

76-16-4 C2F6..........................

9,200

PFC-218 (Perfluoropropane)..................

76-19-7 C3F8..........................

7,000

Page 56396

Perfluorocyclopropane.......................

931-91-9 C-C3F6........................

17,340

PFC-3-1-10 (Perfluorobutane)................

355-25-9 C4F10.........................

7,000

Perfluorocyclobutane........................

115-25-3 C-C4F8........................

8,700

PFC-4-1-12 (Perfluoropentane)...............

678-26-2 C5F12.........................

7,500

PFC-5-1-14..................................

355-42-0 C6F14.........................

7,400

(Perfluorohexane)...........................

PFC-9-1-18..................................

306-94-5 C10F18........................

7,500

HCFE-235da2 (Isoflurane)....................

26675-46-7 CHF2OCHClCF3..................

350

HFE-43-10pccc (H-Galden 1040x)..............

E1730133 CHF2OCF2OC2F4OCHF2............

1,870

HFE-125.....................................

3822-68-2 CHF2OCF3......................

14,900

HFE-134.....................................

1691-17-4 CHF2OCHF2.....................

6,320

HFE-143a....................................

421-14-7 CH3OCF3.......................

756

HFE-227ea...................................

2356-62-9 CF3CHFOCF3....................

1,540

HFE-236ca12 (HG-10).........................

78522-47-1 CHF2OCF2OCHF2.................

2,800

HFE-236ea2 (Desflurane).....................

57041-67-5 CHF2OCHFCF3...................

989

HFE-236fa...................................

20193-67-3 CF3CH2OCF3....................

487

HFE-245cb2..................................

22410-44-2 CH3OCF2CF3....................

708

HFE-245fa1..................................

84011-15-4 CHF2CH2OCF3...................

286

HFE-245fa2..................................

1885-48-9 CHF2OCH2CF3...................

659

HFE-254cb2..................................

425-88-7 CH3OCF2CHF2...................

359

HFE-263fb2..................................

460-43-5 CF3CH2OCH3....................

HFE-329mcc2.................................

67490-36-2 CF3CF2OCF2CHF2................

919

HFE-338mcf2.................................

156053-88-2 CF3CF2OCH2CF3.................

552

HFE-338pcc13 (HG-01)........................

188690-78-0 CHF2OCF2CF2OCHF2..............

1,500

HFE-347mcc3.................................

28523-86-6 CH3OCF2CF2CF3.................

575

HFE-347mcf2.................................

E1730135 CF3CF2OCH2CHF2................

374

HFE-347pcf2.................................

406-78-0 CHF2CF2OCH2CF3................

580

HFE-356mec3.................................

382-34-3 CH3OCF2CHFCF3.................

101

HFE-356pcc3.................................

160620-20-2 CH3OCF2CF2CHF2................

110

HFE-356pcf2.................................

E1730137 CHF2CH2OCF2CHF2...............

265

HFE-356pcf3.................................

35042-99-0 CHF2OCH2CF2CHF2...............

502

HFE-365mcf3.................................

378-16-5 CF3CF2CH2OCH3.................

HFE-374pc2..................................

512-51-6 CH3CH2OCF2CHF2................

557

HFE-449sl (HFE-7100)........................

163702-07-6 C4F9OCH3......................

297

Chemical blend..............................

163702-08-7 (CF3)2CFCF2OCH3...............

HFE-569sf2 (HFE-7200).......................

163702-05-4 C4F9OC2H5.....................

Chemical blend..............................

163702-06-5 (CF3)2CFCF2OC2H5..............

Sevoflurane.................................

28523-86-6 CH2FOCH(CF3)2.................

345

HFE-356mm1..................................

13171-18-1 (CF3)2CHOCH3..................

HFE-338mmz1.................................

26103-08-2 CHF2OCH(CF3)2.................

380

(Octafluorotetramethy-lene)hydroxymethyl

NA X-(CF2)4CH(OH)-X..............

73 group.

HFE-347mmy1.................................

22052-84-2 CH3OCF(CF3)2..................

343

Bis(trifluoromethyl)-methanol...............

920-66-1 (CF3)2CHOH....................

195 2,2,3,3,3-pentafluoropropanol...............

422-05-9 CF3CF2CH2OH...................

PFPMIE......................................

NA CF3OCF(CF3)CF2OCF2OCF3........

10,300

NA = not available.

Table A-2 to Subpart A of Part 98--Units of Measure Conversions

To convert from

Multiply by

Kilograms (kg).......................... Pounds (lbs)................... 2.20462

Pounds (lbs)............................ Kilograms (kg)................. 0.45359

Pounds (lbs)............................ Metric tons.................... 4.53592 x 10-4

Short tons.............................. Pounds (lbs)................... 2,000

Short tons.............................. Metric tons.................... 0.90718

Metric tons............................. Short tons..................... 1.10231

Metric tons............................. Kilograms (kg)................. 1,000

Cubic meters (m\3\)..................... Cubic feet (ft\3\)............. 35.31467

Cubic feet (ft\3\)...................... Cubic meters (m\3\)............ 0.028317

Gallons (liquid, US).................... Liters (l)..................... 3.78541

Liters (l).............................. Gallons (liquid, US)........... 0.26417

Barrels of Liquid Fuel (bbl)............ Cubic meters (m\3\)............ 0.15891

Cubic meters (m\3\)..................... Barrels of Liquid Fuel (bbl)... 6.289

Barrels of Liquid Fuel (bbl)............ Gallons (liquid, US)........... 42

Gallons (liquid, US).................... Barrels of Liquid Fuel (bbl)... 0.023810

Gallons (liquid, US).................... Cubic meters (m\3\)............ 0.0037854

Liters (l).............................. Cubic meters (m\3\)............ 0.001

Page 56397

Feet (ft)............................... Meters (m)..................... 0.3048

Meters (m).............................. Feet (ft)...................... 3.28084

Miles (mi).............................. Kilometers (km)................ 1.60934

Kilometers (km)......................... Miles (mi)..................... 0.62137

Square feet (ft\2\)..................... Acres.......................... 2.29568 x 10-5

Square meters (m\2\).................... Acres.......................... 2.47105 x 10-4

Square miles (mi\2\).................... Square kilometers (km\2\)...... 2.58999

Degrees Celsius ([deg]C)................ Degrees Fahrenheit ([deg]F).... [deg]C = (\5/9\) x ([deg]F -32)

Degrees Fahrenheit ([deg]F)............. Degrees Celsius ([deg]C)....... [deg]F = (\9/5\) x [deg]C + 32

Degrees Celsius ([deg]C)................ Kelvin (K)..................... K = [deg]C + 273.15

Kelvin (K).............................. Degrees Rankine ([deg]R)....... 1.8

Joules.................................. Btu............................ 9.47817 x 10-4

Btu..................................... MMBtu.......................... 1 x 10-6

Pascals (Pa)............................ Inches of Mercury (in Hg)...... 2.95334 x 10-4

Inches of Mercury (inHg)................ Pounds per square inch (psi)... 0.49110

Pounds per square inch (psi)............ Inches of Mercury (in Hg)...... 2.03625

Subpart B--[Reserved]

Subpart C--General Stationary Fuel Combustion Sources

Sec. 98.30 Definition of the source category.

(a) Stationary fuel combustion sources are devices that combust solid, liquid, or gaseous fuel, generally for the purposes of producing electricity, generating steam, or providing useful heat or energy for industrial, commercial, or institutional use, or reducing the volume of waste by removing combustible matter. Stationary fuel combustion sources include, but are not limited to, boilers, simple and combined- cycle combustion turbines, engines, incinerators, and process heaters.

(b) This source category does not include:

(1) Portable equipment, as defined in Sec. 98.6.

(2) Emergency generators and emergency equipment, as defined in

Sec. 98.6.

(3) Irrigation pumps at agricultural operations.

(4) Flares, unless otherwise required by provisions of another subpart of 40 CFR part 98 to use methodologies in this subpart.

(5) Electricity generating units that are subject to subpart D of this part.

(c) For a unit that combusts hazardous waste (as defined in 40 CFR 261.3), reporting of GHG emissions is not required unless either of the following conditions apply:

(1) Continuous emission monitors (CEMS) are used to quantify

CO2mass emissions.

(2) Any fuel listed in Table C-1 of this subpart is also combusted in the unit. In this case, report GHG emissions from combustion of all fuels listed in Table C-1 of this subpart.

Sec. 98.31 Reporting threshold.

You must report GHG emissions under this subpart if your facility contains one or more stationary fuel combustion sources and the facility meets the applicability requirements of either Sec. Sec. 98.2(a)(1), 98.2(a)(2), or 98.2(a)(3).

Sec. 98.32 GHGs to report.

You must report CO2, CH4, and N2O mass emissions from each stationary fuel combustion unit.

Sec. 98.33 Calculating GHG emissions.

You must calculate CO2emissions according to paragraph

(a) of this section, and calculate CH4and N2O emissions according to paragraph (c) of this section.

(a) CO2emissions from fuel combustion. Calculate

CO2emissions by using one of the four calculation methodologies in this paragraph (a) subject to the conditions, requirements, and restrictions set forth in paragraph (b) of this section. If you co-fire biomass fuels with fossil fuels, report

CO2emissions from the combustion of biomass separately using the methods in paragraph (e) of this section.

(1) Tier 1 Calculation Methodology. Calculate the annual

CO2mass emissions for each type of fuel by using Equation

C-1 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.004

Where:

CO2= Annual CO2mass emissions for the specific fuel type (metric tons).

Fuel = Mass or volume of fuel combusted per year, from company records as defined in Sec. 98.6 (express mass in short tons for solid fuel, volume in standard cubic feet for gaseous fuel, and volume in gallons for liquid fuel).

HHV = Default high heat value of the fuel, from Table C-1 of this subpart (mmBtu per mass or mmBtu per volume, as applicable).

EF = Fuel-specific default CO2emission factor, from

Table C-1 of this subpart (kg CO2/mmBtu). 1 x 10-3= Conversion factor from kilograms to metric tons.

(2) Tier 2 Calculation Methodology. Calculate the annual

CO2mass emissions for each type of fuel by using either

Equation C2a or C2c of this section, as appropriate.

(i) Equation C-2a of this section applies to any type of fuel listed in Table C-1 of the subpart, except for municipal solid waste

(MSW). For MSW combustion, use Equation C-2c of this section.

Page 56398

GRAPHIC

TIFF OMITTED TR30OC09.005

Where:

CO2= Annual CO2mass emissions for a specific fuel type (metric tons).

Fuel = Mass or volume of the fuel combusted during the year, from company records as defined in Sec. 98.6 (express mass in short tons for solid fuel, volume in standard cubic feet for gaseous fuel, and volume in gallons for liquid fuel).

HHV = Annual average high heat value of the fuel from all valid samples for the year (mmBtu per mass or volume). The average HHV shall be calculated according to the requirements of paragraph

(a)(2)(ii) of this section.

EF = Fuel-specific default CO2emission factor, from

Table C-1 of this subpart (kg CO2/mmBtu). 1 x 10-3= Conversion factor from kilograms to metric tons.

(ii) The minimum number of HHV samples for determining annual average HHV is specified (e.g., monthly, quarterly, semi-annually, or by lot) in Sec. 98.34. The method for computing the annual average HHV is a function of how frequently you perform or receive from the fuel supplier the results of fuel sampling for HHV. The method is specified in paragraph (a)(2)(ii)(A) or (a)(2)(ii)(B) of this section, as applicable.

(A) If the results of fuel sampling are received monthly or more frequently, then the annual average HHV shall be calculated using

Equation C-2b of this section. If multiple HHV determinations are made in any month, average the values for the month arithmetically.

GRAPHIC

TIFF OMITTED TR30OC09.006

Where:

(HHV)annual= Weighted annual average high heat value of the fuel (mmBtu per mass or volume).

(HHV)i= High heat value of the fuel, for month ``i''

(mmBtu per mass or volume).

(Fuel)i= Mass or volume of the fuel combusted during month ``i'' (express mass in short tons for solid fuel, volume in standard cubic feet for gaseous fuel, and volume in gallons for liquid fuel). n = Number of months in the year that fuel is burned in the unit.

(B) If the results of fuel sampling are received less frequently than monthly, then the annual average HHV shall be computed as the arithmetic average HHV for all values for the year (including valid samples and substitute data values under Sec. 98.35).

(iii) For units that combust municipal solid waste (MSW) and that produce steam, use Equation C-2c of this section. Equation C-2c of this section may also be used for any other solid fuel listed in Table C-1 of this subpart provided that steam is generated by the unit.

GRAPHIC

TIFF OMITTED TR30OC09.007

Where:

CO2= Annual CO2mass emissions from MSW or solid fuel combustion (metric tons).

Steam = Total mass of steam generated by MSW or solid fuel combustion during the reporting year (lb steam).

B = Ratio of the boiler's maximum rated heat input capacity to its design rated steam output capacity (mmBtu/lb steam).

EF = Fuel-specific default CO2emission factor, from

Table C-1 of this subpart (kg CO2/mmBtu). 1 x 10-3= Conversion factor from kilograms to metric tons.

(3) Tier 3 Calculation Methodology. Calculate the annual

CO2mass emissions for each fuel by using either Equation

C3, C4, or C5 of this section, as appropriate.

(i) For a solid fuel, use Equation C-3 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.008

Where:

CO2= Annual CO2mass emissions from the combustion of the specific solid fuel (metric tons).

Fuel = Annual mass of the solid fuel combusted, from company records as defined in Sec. 98.6 (short tons).

CC = Annual average carbon content of the solid fuel (percent by weight, expressed as a decimal fraction, e.g., 95% = 0.95). The annual average carbon content shall be determined using the same procedures as specified for HHV in paragraph (a)(2)(ii) of this section. 44/12 = Ratio of molecular weights, CO2to carbon. 0.91 = Conversion factor from short tons to metric tons.

(ii) For a liquid fuel, use Equation C-4 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.009

Page 56399

Where:

CO2= Annual CO2mass emissions from the combustion of the specific liquid fuel (metric tons).

Fuel = Annual volume of the liquid fuel combusted (gallons). The volume of fuel combusted must be measured directly, using fuel flow meters calibrated according to Sec. 98.3(i). Fuel billing meters may be used for this purpose. Tank drop measurements may also be used.

CC = Annual average carbon content of the liquid fuel (kg C per gallon of fuel). The annual average carbon content shall be determined using the same procedures as specified for HHV in paragraph (a)(2)(ii) of this section. 44/12 = Ratio of molecular weights, CO2to carbon. 0.001 = Conversion factor from kg to metric tons.

(iii) For a gaseous fuel, use Equation C-5 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.010

Where:

CO2= Annual CO2mass emissions from combustion of the specific gaseous fuel (metric tons).

Fuel = Annual volume of the gaseous fuel combusted (scf). The volume of fuel combusted must be measured directly, using fuel flow meters calibrated according to Sec. 98.3(i). Fuel billing meters may be used for this purpose.

MW = Annual average molecular weight of the gaseous fuel (kg/kg- mole). The annual average carbon content shall be determined using the same procedures as specified for HHV in paragraph (a)(2)(ii) of this section.

MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard conditions, as defined in Sec. 98.6). 44/12 = Ratio of molecular weights, CO2to carbon. 0.001 = Conversion factor from kg to metric tons.

(iv) Fuel flow meters that measure mass flow rates may be used for liquid fuels, provided that the fuel density is used to convert the readings to volumetric flow rates. The density shall be measured at the same frequency as the carbon content, using ASTM D1298-99 (Reapproved 2005) ``Standard Test Method for Density, Relative Density (Specific

Gravity), or API Gravity of Crude Petroleum and Liquid Petroleum

Products by Hydrometer Method'' (incorporated by reference, see Sec. 98.7).

(v) The following default density values may be used for fuel oil, in lieu of using the ASTM method in paragraph (a)(3)(iv) of this section: 6.8 lb/gal for No. 1 oil; 7.2 lb/gal for No. 2 oil; 8.1 lb/gal for No. 6 oil.

(4) Tier 4 Calculation Methodology. Calculate the annual

CO2mass emissions from all fuels combusted in a unit, by using quality-assured data from continuous emission monitoring systems

(CEMS).

(i) This methodology requires a CO2concentration monitor and a stack gas volumetric flow rate monitor, except as otherwise provided in paragraph (a)(4)(iv) of this section. Hourly measurements of CO2concentration and stack gas flow rate are converted to CO2mass emission rates in metric tons per hour.

(ii) When the CO2concentration is measured on a wet basis, Equation C-6 of this section is used to calculate the hourly

CO2emission rates:

GRAPHIC

TIFF OMITTED TR30OC09.011

Where:

CO2= CO2mass emission rate (metric tons/hr).

CCO2= Hourly average CO2concentration (%

CO2).

Q = Hourly average stack gas volumetric flow rate (scfh). 5.18 x 10-7= Conversion factor (metric tons/scf/%

CO2).

(iii) If the CO2concentration is measured on a dry basis, a correction for the stack gas moisture content is required. You shall either continuously monitor the stack gas moisture content as described in Sec. 75.11(b)(2) of this chapter or, for certain types of fuel, use a default moisture percentage from Sec. 75.11(b)(1) of this chapter. For each unit operating hour, a moisture correction must be applied to Equation C-6 of this section as follows:

GRAPHIC

TIFF OMITTED TR30OC09.012

Where:

CO2* = Hourly CO2mass emission rate, corrected for moisture (metric tons/hr).

CO2= Hourly CO2mass emission rate from

Equation C-6 of this section, uncorrected (metric tons/hr).

%H2O = Hourly moisture percentage in the stack gas

(measured or default value, as appropriate).

(iv) An oxygen (O2) concentration monitor may be used in lieu of a CO2concentration monitor to determine the hourly

CO2concentrations, in accordance with Equation F-14a or F- 14b (as applicable) in appendix F to 40 CFR part 75, if the effluent gas stream monitored by the CEMS consists solely of combustion products

(i.e., no process CO2emissions are mixed with the combustion products) and if only fuels that are listed in Table 1 in section 3.3.5 of appendix F to 40 CFR part 75 are combusted in the unit. If the O2monitoring option is selected, the F-factors used in Equations F-14a and F-14b shall be determined according to section 3.3.5 or section 3.3.6 of appendix F to 40 CFR part 75, as applicable. If Equation F-14b is used, the hourly moisture percentage in the stack gas shall be either a measured value in accordance with

Sec. 75.11(b)(2) of this chapter, or, for certain types of fuel, a default moisture value from Sec. 75.11(b)(1) of this chapter.

(v) Each hourly CO2mass emission rate from Equation C-6 or C-7 of this section is multiplied by the operating time to convert it from metric tons per hour to metric tons. The operating time is the fraction of the hour during which fuel is combusted (e.g., the unit operating time is 1.0 if the unit operates for the whole hour and is 0.5 if the unit operates for 30 minutes in the hour). For common stack configurations, the operating time is the fraction of the hour during which effluent gases flow through the common stack.

(vi) The hourly CO2mass emissions are then summed over each calendar quarter and the quarterly totals are summed to determine the annual CO2mass emissions.

(vii) If both biomass and fossil fuel are combusted during the year, determine and report the biogenic CO2mass emissions separately, as described in paragraph (e) of this section.

(5) Alternative methods for units with continuous monitoring systems. Units not subject to the Acid Rain Program that report data to

EPA according to 40 CFR part 75 may use the alternative methods in this paragraph in lieu of using any of the four calculation methodology tiers.

(i) For a unit that combusts only natural gas and/or fuel oil, is not subject to the Acid Rain Program, monitors and reports heat input data year-round according to appendix D to 40 CFR part

Page 56400

75, but is not required by the applicable 40 CFR part 75 program to report CO2mass emissions data, calculate the annual

CO2mass emissions for the purposes of this part as follows:

(A) Use the hourly heat input data from appendix D to 40 CFR part 75, together with Equation G-4 in appendix G to 40 CFR part 75 to determine the hourly CO2mass emission rates, in units of tons/hr;

(B) Use Equations F-12 and F-13 in appendix F to 40 CFR part 75 to calculate the quarterly and cumulative annual CO2mass emissions, respectively, in units of short tons; and

(ii) For a unit that combusts only natural gas and/or fuel oil, is not subject to the Acid Rain Program, monitors and reports heat input data year-round according to 40 CFR 75.19 of this chapter but is not required by the applicable 40 CFR part 75 program to report

CO2mass emissions data, calculate the annual CO2 mass emissions for the purposes of this part as follows:

(A) Calculate the hourly CO2mass emissions, in units of short tons, using Equation LM-11 in 40 CFR 75.19(c)(4)(iii).

(B) Sum the hourly CO2mass emissions values over the entire reporting year to obtain the cumulative annual CO2 mass emissions, in units of short tons.

(iii) For a unit that is not subject to the Acid Rain Program, uses flow rate and CO2(or O2) CEMS to report heat input data year-round according to 40 CFR part 75, but is not required by the applicable 40 CFR part 75 program to report CO2mass emissions data, calculate the annual CO2mass emissions as follows:

(A) Use Equation F-11 or F-2 (as applicable) in appendix F to 40

CFR part 75 to calculate the hourly CO2mass emission rates from the CEMS data. If an O2monitor is used, convert the hourly average O2readings to CO2using Equation

F-14a or F-14b in appendix F to 40 CFR part 75 (as applicable), before applying Equation F-11 or F-2.

(B) Use Equations F-12 and F-13 in appendix F to 40 CFR part 75 to calculate the quarterly and cumulative annual CO2mass emissions, respectively, in units of short tons.

(D) If both biomass and fossil fuel are combusted during the year, determine and report the biogenic CO2mass emissions separately, as described in paragraph (e) of this section.

(b) Use of the four tiers. Use of the four tiers of CO2 emissions calculation methodologies described in paragraph (a) of this section is subject to the following conditions, requirements, and restrictions:

(1) The Tier 1 Calculation Methodology:

(i) May be used for any fuel listed in Table C-1 of this subpart that is combusted in a unit with a maximum rated heat input capacity of 250 mmBtu/hr or less.

(ii) May be used for MSW in a unit of any size that does not produce steam, if the use of Tier 4 is not required.

(iii) May be used for solid, gaseous, or liquid biomass fuels in a unit of any size provided that the fuel is listed in Table C-1 of this subpart.

(iv) May not be used if you routinely perform fuel sampling and analysis for the fuel high heat value (HHV) or routinely receive the results of HHV sampling and analysis from the fuel supplier at the minimum frequency specified in Sec. 98.34(a), or at a greater frequency. In such cases, Tier 2 shall be used.

(2) The Tier 2 Calculation Methodology:

(i) May be used for the combustion of any type of fuel in a unit with a maximum rated heat input capacity of 250 mmBtu/hr or less provided that the fuel is listed in Table C-1 of this subpart.

(ii) May be used in a unit with a maximum rated heat input capacity greater than 250 mmBtu/hr for the combustion of pipeline quality natural gas and distillate fuel oil.

(iii) May be used for MSW in a unit of any size that produces steam, if the use of Tier 4 is not required.

(3) The Tier 3 Calculation Methodology:

(i) May be used for a unit of any size that combusts any type of fuel listed in Table C-1 of this subpart (except for MSW), unless the use of Tier 4 is required.

(ii) Shall be used for a unit with a maximum rated heat input capacity greater than 250 mmBtu/hr that combusts any type of fuel listed in Table C-1 of this subpart (except MSW), unless either of the following conditions apply:

(A) The use of Tier 1 or 2 is permitted, as described in paragraphs

(b)(1)(iii) and (b)(2)(ii) of this section.

(B) The use of Tier 4 is required.

(iii) Shall be used for a fuel not listed in Table C-1 of this subpart if the fuel is combusted in a unit with a maximum rated heat input capacity greater than 250 mmBtu/hr provided that both of the following conditions apply:

(A) The use of Tier 4 is not required.

(B) The fuel provides 10% or more of the annual heat input to the unit or, if Sec. 98.36(c)(3) applies, to a group of units served by common supply pipe.

(4) The Tier 4 Calculation Methodology:

(i) May be used for a unit of any size, combusting any type of fuel.

(ii) Shall be used if the unit meets all six of the conditions specified in paragraphs (b)(4)(ii)(A) through (b)(4)(ii)(F) of this section:

(A) The unit has a maximum rated heat input capacity greater than 250 mmBtu/hr, or if the unit combusts municipal solid waste and has a maximum rated input capacity greater than 250 tons per day of MSW.

(B) The unit combusts solid fossil fuel or MSW, either as a primary or secondary fuel.

(D) The unit has installed CEMS that are required either by an applicable Federal or State regulation or the unit's operating permit.

(E) The installed CEMS include a gas monitor of any kind or a stack gas volumetric flow rate monitor, or both and the monitors have been certified, either in accordance with the requirements of 40 CFR part 75, part 60 of this chapter, or an applicable State continuous monitoring program.

(F) The installed gas or stack gas volumetric flow rate monitors are required, either by an applicable Federal or State regulation or by the unit's operating permit, to undergo periodic quality assurance testing in accordance with either appendix B to 40 CFR part 75, appendix F to 40 CFR part 60, or an applicable State continuous monitoring program.

(iii) Shall be used for a unit with a maximum rated heat input capacity of 250 mmBtu/hr or less and for a unit that combusts municipal solid waste with a maximum rated input capacity of 250 tons of MSW per day or less, if the unit meets all of the following three conditions:

(A) The unit has both a stack gas volumetric flow rate monitor and a CO2concentration monitor.

(B) The unit meets the conditions specified in paragraphs

(b)(4)(ii)(B) through (b)(4)(ii)(D) of this section.

(b)(4)(ii)(F) of this section.

Page 56401

(5) The Tier 4 Calculation Methodology shall be used beginning on:

(i) January 1, 2010, for a unit that is required to report

CO2mass emissions beginning on that date, if all of the monitors needed to measure CO2mass emissions have been installed and certified by that date.

(ii) January 1, 2011, for a unit that is required to report

CO2mass emissions beginning on January 1, 2010, if all of the monitors needed to measure CO2mass emissions have not been installed and certified by January 1, 2010. In this case, you may use Tier 2 or Tier 3 to report GHG emissions for 2010.

(6) You may elect to use any applicable higher tier for one or more of the fuels combusted in a unit. For example, if a 100 mmBtu/hr unit combusts natural gas and distillate fuel oil, you may elect to use Tier 1 for natural gas and Tier 3 for the fuel oil, even though Tier 1 could have been used for both fuels. However, for units that use either the

Tier 4 or the alternative calculation methodology specified in paragraph (a)(5) of this section, CO2emissions from the combustion of all fuels shall be based solely on CEMS measurements.

(c) Calculation of CH4 and N2O emissions from stationary combustion sources. You must calculate annual CH4and N2O mass emissions only for units that are required to report

CO2emissions using the calculation methodologies of this subpart and for only those fuels that are listed in Table C-2 of this subpart.

(1) Use Equation C-8 of this section to estimate CH4and

N2O emissions for any fuels for which you use the Tier 1 or

Tier 3 calculation methodologies for CO2. Use the same values for fuel combustion that you use for the Tier 1 or Tier 3 calculation.

GRAPHIC

TIFF OMITTED TR30OC09.013

Where:

CH4or N2O = Annual CH4or

N2O emissions from the combustion of a particular type of fuel (metric tons).

Fuel = Mass or volume of the fuel combusted, either from company records or directly measured by a fuel flow meter, as applicable

(mass or volume per year).

HHV = Default high heat value of the fuel from Table C-1 of this subpart (mmBtu per mass or volume).

EF = Fuel-specific default emission factor for CH4or

N2O, from Table C-2 of this subpart (kg CH4or

N2O per mmBtu). 1 x 10-3= Conversion factor from kilograms to metric tons.

(2) Use Equation C-9a of this section to estimate CH4 and N2O emissions for any fuels for which you use the Tier 2

Equation C-2a of this section to estimate CO2emissions. Use the same values for fuel combustion and HHV that you use for the Tier 1 or Tier 3 calculation.

GRAPHIC

TIFF OMITTED TR30OC09.014

Where:

CH4or N2O = Annual CH4or

N2O emissions from the combustion of a particular type of fuel (metric tons).

Fuel = Mass or volume of the fuel combusted during the reporting year.

HHV = High heat value of the fuel, averaged for all valid measurements for the reporting year (mmBtu per mass or volume).

EF = Fuel-specific default emission factor for CH4or

N2O, from Table C-2 of this subpart (kg CH4or

N2O per mmBtu). 1 x 10-3= Conversion factor from kilograms to metric tons.

(3) Use Equation C-9b of this section to estimate CH4 and N2O emissions for any fuels for which you use Equation

C-2c of this section to calculate the CO2emissions. Use the same values for steam generation and the ratio ``B'' that you use for

Equation C-2c.

GRAPHIC

TIFF OMITTED TR30OC09.015

Where:

CH4or N2O = Annual CH4or

N2O emissions from the combustion of a solid fuel (metric tons).

Steam = Total mass of steam generated by solid fuel combustion during the reporting year (lb steam).

B = Ratio of the boiler's maximum rated heat input capacity to its design rated steam output (mmBtu/lb steam).

EF = Fuel-specific emission factor for CH4or

N2O, from Table C-2 of this subpart (kg CH4or

N2O per mmBtu). 1 x 10-3= Conversion factor from kilograms to metric tons.

(4) Use Equation C-10 of this section for units in the Acid Rain

Program, units that monitor and report heat input on a year-round basis according to 40 CFR part 75, and units that use the Tier 4 Calculation

Methodology.

GRAPHIC

TIFF OMITTED TR30OC09.016

Where:

CH4or N2O = Annual CH4or

N2O emissions from the combustion of a particular type of fuel (metric tons).

(HI)A= Cumulative annual heat input from the fuel, derived from the electronic data reports required under Sec. 75.64 of this chapter or, for Tier 4 units, from the best available information as described in paragraph (c)(4)(ii) of this section

(mmBtu).

EF = Fuel-specific emission factor for CH4or

N2O, from Table C-2 of this section (kg CH4or

N2O per mmBtu). 0.001 = Conversion factor from kg to metric tons.

(i) If only one type of fuel listed in Table C-2 of this subpart is combusted during normal operation, substitute the cumulative annual heat input from combustion of the fuel into Equation C-10 of this section to calculate the annual CH4or N2O emissions.

Page 56402

(ii) If more than one type of fuel listed in Table C-2 of this subpart is combusted during normal operation, use Equation C-10 of this section separately for each type of fuel. If flow rate and diluent gas monitors are used to measure the unit heat input, use the best available information (e.g., fuel feed rate measurements, fuel heating values, engineering analysis) to estimate the annual heat input from each type of fuel.

(5) When multiple fuels are combusted during the reporting year, sum the fuel-specific results from Equations C-8, C-9a, C-9b, or C-10 of this section (as applicable) to obtain the total annual

CH4and N2O emissions, in metric tons.

(d) Calculation of CO2from sorbent.

(1) When a unit is a fluidized bed boiler, is equipped with a wet flue gas desulfurization system, or uses other acid gas emission controls with sorbent injection, use Equation C-11 of this section to calculate the CO2emissions from the sorbent, if those

CO2emissions are not monitored by CEMS:

GRAPHIC

TIFF OMITTED TR30OC09.017

Where:

CO2= CO2emitted from sorbent for the reporting year (metric tons).

S = Limestone or other sorbent used in the reporting year, from company records (short tons).

R = 1.00, the calcium-to-sulfur stoichiometric ratio.

MWCO2= Molecular weight of carbon dioxide (44).

MWS= Molecular weight of sorbent (100 if calcium carbonate). 0.91 = Conversion factor from short tons to metric tons.

(2) The annual CO2mass emissions for the unit shall be the sum of the CO2emissions from the combustion process and the CO2emissions from the sorbent.

(e) CO2 emissions from combustion of biomass. Use the procedures of this paragraph (e) to estimate biogenic CO2emissions from units that combust a combination of biomass and fossil fuels. Reporting of CO2emissions from combustion of biomass is required only for those biomass fuels listed in Table C-1 of this section, unless emissions are measured using CEMS.

(1) If CEMS are not used to measure CO2, use Equation C- 1 of this subpart to calculate the annual CO2mass emissions from the combustion of biomass (except MSW) for a unit of any size.

Determine the mass of biomass combusted using one of the following procedures in this paragraph (e)(1), as appropriate.

(i) Use company records.

(ii) Follow the procedures in paragraph (e)(5) of this section.

(iii) For premixed fuels that contain biomass and fossil fuels

(e.g., mixtures containing biodiesel), use best available information to determine the mass of biomass fuels and document the procedure used in the GHG Monitoring Plan required by Sec. 98.3(g)(5).

(2) If a CO2CEMS (or a surrogate O2monitor) and a stack gas flow rate monitor are used to determine the annual

CO2mass emissions either according to 40 CFR part 75, the

Tier 4 Calculation Methodology, or the alternative calculation methodology specified in paragraph (a)(5)(iii); and if both fossil fuel and biomass (except for MSW) are combusted in the unit during the reporting year, you may use the following procedure to determine the annual biogenic CO2mass emissions. If MSW is combusted in the unit, follow the procedures in paragraph (e)(3) of this section.

(i) For each operating hour, use Equation C-12 of this section to determine the volume of CO2emitted.

GRAPHIC

TIFF OMITTED TR30OC09.018

Where:

VCO2h= Hourly volume of CO2emitted (scf).

(%CO2)h= Hourly average CO2 concentration, measured by the CO2concentration monitor, or, if applicable, calculated from the hourly average O2 concentration (%CO2).

Qh= Hourly average stack gas volumetric flow rate, measured by the stack gas volumetric flow rate monitor (scfh). th= Source operating time (decimal fraction of the hour during which the source combusts fuel, i.e., 1.0 for a full operating hour, 0.5 for 30 minutes of operation, etc.). 100 = Conversion factor from percent to a decimal fraction.

(ii) Sum all of the hourly VCO2hvalues for the reporting year, to obtain Vtotal, the total annual volume of

CO2emitted.

(iii) Calculate the annual volume of CO2emitted from fossil fuel combustion using Equation C-13 of this section. If two or more types of fossil fuel are combusted during the year, perform a separate calculation with Equation C-13 of this section for each fuel and sum the results.

GRAPHIC

TIFF OMITTED TR30OC09.019

Where:

Vff= Annual volume of CO2emitted from combustion of a particular fossil fuel (scf).

Fuel = Total quantity of the fossil fuel combusted in the reporting year, from company records, as defined in Sec. 98.6 (lb for solid fuel, gallons for liquid fuel, and scf for gaseous fuel).

Fc= Fuel-specific carbon based F-factor, either a default value from Table 1 in section 3.3.5 of appendix F to 40 CFR part 75 or a site-specific value determined under section 3.3.6 of appendix F to 40 CFR part 75 (scf CO2/mmBtu).

HHV = High heat value of the fossil fuel, from fuel sampling and analysis (annual average value in Btu/lb for solid fuel, Btu/gal for liquid fuel and Btu/scf for gaseous fuel, sampled as specified

(e.g., monthly, quarterly, semi-annually, or by lot) in Sec. 98.34(a)(2)). The average HHV shall be calculated according to the requirements of paragraph (a)(2)(ii) of this section. 10\6\ = Conversion factor, Btu per mmBtu.

(iv) Subtract Vfffrom Vtotalto obtain

Vbio, the annual volume of CO2from the combustion of biomass. If a CEMS is being used to measure the combined combustion and process emissions from a unit that is subject to another subpart of part 98, then also subtract CO2process emissions from Vtotalto determine Vbio. The CO2 process emissions must be calculated according to the requirements of the applicable subpart.

Page 56403

(v) Calculate the biogenic percentage of the annual CO2 emissions,expressed as a decimal fraction, using Equation C-14 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.020

(vi) Calculate the annual biogenic CO2mass emissions, in metric tons, by multiplying the results obtained from Equation C-14 of this section by the annual CO2mass emissions in metric tons, as determined:

(A) Under paragraph (a)(4)(vi) of this section, for units using the

Tier 4 Calculation Methodology.

(B) Under paragraph (a)(5)(iii)(B) of this section, for units using the alternative calculation methodology specified in paragraph

(a)(5)(iii).

(C) From the electronic data report required under Sec. 75.64 of this chapter, for units in the Acid Rain Program and other units using

CEMS to monitor and report CO2mass emissions according to 40 CFR part 75. However, before calculating the annual biogenic

CO2mass emissions, multiply the cumulative annual

CO2mass emissions by 0.91 to convert from short tons to metric tons.

(3) For a unit that combusts MSW, the annual biogenic

CO2emissions shall be calculated using the procedures in this paragraph (e)(3).

(i) If the Tier 1 or Tier 2 Calculation Methodology is used to quantify CO2mass emissions:

(A) Use Equation C-1 or C-2c of this subpart, as appropriate, to calculate the annual CO2mass emissions from MSW combustion.

(B) Determine the relative proportions of biogenic and non-biogenic

CO2emissions on a quarterly basis using the method specified in Sec. 98.34(d).

(C) Determine the annual biogenic CO2mass emissions from MSW combustion by multiplying the annual CO2mass emissions by the annual average biogenic decimal fraction obtained from

Sec. 98.34(d).

(ii) If the unit uses Tier 4 to quantify CO2emissions:

(A) Follow the procedures in paragraphs (e)(2)(i) and (ii) of this section, to determine Vtotal.

(B) If any fossil fuel was combusted during the year, follow the procedures in paragraph (e)(2)(iii) of this section, to determine

Vff.

VMSW, the annual volume of CO2emissions from MSW combustion.

(D) Determine the annual volume of biogenic CO2 emissions (Vbio) from MSW combustion as follows. Multiply the annual volume of CO2emissions from MSW combustion

(VMSW) by the annual average biogenic decimal fraction obtained from ASTM D6866-08 and ASTM D7459-08.

(E) Calculate the biogenic percentage of the annual CO2 emissions from the unit, using Equation C-14 of this section. For the purposes of this calculation, the term ``Vbio'' in the numerator of Equation C-14 of this section shall be the results of the calculation performed under paragraph (e)(3)(ii)(D) of this section.

(F) Calculate the annual biogenic CO2mass emissions according to paragraph (e)(2)(vi)(A) of this section.

(4) As an alternative to the procedures in paragraph (e)(2) of this section, use ASTM Methods D7459-08 and D6866-08 to determine the biogenic portion of the annual CO2emissions, as described in Sec. 98.34(e). If this option is selected, the results of each determination shall be expressed as a decimal fraction (e.g., 0.30, if 30 percent of the CO2is biogenic), and the values shall be averaged over the reporting year. The annual biogenic CO2 mass emissions shall be calculated by multiplying the the total annual

CO2mass emissions by the annual average biogenic fraction obtained from ASTM D6866-08 and ASTM D7459-08.

(5) If Equation C-1 of this section is selected to calculate the annual biogenic mass emissions for wood, wood waste, or other solid biomass-derived fuel, Equation C-15 of this section may be used to quantify biogenic fuel consumption, provided that all of the required input parameters are accurately quantified. Similar equations and calculation methodologies based on steam generation and boiler efficiency may be used, provided that they are documented in the GHG

Monitoring Plan required by Sec. 98.3(g)(5).

GRAPHIC

TIFF OMITTED TR30OC09.021

Where:

(Fuel)p= Quantity of biomass consumed during the measurement period ``p'' (tons/year or tons/month, as applicable).

H = Average enthalpy of the boiler steam for the measurement period

(Btu/lb).

S = Total boiler steam production for the measurement period (lb/ month or lb/year, as applicable).

(HI)nb= Heat input from co-fired fossil fuels and non- biomass-derived fuels for the measurement period, based on company records of fuel usage and default or measured HHV values (Btu/month or Btu/year, as applicable).

(HHV)bio= Default or measured high heat value of the biomass fuel (Btu/lb).

(Eff)bio= Percent efficiency of biomass-to-energy conversion, expressed as a decimal fraction. 2000 = Conversion factor (lb/ton).

Sec. 98.34 Monitoring and QA/QC requirements.

The CO2mass emissions data for stationary fuel combustion sources shall be monitored as follows:

(a) For the Tier 2 Calculation Methodology:

(1) All fuel samples shall be taken at a location in the fuel handling system that provides a sample representative of the fuel combusted. The fuel sampling and analysis may be performed by either the owner or operator or the supplier of the fuel.

(2) The minimum required frequency of the HHV sampling and analysis for each type of fuel is specified in this paragraph. When the specified frequency is based on a specified time period (i.e., weekly, monthly, quarterly, or semiannually), fuel sampling and analysis is required only for those periods in which the unit operates.

(i) For natural gas, semiannual sampling and analysis is required

(i.e., twice in a calendar year, with consecutive samples taken at least four months apart).

(ii) For coal and fuel oil, analysis of at least one representative sample from each fuel lot is required. For the purposes of this section, a fuel lot is defined as a shipment or delivery of a single fuel (e.g., ship load, barge load, group of trucks, group of railroad cars, etc.).

(iii) For liquid fuels other than fuel oil, for fossil fuel-derived gaseous fuels, and for biogas; sampling and analysis is required at least once per calendar quarter. To the extent practicable, consecutive quarterly samples shall be taken at least 30 days apart.

(iv) For solid fuels other than coal and MSW, weekly sampling is required to

Page 56404

obtain composite samples, which are then analyzed monthly.

(3) If different types of fuel (e.g., different ranks of coal or different grades of fuel oil) are blended prior to combustion, use one of the following procedures in this paragraph.

(i) Use a weighted HHV value in the emission calculations, based on the relative proportions of each fuel in the blend.

(ii) Take a representative sample of the blend and analyze it for

HHV.

(4) If, for a particular type of fuel, HHV sampling and analysis is performed more often than the minimum frequency specified in paragraph

(a)(2) of this section, the results of all valid fuel analyses shall be used in the GHG emission calculations.

(5) If, for a particular type of fuel, valid HHV values are obtained at less than the minimum frequency specifed in paragraph

(a)(2) of this section, appropriate substitute data values shall be used in the emissions calculations, in accordance with missing data procedures of Sec. 98.35.

(6) Use any applicable fuel sampling and analysis methods in this paragraph (a)(6) to determine the high heat values. Alternatively, for gaseous fuels, the HHV may be calculated using chromatographic analysis together with standard heating values of the fuel constituents, provided that the gas chromatograph is operated, maintained, and calibrated according to the manufacturer's instructions.

(i) ASTM D4809-06 Standard Test Method for Heat of Combustion of

Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method)

(incorporated by reference, see Sec. 98.7).

(ii) ASTM D240-02 (Reapproved 2007) Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter

(incorporated by reference, see Sec. 98.7).

(iii) ASTM D1826-94 (Reapproved 2003) Standard Test Method for

Calorific (Heating) Value of Gases in Natural Gas Range by Continuous

Recording Calorimeter (incorporated by reference, see Sec. 98.7).

(iv) ASTM D3588-98 (Reapproved 2003) Standard Practice for

Calculating Heat Value, Compressibility Factor, and Relative Density of

Gaseous Fuels (incorporated by reference, see Sec. 98.7).

(v) ASTM D4891-89 (Reapproved 2006) Standard Test Method for

Heating Value of Gases in Natural Gas Range by Stoichiometric

Combustion (incorporated by reference, see Sec. 98.7).

(vi) GPA Standard 2172-09 Calculation of Gross Heating Value,

Relative Density, Compressibility and Theoretical Hydrocarbon Liquid

Content for Natural Gas Mixtures for Custody Transfer (incorporated by reference, see Sec. 98.7).

(vii) GPA Standard 2261-00, Analysis for Natural Gas and Similar

Gaseous Mixtures by Gas Chromatography (incorporated by reference, see

Sec. 98.7).

(viii) ASTM D5865-07a, Standard Test Method for Gross Calorific

Value of Coal and Coke (incorporated by reference, see Sec. 98.7).

(b) For the Tier 3 Calculation Methodology:

(1) Calibrate each oil and gas flow meter according to Sec. 98.3(i) and the provisions of this paragraph (b).

(i) Perform calibrations using any of the test methods and procedures in this paragraph (b)(1)(i):

(A) An applicable flow meter test method listed in paragraphs

(b)(4)(i) through (b)(4)(viii) of this section.

(B) The calibration procedures specified by the flow meter manufacturer.

(ii) In addition to the initial calibration required by Sec. 98.3(i), recalibrate each fuel flow meter (except for qualifying billing meters under paragraph (b)(1)(iii) of this section) either annually, at the minimum frequency specified by the manufacturer, or at the interval specified by the industry consensus standard practice used.

(iii) Fuel billing meters are exempted from the initial and ongoing calibration requirements of this paragraph, provided that the fuel supplier and the unit combusting the fuel do not have any common owners and are not owned by subsidiaries or affiliates of the same company.

(iv) For the initial calibration of an orifice, nozzle, or venturi meter; in-situ calibration of the transmitters is sufficient. A primary element inspection (PEI) shall be performed at least once every three years.

(v) For the continuously-operating units and processes described in

Sec. 98.3(i)(6), the required flow meter recalibrations and, if necessary, the PEIs may be postponed until the next scheduled maintenance outage.

(vi) If a mixture of fuels is transported by a common pipe (e.g., still gas and supplementary natural gas), you must either separately meter each of the fuels prior to mixing using flow meters calibrated according to Sec. 98.3(i), or use flow meters calibrated according to

Sec. 98.3(i) to measure the mixed fuel at the common pipe and to separately meter an appropriate subset of the fuels prior to mixing. If the latter option is chosen, quantify the fuels that are not measured prior to mixing by subtracting out the fuels measured prior to mixing from the fuel measured at the common pipe.

(2) Oil tank drop measurements (if used to determine liquid fuel use volume) shall be performed according to any an appropriate method published by a consensus-based standards organization (e.g., the

American Petroleum Institute).

(3) The carbon content and, if applicable, molecular weight of the fuels shall be determined according to the procedures in this paragraph

(b)(3).

(i) All fuel samples shall be taken at a location in the fuel handling system that provides a sample representative of the fuel combusted. The fuel sampling and analysis may be performed by either the owner or operator or by the supplier of the fuel.

(ii) At a minimum, fuel samples shall be collected at the frequency specified in this paragraph. When sampling is required at a specified time interval (e.g., weekly, monthly, quarterly, or semiannually), fuel sampling and analysis is required for only those specified periods in which the unit operates.

(A) For natural gas, semiannual sampling and analysis is required

(i.e., twice in a calendar year, with consecutive samples taken at least four months apart).

(B) For coal and fuel oil, analysis of at least one representative sample from each fuel lot is required. For the purposes of this section, a fuel lot is defined as a shipment or delivery of a single fuel (e.g., ship load, barge load, group of trucks, group of railroad cars, etc.).

(C) For other liquid fuels other than fuel oil, for fossil fuel- derived gaseous fuels, and for biogas; sampling and analysis is required at least once per calendar quarter. To the extent practicable, consecutive quarterly samples shall be taken at least 30 days apart.

(D) For solid fuels other than coal, weekly sampling is required to obtain composite samples, which are then analyzed monthly.

(E) For gaseous fuels other than natural gas and biogas (e.g., refinery gas), daily sampling and analysis to determine the carbon content and molecular weight of the fuel is required if the necessary equipment is in place to make these measurements. Otherwise, weekly sampling and analysis shall be performed.

(iii) If, for a particular type of fuel, sampling and analysis for carbon content and molecular weight is performed more often than the

Page 56405

minimum frequency specified in paragraph (b)(3) of this section, the results of all valid fuel analyses shall be used in the GHG emission calculations.

(iv) If, for a particular type of fuel, sampling and analysis for carbon content and molecular weight is performed at less than the minimum frequency specified in paragraph (b)(3) of this section, appropriate substitute data values shall be used in the emissions calculations, in accordance with the missing data procedures of Sec. 98.35.

(v) The procedures of paragraph (a)(3) of this section apply to carbon content and molecular weight determinations.

(4) Use any applicable standard method from the following list to quality assure the data from each fuel flow meter.

(i) AGA Report No. 3, Orifice Metering of Natural Gas and Other

Related Hydrocarbon Fluids, Part 1: General Equations and Uncertainty

Guidelines (1990) and Part 2: Specification and Installation

Requirements (2000) (incorporated by reference, see Sec. 98.7).

(ii) AGA Transmission Measurement Committee Report No. 7,

Measurement of Gas by Turbine Meters (2006) (incorporated by reference, see Sec. 98.7).

(iii) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using

Orifice, Nozzle, and Venturi (incorporated by reference, see Sec. 98.7).

(iv) ASME MFC-4M-1986 (Reaffirmed 1997), Measurement of Gas Flow by

Turbine Meters (incorporated by reference, see Sec. 98.7).

(v) ASME MFC-5M-1985 (Reaffirmed 1994), Measurement of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flowmeters

(incorporated by reference, see Sec. 98.7).

(vi) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using

Vortex Flowmeters (incorporated by reference, see Sec. 98.7).

(vii) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles (incorporated by reference, see Sec. 98.7).

(viii) ASME MFC-9M-1988 (Reaffirmed 2001), Measurement of Liquid

Flow in Closed Conduits by Weighing Method (incorporated by reference, see Sec. 98.7).

(5) Use any applicable methods from the following list to determine the carbon content and molecular weight (for gaseous fuel) of the fuel.

Alternatively, the results of chromatographic analysis of the fuel may be used, provided that the gas chromatograph is operated, maintained, and calibrated according to the manufacturer's instructions.

(i) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see Sec. 98.7).

(ii) ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference, see

Sec. 98.7).

(iii) ASTM D2502-04 (Reapproved 2002) Standard Test Method for

Estimation of Molecular Weight (Relative Molecular Mass) of Petroleum

Oils from Viscosity Measurements (incorporated by reference, see Sec. 98.7).

(iv) ASTM D2503-92 (Reapproved 2007) Standard Test Method for

Relative Molecular Mass (Relative Molecular Weight) of Hydrocarbons by

Thermoelectric Measurement of Vapor Pressure (incorporated by reference, see Sec. 98.7).

(v) ASTM D3238-95 (Reapproved 2005) Standard Test Method for

Calculation of Carbon Distribution and Structural Group Analysis of

Petroleum Oils by the n-d-M Method (incorporated by reference, see

Sec. 98.7).

(vi) ASTM D5291-02 (Reapproved 2007) Standard Test Methods for

Instrumental Determination of Carbon, Hydrogen, and Nitrogen in

Petroleum Products and Lubricants (incorporated by reference, see Sec. 98.7).

(vii) ASTM D5373-08 Standard Test Methods for Instrumental

Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see Sec. 98.7).

(c) For the Tier 4 Calculation Methodology, the CO2and flow rate monitors must be certified prior to the applicable deadline specified in Sec. 98.33(b)(5).

(1) For initial certification, you may use any one of the following three procedures in this paragraph.

(i) Sec. 75.20(c)(2) and (4) and appendix A to 40 CFR part 75.

(ii) The calibration drift test and relative accuracy test audit

(RATA) procedures of Performance Specification 3 in appendix B to part 60 (for the CO2concentration monitor) and Performance

Specification 6 in appendix B to part 60 (for the continuous emission rate monitoring system (CERMS)).

(iii) The provisions of an applicable State continuous monitoring program.

(2) If an O2concentration monitor is used to determine

CO2concentrations, the applicable provisions of 40 CFR part 75, 40 CFR part 60, or an applicable State continuous monitoring program shall be followed for initial certification and on-going quality assurance, and all required RATAs of the monitor shall be done on a percent CO2basis.

(3) For ongoing quality assurance, follow the applicable procedures in either appendix B to 40 CFR part 75, appendix F to 40 CFR part 60, or an applicable State continuous monitoring program. If appendix F to 40 CFR part 60 is selected for on-going quality assurance, perform daily calibration drift assessments for both the CO2monitor

(or surrogate O2monitor) and the flow rate monitor, conduct cylinder gas audits of the CO2concentration monitor in three of the four quarters of each year (except for non-operating quarters), and perform annual RATAs of the CO2concentration monitor and the CERMS.

(4) For the purposes of this part, the stack gas volumetric flow rate monitor RATAs required by appendix B to 40 CFR part 75 and the annual RATAs of the CERMS required by appendix F to 40 CFR part 60 need only be done at one operating level, representing normal load or normal process operating conditions, both for initial certification and for ongoing quality assurance.

(5) If, for any source operating hour, quality assured data are not obtained with a CO2monitor (or surrogate O2 monitor), flow rate monitor, or (if applicable) moisture monitor, use appropriate substitute data values in accordance with the missing data provisions of Sec. 98.35.

(d) When municipal solid waste (MSW) is combusted in a unit, determine the biogenic portion of the CO2emissions from MSW combustion using ASTM D6866-08 Standard Test Methods for Determining the Biobased Content of Solid, Liquid, and Gaseous Samples Using

Radiocarbon Analysis (incorporated by reference, see Sec. 98.7) and

ASTM D7459-08 Standard Practice for Collection of Integrated Samples for the Speciation of Biomass (Biogenic) and Fossil-Derived Carbon

Dioxide Emitted from Stationary Emissions Sources (incorporated by reference, see Sec. 98.7). Perform the ASTM D7459-08 sampling and the

ASTM D6866-08 analysis at least once in every calendar quarter in which

MSW is combusted in the unit. Collect each gas sample during normal unit operating conditions while MSW is the only fuel being combusted for at least 24 consecutive hours or for as long as is necessary to obtain a sample large enough to meet the specifications of ASTM D6866- 08. Separate CO2emissions into the biogenic and non- biogenic fraction using the average proportion of biogenic emissions of all samples analyzed during the reporting year. Express the results as a decimal fraction (e.g., 0.30, if 30 percent of the CO2 from MSW combustion is biogenic). If there is a

Page 56406

common fuel source of MSW that feeds multiple units at the facility, performing the testing at only one of the units is sufficient.

(e) For units that use CEMS to measure the total CO2 mass emissions and combust a combination of biogenic fuels (other than

MSW) with a fossil fuel, ASTM D6866-08 and ASTM D7459-08 may be used to determine the biogenic portion of the CO2emissions. Perform the ASTM D7459-08 sampling and the ASTM D6866-08 analysis at least once in every calendar quarter in which biogenic and non-biogenic fuels are co-fired in the unit. The relative proportions of the biogenic and non- biogenic fuels during the sampling shall be representative of the average fuel blend for a typical operating year. Collect each gas sample using ASTM D7459-08 during normal unit operation for at least 24 consecutive hours or for as long as is necessary to obtain a sample large enough to meet the specifications of ASTM D6866-08.

(f) Whenever company records are used in the calculation of

CO2emissions, the records required under Sec. 98.3(g) shall include both the company records and an explanation of how those records are used to estimate the following parameters:

(1) Fuel consumption, when the Tier 1 and Tier 2 Calculation

Methodologies are used.

(2) Fuel consumption, when solid fuel is combusted and the Tier 3

Calculation Methodology is used.

(3) Fossil fuel consumption when Sec. 98.33(e) applies to a unit that uses CEMS to quantify CO2emissions and that combusts both fossil and biomass fuels.

(4) Sorbent usage, when Sec. 98.33(d) applies.

(5) Quantity of steam generated by a unit when Sec. 98.33(a)(2) applies.

(6) Biogenic fuel consumption under Sec. 98.33(e)(5).

(g) As part of the GHG Monitoring Plan required under Sec. 98.3(g)(5), you must document the procedures used to ensure the accuracy of the estimates of fuel usage, sorbent usage, steam production, and boiler efficiency (as applicable) in paragraph (f) of this section, including but not limited to calibration of weighing equipment, fuel flow meters, steam flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices shall also be recorded, and the technical basis for these estimates shall be provided.

Sec. 98.35 Procedures for estimating missing data.

Whenever a quality-assured value of a required parameter is unavailable (e.g., if a CEMS malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations.

(a) For all units subject to the requirements of the Acid Rain

Program, and all other stationary combustion units subject to the requirements of this part that monitor and report emissions and heat input data in accordance with 40 CFR part 75, the missing data substitution procedures in 40 CFR part 75 shall be followed for

CO2concentration, stack gas flow rate, fuel flow rate, high heating value, and fuel carbon content.

(b) For units that use the Tier 1, Tier 2, Tier 3, and Tier 4

Calculation Methodologies, perform missing data substitution as follows for each parameter:

(1) For each missing value of the high heating value, carbon content, or molecular weight of the fuel, substitute the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If the

``after'' value has not been obtained by the time that the GHG emissions report is due, you may use the ``before'' value for missing data substitution or the best available estimate of the parameter, based on all available process data (e.g., electrical load, steam production, operating hours). If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period.

(2) For missing records of CO2concentration, stack gas flow rate, percent moisture, fuel usage, and sorbent usage, the substitute data value shall be the best available estimate of the parameter, based on all available process data (e.g., electrical load, steam production, operating hours, etc.). You must document and retain records of the procedures used for all such estimates.

Sec. 98.36 Data reporting requirements.

(a) In addition to the facility-level information required under

Sec. 98.3, the annual GHG emissions report shall contain the unit- level or process-level emissions data in paragraphs (b) through (d) of this section (as applicable) and the emissions verification data in paragraph (e) of this section.

(b) Units that use the four tiers. You shall report the following information for stationary combustion units that use the Tier 1, Tier 2, Tier 3, or Tier 4 methodology in Sec. 98.33(a) to calculate

CO2emissions, except as otherwise provided in paragraphs

(1) The unit ID number.

(2) A code representing the type of unit.

(3) Maximum rated heat input capacity of the unit, in mmBtu/hr for boilers and process heaters only and relevant units of measure for other combustion sources.

(4) Each type of fuel combusted in the unit during the report year.

(5) The tier used to calculate the CO2emissions for each type of fuel combusted (i.e., Tier 1, 2, 3, or 4).

(6) For a unit that uses Tiers 1, 2, and 3; the CO2,

CH4, and N2O emissions for each type of fuel combusted, expressed in metric tons of each gas and in metric tons of

CO2e.

(7) For a unit that uses Tier 4:

(i) For units that burn fossil fuels only, the annual

CO2emissions for all fuels combined. Reporting

CO2emissions by type of fuel is not required.

(ii) For units that burn both fossil fuels and biomass, the annual

CO2emissions from combustion of all fossil fuels combined and the annual CO2emissions from combustion of all biomass fuels combined. Reporting CO2emissions by type of fuel is not required.

(iii) Annual CH4and N2O emissions for each type of fuel combusted expressed in metric tons of each gas and in metric tons of CO2e.

(8) Annual CO2emissions from sorbent (if calculated using Equation C-11 of this subpart), expressed in metric tons.

(9) Annual GHG emissions from all fossil fuels burned in the unit

(i.e., the sum of the CO2, CH4, and

N2O emissions), expressed in metric tons of CO2e.

(10) Customer meter number for units that combust natural gas.

(c) Reporting alternatives for units using the four Tiers. You may use any of the applicable reporting alternatives of this paragraph to simplify the unit-level reporting required under paragraph (b) of this section:

(1) Aggregation of units. If a facility contains two or more units

(e.g., boilers or combustion turbines), each of which has a maximum rated heat input capacity of 250 mmBtu/hr or less, you may report the combined GHG emissions for the group of units in lieu of reporting GHG emissions from the individual units, provided that the use of Tier 4 is not required or elected for

Page 56407

any of the units and the units use the same tier for any common fuels combusted. If this option is selected, the following information shall be reported instead of the information in paragraph (b) of this section:

(i) Group ID number, beginning with the prefix ``GP''.

(ii) An identification number for each unit in the group.

(iii) Cumulative maximum rated heat input capacity of the group

(mmBtu/hr).

(iv) The highest maximum rated heat input capacity of any unit in the group (mmBtu/hr).

(v) Each type of fuel combusted in the group of units during the reporting year.

(vi) Annual CO2, CH4, and N2O mass emissions aggregated for each type of fuel combusted in the group of units during the year, expressed in metric tons of each gas and in metric tons of CO2e. If any of the units burn both fossil fuels and biomass, report also the annual CO2emissions from combustion of all fossil fuels combined and annual CO2 emissions from combustion of all biomass fuels combined, expressed in metric tons.

(vii) The tier used to calculate the CO2mass emissions for each type of fuel combusted in the units (i.e., Tier 1, Tier 2, or

Tier 3).

(viii) The calculated CO2mass emissions (if any) from sorbent.

(ix) Annual GHG emissions from all fossil fuels burned in the group

(i.e., the sum of the CO2, CH4, and

N2O emissions), expressed in metric tons of CO2e.

(2) Monitored common stack or duct configurations. When the flue gases from two or more stationary combustion units at a facility are discharged through a common stack or duct before exiting to the atmosphere and if CEMS are used to continuously monitor CO2 mass emissions at the common stack or duct according to the Tier 4

Calculation Methodology, you may report the combined emissions from the units sharing the common stack or duct, in lieu of separately reporting the GHG emissions from the individual units. The following information shall be reported instead of the information in paragraph (b) of this section:

(i) Common stack or duct identification number, beginning with the prefix ``CS''.

(ii) Identification numbers of the units sharing the common stack or duct.

(iii) Maximum rated heat input capacity of each unit sharing the common stack or duct (mmBtu/hr).

(iv) Each type of fuel combusted in the units during the year.

(v) The methodology used to calculate the CO2mass emissions, i.e., Tier 4.

(vi) If the any of the units burn both fossil fuels and biomass, annual CO2mass emissions, annual CO2emissions from combustion of fossil fuels, and annual CO2emissions from combustion of biomass measured at the common stack or duct, expressed in metric tons.

(vii) The annual CH4and N2O emissions from the units sharing the common stack or duct, expressed in metric tons of each gas and in metric tons of CO2e.

(viii) Annual GHG emissions from all fossil fuels burned in the group (i.e., the sum of the CO2, CH4, and

N2O emissions), expressed in metric tons of CO2e.

(3) Common pipe configurations. When two or more liquid-fired or gaseous-fired stationary combustion units at a facility combust the same type of fuel and the fuel is fed to the individual units through a common supply line or pipe, you may report the combined emissions from the units served by the common supply line, in lieu of separately reporting the GHG emissions from the individual units, provided that the total amount of fuel combusted by the units is accurately measured at the common pipe or supply line using a fuel flow meter that is calibrated in accordance with Sec. 98.34(a). If a portion of the fuel measured at the common pipe is diverted to a chemical or industrial process where it is used but not combusted, you may subtract the diverted fuel from the fuel measured at the common pipe prior to performing the GHG emissions calculations, provided that the amount of fuel diverted is also measured with a calibrated flow meter per Sec. 98.3(i). If the common pipe option is selected, the applicable tier shall be used based on the maximum rated heat input capacity of the largest unit served by the common pipe configuration. The following information shall be reported instead of the information in paragraph

(b) of this section:

(i) Common pipe identification number, beginning with the prefix

``CP''.

(ii) The identification numbers of the units served by the common pipe.

(iii) Maximum rated heat input capacity of each unit served by the common pipe (mmBtu/hr).

(iv) The fuels combusted in the units during the reporting year.

(v) The methodology used to calculate the CO2mass emissions (i.e., Tier 1, Tier 2, or Tier 3).

(vi) If the any of the units burns both fossil fuels and biomass, the annual CO2mass emissions from combustion of all fossil fuels and annual CO2emissions from combustion of all biomass fuels from the units served by the common pipe, expressed in metric tons.

(vii) Annual CH4and N2O emissions from the units served by the common pipe, expressed in metric tons of each gas and in metric tons of CO2e.

(viii) Annual GHG emissions from all fossil fuels burned in units served by the common pipe (i.e., the sum of the CO2,

CH4, and N2O emissions), expressed in metric tons of CO2e.

(d) Units subject to 40 CFR part 75.

(1) For stationary combustion units that are either subject to the

Acid Rain Program or not in the Acid Rain Program but monitor and report CO2mass emissions year-round according to 40 CFR part 75, you shall report the following unit-level information:

(i) Unit or stack identification numbers. Use exact same unit, common stack, or multiple stack identification numbers that represent the monitored locations (e.g., 1, 2, CS001, MS1A, etc.) that are reported under Sec. 75.64 of this chapter.

(ii) Annual CO2, CH4, and N2O emissions at each monitored location, expressed in metric tons of

CO2e.

(iii) Identification of the Part 75 methodology used to determine the CO2mass emissions.

(2) For units that use the alternative CO2mass emissions calculation methods for units with continuous monitoring systems provided in Sec. 98.33(a)(5), you shall report the following unit-level information:

(i) Unit, stack, or pipe ID numbers. Use exact same unit, common stack, or multiple stack identification numbers that represent the monitored locations (e.g., 1, 2, CS001, MS1A, etc.) that are reported under Sec. 75.64 of this chapter.

(ii) For units that use the alternative methods specified in Sec. 98.33(a)(5)(i) and (ii) to monitor and report heat input data year- round according to appendix D to 40 CFR part 75 or 40 CFR 75.19:

(A) Each type of fuel combusted in the unit during the reporting year.

(B) The methodology used to calculate the CO2mass emissions for each fuel type.

(C) A code or flag to indicate whether heat input is calculated according to appendix D to 40 CFR part 75 or 40 CFR 75.19.

(D) Annual CO2, CH4, and N2O emissions at each monitored location, across all fuel types, expressed in metric tons of CO2e.

(iii) For units with continuous monitoring systems that use the alternative method for units with continuous monitoring systems in

Sec. 98.33(a)(5)(iii) to monitor heat input year-round according to 40

CFR part 75:

(A) Fuel combusted during the reporting year.

Page 56408

(B) Methodology used to calculate the CO2mass emissions.

(D) The total annual CO2, CH4, and

N2O emissions at each monitored location, expressed in metric tons of CO2e.

(e) Verification data. You must keep on file, in a format suitable for inspection and auditing, sufficient data to verify the reported GHG emissions. This data and information must, where indicated in this paragraph (e), be included in the annual GHG emissions report.

(1) The applicable verification data specified in this paragraph

(e) are not required to be kept on file or reported for units that meet any one of the three following conditions:

(i) Are subject to the Acid Rain Program.

(ii) Use the alternative methods for units with continuous monitoring systems provided in Sec. 98.33(a)(5).

(iii) Are not in the Acid Rain Program, but are required monitor and report CO2mass emissions and heat input data year- round, in accordance with 40 CFR part 75.

(2) For stationary combustion sources using the Tier 1, Tier 2,

Tier 3, and Tier 4 Calculation Methodologies in Sec. 98.33(a) to quantify CO2emissions, the following additional information shall be kept on file and included in the GHG emissions report, where indicated:

(i) For the Tier 1 Calculation Methodology, report the total quantity of each type of fuel combusted in the unit or group of aggregated units (as applicable) during the reporting year, in short tons for solid fuels, gallons for liquid fuels and standard cubic feet for gaseous fuels.

(ii) For the Tier 2 Calculation Methodology, report:

(A) The total quantity of each type of fuel combusted in the unit or group of aggregated units (as applicable) during each month of the reporting year. Express the quantity of each fuel combusted during the measurement period in short tons for solid fuels, gallons for liquid fuels, and scf for gaseous fuels.

(B) The frequency of the HHV determinations (e.g., once a month, once per fuel lot).

(C) The high heat values used in the CO2emissions calculations for each type of fuel combusted, in mmBtu per short ton for solid fuels, mmBtu per gallon for liquid fuels, and mmBtu per scf for gaseous fuels. Specify the date on which each fuel sample was taken. Indicate whether each HHV is a measured value of a substitute data value.

(D) If Equation C-2c of this subpart is used to calculate

CO2mass emissions, report the total quantity (i.e., pounds) of steam produced from MSW or solid fuel combustion during the year, and the ratio of the maximum rate heat input capacity to the design rated steam output capacity of the unit, in mmBtu per lb of steam.

(iii) For the Tier 2 Calculation Methodology, keep records of the methods used to determine the HHV for each type of fuel combusted and the date on which each fuel sample was taken.

(iv) For the Tier 3 Calculation Methodology, report:

(A) The quantity of each type of fuel combusted in the unit or group of units (as applicable) during the year, in short tons for solid fuels, gallons for liquid fuels, and scf for gaseous fuels.

(B) The frequency of carbon content and, if applicable, molecular weight determinations for each type of fuel for the reporting year

(e.g., daily, weekly, monthly, semiannually, once per fuel lot).

(C) The carbon content and, if applicable, gas molecular weight values used in the emission calculations (including both valid and substitute data values). Report all measured values if the fuel is sampled monthly or less frequently. Otherwise, for daily and weekly sampling, report monthly average values determined using the calculation procedures in Equation C-2b for each variable. Express carbon content as a decimal fraction for solid fuels, kg C per gallon for liquid fuels, and kg C per kg of fuel for gaseous fuels. Express the gas molecular weights in units of kg per kg-mole.

(D) The total number of valid carbon content determinations and, if applicable, molecular weight determinations made during the reporting year, for each fuel type.

(E) The number of substitute data values used for carbon content and, if applicable, molecular weight used in the annual GHG emissions calculations.

(v) For the Tier 3 Calculation Methodology, keep records of the following:

(A) For liquid and gaseous fuel combustion, the dates and results of the initial calibrations and periodic recalibrations of the required fuel flow meters.

(B) For fuel oil combustion, the method from Sec. 98.34(b) used to make tank drop measurements (if applicable).

(D) The methods used to calibrate the fuel flow meters).

(vi) For the Tier 4 Calculation Methodology, report:

(A) The total number of source operating hours in the reporting year.

(B) The cumulative CO2mass emissions in each quarter of the reporting year, i.e., the sum of the hourly values calculated from

Equation C-6 or C-7 of this subpart (as applicable), in metric tons.

(C) For CO2concentration, stack gas flow rate, and (if applicable) stack gas moisture content, the percentage of source operating hours in which a substitute data value of each parameter was used in the emissions calculations.

(vii) For the Tier 4 Calculation Methodology, keep records of:

(A) Whether the CEMS certification and quality assurance procedures of 40 CFR part 75, 40 CFR part 60, or an applicable State continuous monitoring program were used.

(B) The dates and results of the initial certification tests of the

CEMS.

(C) The dates and results of the major quality assurance tests performed on the CEMS during the reporting year, i.e., linearity checks, cylinder gas audits, and relative accuracy test audits (RATAs).

(viii) If CO2emissions that are generated from acid gas scrubbing with sorbent injection are not captured using CEMS, report:

(A) The total amount of sorbent used during the report year, in short tons.

(B) The molecular weight of the sorbent.

(ix) For units that combust both fossil fuel and biomass, when CEMS are used to quantify the annual CO2emissions and biogenic

CO2is determined according to Sec. 98.33(e)(2), you shall report the following additional information, as applicable:

(A) The annual volume of CO2emitted from the combustion of all fuels, i.e., Vtotal, in scf.

(B) The annual volume of CO2emitted from the combustion of fossil fuels, i.e., Vff, in scf. If more than one type of fossil fuel was combusted, report the combustion volume of

CO2for each fuel separately as well as the total.

(D) The carbon-based F-factor used in Equation C-13 of this subpart, for each type of fossil fuel combusted, in scf CO2 per mmBtu.

(E) The annual average HHV value used in Equation C-13 of this subpart, for each type of fossil fuel combusted,

Continued on page 56409

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pp. 56409-56458

Mandatory Reporting of Greenhouse Gases

Continued from page 56408

Page 56409

in Btu/lb, Btu/gal, or Btu/scf, as appropriate.

(F) The total quantity of each type of fossil fuel combusted during the reporting year, in lb, gallons, or scf, as appropriate.

(G) Annual biogenic CO2mass emissions, in metric tons.

(x) When ASTM methods D7459-08 and D6866-08 are used to determine the biogenic portion of the annual CO2emissions from MSW combustion, report:

(A) The results of each quarterly sample analysis, expressed as a decimal fraction (e.g., if the biogenic fraction of the CO2 emissions from MSW combustion is 30 percent, report 0.30).

(B) Annual combined biomass and fossil fuel CO2 emissions from MSW combustion, in metric tons of CO2e.

VMSWfrom Sec. 98.33(e)(4)(ii), if CEMS are used to measure

CO2emissions.

(D) The annual volume of biogenic CO2emissions from MSW combustion, in metric tons.

(xi) When ASTM methods D7459-08 and D6866-08 are used to determine the biogenic portion of the annual CO2emissions from a unit that co-fires biogenic (other than MSW) and non-biogenic fuels, you shall report the results of each quarterly sample analysis, expressed as a decimal fraction (e.g., if the biogenic fraction of the

CO2emissions is 30 percent, report 0.30).

(3) Within 30 days of receipt of a written request from the

Administrator, you shall submit explanations of the following:

(i) An explanation of how company records are used to quantify fuel consumption, if the Tier 1 or Tier 2 Calculation Methodology is used to calculate CO2emissions.

(ii) An explanation of how company records are used to quantify fuel consumption, if solid fuel is combusted and the Tier 3 Calculation

Methodology is used to calculate CO2emissions.

(iii) An explanation of how sorbent usage is quantified.

(iv) An explanation of how company records are used to quantify fossil fuel consumption in units that uses CEMS to quantify

CO2emissions and combusts both fossil fuel and biomass.

(v) An explanation of how company records are used to measure steam production, when it is used to calculate CO2mass emissions under Sec. 98.33(a)(2)(iii) or to quantify solid fuel usage under

Sec. 98.33(c)(3).

(4) Within 30 days of receipt of a written request from the

Administrator, you shall submit the verification data and information described in paragraphs (e)(2)(iii), (e)(2)(v), and (e)(2)(vii) of this section.

Sec. 98.37 Records that must be retained.

In addition to the requirements of Sec. 98.3(g), you must retain the applicable records specified in Sec. Sec. 98.34(f) and (g), 98.35(b), and 98.36(e).

Sec. 98.38 Definitions.

All terms used in this subpart have the same meaning given in the

Clean Air Act and subpart A of this part.

Table C-1 to Subpart C of Part 98--Default CO2 Emission Factors and High

Heat Values for Various Types of Fuel

Default high heat

Default CO2

Fuel type

value

emission factor

Coal and coke

mmBtu/short ton

kg CO2/mmBtu

Anthracite.................... 25.09

103.54

Bituminous.................... 24.93

93.40

Subbituminous................. 17.25

97.02

Lignite....................... 14.21

96.36

Coke.......................... 24.80

102.04

Mixed (Commercial sector)..... 21.39

95.26

Mixed (Industrial coking)..... 26.28

93.65

Mixed (Industrial sector)..... 22.35

93.91

Mixed (Electric Power sector). 19.73

94.38

Natural gas

mmBtu/scf

kg CO2/mmBtu

Pipeline (Weighted U.S.

1.028 x 10-3

53.02

Average).

Petroleum products

mmBtu/gallon

kg CO2/mmBtu

Distillate Fuel Oil No. 1..... 0.139

73.25

Distillate Fuel Oil No. 2..... 0.138

73.96

Distillate Fuel Oil No. 4..... 0.146

75.04

Residual Fuel Oil No. 5....... 0.140

72.93

Residual Fuel Oil No. 6....... 0.150

75.10

Still Gas..................... 0.143

66.72

Kerosene...................... 0.135

75.20

Liquefied petroleum gases

0.092

62.98

(LPG).

Propane....................... 0.091

61.46

Propylene..................... 0.091

65.95

Ethane........................ 0.096

62.64

Ethylene...................... 0.100

67.43

Isobutane..................... 0.097

64.91

Isobutylene................... 0.103

67.74

Butane........................ 0.101

65.15

Butylene...................... 0.103

67.73

Naphtha (401 deg F)........ 0.139

76.22

Pentanes Plus................. 0.110

70.02

Petrochemical Feedstocks...... 0.129

70.97

Page 56410

Petroleum Coke................ 0.143

102.41

Special Naphtha............... 0.125

72.34

Unfinished Oils............... 0.139

74.49

Heavy Gas Oils................ 0.148

74.92

Lubricants.................... 0.144

74.27

Motor Gasoline................ 0.125

70.22

Aviation Gasoline............. 0.120

69.25

Kerosene-Type Jet Fuel........ 0.135

72.22

Asphalt and Road Oil.......... 0.158

75.36

Crude Oil..................... 0.138

74.49

Fossil fuel-derived fuels

mmBtu/short ton

kg CO2/mmBtu

(solid)

Municipal Solid Waste \1\..... 9.95

90.7

Tires......................... 26.87

85.97

Fossil fuel-derived fuels

mmBtu/scf

kg CO2/mmBtu

(gaseous)

Blast Furnace Gas............. 0.092 x 10-3

274.32

Coke Oven Gas................. 0.599 x 10-3

46.85

Biomass fuels--solid

mmBtu/short ton

kg CO2/mmBtu

Wood and Wood Residuals....... 15.38

93.80

Agricultural Byproducts....... 8.25

118.17

Peat.......................... 8.00

111.84

Solid Byproducts.............. 25.83

105.51

Biomass fuels--gaseous

mmBtu/scf

kg CO2/mmBtu

Biogas (Captured methane)..... 0.841 x 10-3

52.07

Biomass Fuels--Liquid.........

mmBtu/gallon

kg CO2/mmBtu

Ethanol (100%)................ 0.084

68.44

Biodiesel (100%).............. 0.128

73.84

Rendered Animal Fat........... 0.125

71.06

Vegetable Oil................. 0.120

81.55

\1\ Allowed only for units that do not generate steam and use Tier 1.

Table C-2 to Subpart C of Part 98--Default CH4 and N2O Emission Factors for Various Types of Fuel

Default CH4 emission Default N2O emission

Fuel type

factor (kg CH4/

factor (kg N2O/ mmBtu)

mmBtu)

Coal and Coke (All fuel

1.1 x 10-2

1.6 x 10-03 types in Table C-1).

Natural Gas................. 1.0 x 10-03

1.0 x 10-04

Petroleum (All fuel types in 3.0 x 10-03

6.0 x 10-04

Table C-1).

Municipal Solid Waste....... 3.2 x 10-02

4.2 x 10-03

Tires....................... 3.2 x 10-02

4.2 x 10-03

Blast Furnace Gas........... 2.2 x 10-05

1.0 x 10-04

Coke Oven Gas............... 4.8 x 10-04

1.0 x 10-04

Biomass Fuels--Solid (All

3.2 x 10-02

4.2 x 10-03 fuel types in Table C-1).

Biogas...................... 3.2 x 10-03

6.3 x 10-04

Biomass Fuels--Liquid (All 1.1 x 10-03

1.1 x 10-04 fuel types in Table C-1).

Note: Those employing this table are assumed to fall under the IPCC definitions of the ``Energy Industry'' or ``Manufacturing Industries and Construction''. In all fuels except for coal the values for these two categories are identical. For coal combustion, those who fall within the IPCC ``Energy Industry'' category may employ a value of 1g of CH4/MMBtu.

\1\ Allowed only for units that do not generate steam and use Tier 1.

Table C-2 to Subpart C--Default CH4 and N2O Emission Factors for Various

Types of Fuel

Default CH4 emission Default N2O emission

Fuel type

factor (kg CH4/

factor (kg N2O/ mmBtu)

mmBtu)

Coal and Coke (All fuel

1.1 x 10-2

1.6 x 10-03 types in Table C-1).

Natural Gas................. 1.0 x 10-03

1.0 x 10-04

Page 56411

Petroleum (All fuel types in 3.0 x 10-03

6.0 x 10-04

Table C-1).

Municipal Solid Waste....... 3.2 x 10-02

4.2 x 10-03

Tires....................... 3.2 x 10-02

4.2 x 10-03

Blast Furnace Gas........... 2.2 x 10-05

1.0 x 10-04

Coke Oven Gas............... 4.8 x 10-04

1.0 x 10-04

Biomass Fuels--Solid (All

3.2 x 10-02

4.2 x 10-03 fuel types in Table C-1).

Biogas...................... 3.2 x 10-03

6.3 x 10-04

Biomass Fuels--Liquid (All 1.1 x 10-03

1.1 x 10-04 fuel types in Table C-1).

Subpart D--Electricity Generation

Sec. 98.40 Definition of the source category.

(a) The electricity generation source category comprises electricity generating units that are subject to the requirements of the Acid Rain Program and any other electricity generating units that are required to monitor and report to EPA CO2emissions year-round according to 40 CFR part 75.

(b) This source category does not include portable equipment, emergency equipment, or emergency generators, as defined in Sec. 98.6.

Sec. 98.41 Reporting threshold.

You must report GHG emissions under this subpart if your facility contains one or more electricity generating units and the facility meets the requirements of Sec. 98.2(a)(1).

Sec. 98.42 GHGs to report.

(a) For each electricity generating unit that is subject to the requirements of the Acid Rain Program or is otherwise required to monitor and report to EPA CO2emissions year-round according to 40 CFR part 75, you must report under this subpart the annual mass emissions of CO2, N2O, and CH4by following the requirements of this subpart.

(b) For each electricity generating unit that is not subject to the

Acid Rain Program or otherwise required to monitor and report to EPA

CO2emissions year-round according to 40 CFR part 75, you must report under subpart C of this part (General Stationary Fuel

Combustion Sources) the emissions of CO2, CH4, and N2O by following the requirements of subpart C.

(c) For each stationary fuel combustion unit that does not generate electricity, you must report under subpart C of this part (General

Stationary Fuel Combustion Sources) the emissions of CO2,

CH4, and N2O by following the requirements of subpart C of this part.

Sec. 98.43 Calculating GHG emissions.

Continue to monitor and report CO2mass emissions as required under Sec. 75.13 or section 2.3 of apppendix G to 40 CFR part 75, and Sec. 75.64. Calculate CO2, CH4, and

N2O emissions as follows:

(a) Convert the cumulative annual CO2mass emissions reported in the fourth quarter electronic data report required under

Sec. 75.64 from units of short tons to metric tons. To convert tons to metric tons, divide by 1.1023.

(b) Calculate and report annual CH4and N2O mass emissions under this subpart by following the applicable method specified in Sec. 98.33(c).

Sec. 98.44 Monitoring and QA/QC requirements.

Follow the applicable quality assurance procedures for

CO2emissions in appendices B, D, and G to 40 CFR part 75.

Sec. 98.45 Procedures for estimating missing data.

Follow the applicable missing data substitution procedures in 40

CFR part 75 for CO2concentration, stack gas flow rate, fuel flow rate, high heating value, and fuel carbon content.

Sec. 98.46 Data reporting requirements.

The annual report shall comply with the data reporting requirements specified in Sec. 98.36(b) and, if applicable, Sec. 98.36(c)(2) or

(c)(3).

Sec. 98.47 Records that must be retained.

You shall comply with the recordkeeping requirements of Sec. Sec. 98.3(g) and 98.37.

Sec. 98.48 Definitions.

All terms used in this subpart have the same meaning given in the

Clean Air Act and subpart A of this part.

Subpart E--Adipic Acid Production

Sec. 98.50 Definition of source category.

The adipic acid production source category consists of all adipic acid production facilities that use oxidation to produce adipic acid.

Sec. 98.51 Reporting threshold.

You must report GHG emissions under this subpart if your facility contains an adipic acid production process and the facility meets the requirements of either Sec. 98.2(a)(1) or (2).

Sec. 98.52 GHGs to report.

(a) You must report N2O process emissions at the facility level.

(b) You must report under subpart C of this part (General

Stationary Fuel Combustion Sources) the emissions of CO2,

CH4, and N2O from each stationary combustion unit following the requirements of subpart C.

Sec. 98.53 Calculating GHG emissions.

(a) You must determine annual N2O emissions from adipic acid production according to paragraphs (a)(1) or (a)(2) of this section.

(1) Use a site-specific emission factor and production data according to paragraphs (b) through (h) of this section.

(2) Request Administrator approval for an alternative method of determining N2O emissions according to paragraphs (a)(2)(i) and (a)(2)(ii) of this section.

(i) You must submit the request within 45 days following promulgation of this subpart or within the first 30 days of each subsequent reporting year.

(ii) If the Administrator does not approve your requested alternative method within 150 days of the end of the reporting year, you must determine the N2O emissions factor for the current reporting period using the procedures specified in paragraphs (b) through (h) of this section.

(b) You must conduct an annual performance test according to

Page 56412

paragraphs (b)(1) through (b)(3) of this section.

(1) You must conduct the test on the waste gas stream from the nitric acid oxidation step of the process using the methods specified in Sec. 98.54(b) through (d).

(2) You must conduct the performance test under normal process operating conditions and without using N2O abatement technology.

(3) You must measure the adipic acid production rate during the test and calculate the production rate for the test period in metric tons per hour.

Equation E-2 of this section according to paragraphs (c)(1) or (c)(2) of this section.

(1) You may request Administrator approval for an alternative method of determining N2O concentration according to the procedures in paragraphs (a)(2)(i) and (a)(2)(ii) of this section.

Alternative methods include the use of N2O CEMs.

(2) Using the results of the performance test in paragraph (b) of this section, you must calculate a facility-specific emissions factor according to Equation E-1 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.022

Where:

EFN2O= Average facility-specific N2O emissions factor (lb N2O generated/ton adipic acid produced).

CN2O= N2O concentration per text run during the performance test (ppm N2O). 1.14 x 10-7= Conversion factor (lb/dscf-ppm

N2O).

Q = Volumetric flow rate of effluent gas per test run during the performance test (dscf/hr).

P = Production rate per test run during the performance test (tons adipic acid produced/hr). n = Number of test runs.

(d) If applicable, you must determine the destruction efficiency for each N2O abatement technology used at your facility according to paragraphs (d)(1), (d)(2), or (d)(3) of this section.

(1) Use the manufacturer's specified destruction efficiency.

(2) Estimate the destruction efficiency through process knowledge.

Examples of information that could constitute process knowledge include calculations based on material balances, process stoichiometry, or previous test results provided the results are still relevant to the current vent stream conditions. You must document how process knowledge was used to determine the destruction efficiency.

(3) Calculate the destruction efficiency by conducting an additional performance test on the emissions stream following the

N2O abatement technology.

(e) If applicable, you must determine the abatement factor for each

N2O abatement technology used at your facility. The abatement factor is calculated for each adipic acid facility according to Equation E-2 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.023

Where:

AFN= Abatement factor of N2O abatement technology (fraction of annual production that abatement technology is operating).

Pa Abate= Annual adipic acid production during which

N2O abatement was used.

Pa= Total annual adipic acid production (ton acid produced).

(f) You must determine the annual amount of adipic acid produced and the annual adipic acid production during which N2O abatement is operating.

(g) You must calculate annual adipic acid production process emissions of N2O by multiplying the emissions factor

(determined using Equation E-1 of this section) by the total annual adipic acid production and accounting for N2O abatement, according to Equation E-3 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.024

Where:

N2O = Annual N2O mass emissions from adipic acid production (metric tons).

EFN2O= Facility-specific N2O emissions factor

(lb N2O generated/ton adipic acid produced).

Pa= Annual adipic acid produced (tons).

DFN= Destruction efficiency of N2O abatement technology N (abatement device destruction efficiency, percent of

N2O removed from air stream).

AFN= Abatement factor of N2O abatement technology N (fraction of annual production abatement technology is operating). 2205 = Conversion factor (lb/metric ton).

N = Number of different N2O abatement technologies.

(h) You must determine the amount of process N2O emissions that is sold or transferred off site (if applicable). You can determine the amount using existing process flow meters and

N2O analyzers.

Sec. 98.54 Monitoring and QA/QC requirements.

(a) You must conduct a new performance test and calculate a new facility-specific emissions factor according to the frequency specified in paragraphs (a)(1) through (a)(3) of this section.

(1) Conduct the performance test annually.

(2) Conduct the performance test when your adipic acid production process is changed either by altering the ratio of cyclohexanone to cyclohexanol or by installing abatement equipment.

(3) If you requested Administrator approval for an alternative method of determining N2O concentration under Sec. 98.53(a)(2), you must conduct the performance test if your request has not been approved by the Administrator within 150 days of the end of the reporting year in which it was submitted.

(b) You must measure the N2O concentration during the performance test using one of the methods in paragraphs (b)(1) through

(b)(3) of this section.

(1) EPA Method 320, Measurement of Vapor Phase Organic and

Inorganic Emissions by Extractive Fourier

Page 56413

Transform Infrared (FTIR) Spectroscopy in 40 CFR part 63, Appendix A;

(2) ASTM D6348-03 Standard Test Method for Determination of Gaseous

Compounds by Extractive Direct Interface Fourier Transform Infrared

(FTIR) Spectroscopy (incorporated by reference, see Sec. 98.7); or

(3) An equivalent method, with Administrator approval.

(c) You must determine the production rate(s) during the performance test according to paragraph (c)(1) or (c)(2) of this section.

(1) Direct measurement (such as using flow meters or weigh scales).

(2) Existing plant procedures used for accounting purposes.

(d) You must conduct all required performance tests according to the methods in Sec. 98.54(b) in conjunction with the applicable EPA methods in 40 CFR part 60, appendices A-1 through A-4. Conduct three emissions test runs of 1 hour each. All QA/QC procedures specified in the reference test methods and any associated performance specifications apply. For each test, the facility must prepare an emissions factor determination report that must include the items in paragraphs (d)(1) through (d)(3) of this section:

(1) Analysis of samples, determination of emissions, and raw data.

(2) All information and data used to derive the emissions factor.

(3) The production rate(s) during the performance test and how each production rate was determined.

(e) You must determine the monthly adipic acid production quantity and the monthly adipic acid production during which N2O abatement technology is operating according to the methods in paragraphs (c)(1) or (c)(2) of this section.

(f) You must determine the annual adipic acid production quantity and the annual adipic production quantity during which N2O abatement technology is operating by summing the respective monthly adipic acid production quantities.

Sec. 98.55 Procedures for estimating missing data.

A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality- assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in paragraphs (a) and (b) of this section.

(a) For each missing value of monthly adipic acid production, the substitute data shall be the best available estimate based on all available process data or data used for accounting purposes (such as sales records).

(b) For missing values related to the performance test, including emission factors, production rate, and N2O concentration, you must conduct a new performance test according to the procedures in

Sec. 98.54 (a) through (d).

Sec. 98.56 Data reporting requirements.

In addition to the information required by Sec. 98.3(c), each annual report must contain the information specified in paragraphs (a) through (k) of this section at the facility level:

(a) Annual process N2O emissions from adipic acid production (metric tons).

(b) Annual adipic acid production (tons).

(d) Annual process N2O emissions from adipic acid production facility that is sold or transferred off site (metric tons).

(e) Number of abatement technologies (if applicable).

(f) Types of abatement technologies used (if applicable).

(g) Abatement technology destruction efficiency for each abatement technology (percent destruction).

(h) Abatement utilization factor for each abatement technology

(fraction of annual production that abatement technology is operating).

(i) Number of times in the reporting year that missing data procedures were followed to measure adipic acid production (months).

(j) If you conducted a performance test and calculated a site- specific emissions factor according to Sec. 98.53(a)(1), each annual report must also contain the information specified in paragraphs (j)(1) through (j)(7) of this section for each adipic acid production facility.

(1) Emissions factor (lb N2O/ton adipic acid).

(2) Test method used for performance test.

(3) Production rate per test run during performance test (tons/hr).

(4) N2O concentration per test run during performance test (ppm N2O).

(5) Volumetric flow rate per test run during performance test

(dscf/hr).

(6) Number of test runs.

(7) Number of times in the reporting year that a performance test had to be repeated (number).

(k) If you requested Administrator approval for an alternative method of determining N2O concentration under Sec. 98.53(a)(2), each annual report must also contain the information specified in paragraphs (k)(1) through (k)(4) of this section for each adipic acid production facility.

(1) Name of alternative method.

(2) Description of alternative method.

(3) Request date.

(4) Approval date.

Sec. 98.57 Records that must be retained.

In addition to the information required by Sec. 98.3(g), you must retain the records specified in paragraphs (a) through (h) of this section at the facility level:

(a) Annual adipic acid production capacity (tons).

(b) Records of significant changes to process.

(d) Documentation of how accounting procedures were used to estimate production rate.

(e) Documentation of how process knowledge was used to estimate abatement technology destruction efficiency.

(f) Performance test reports of N2O emissions.

(g) Measurements, records and calculations used to determine reported parameters.

(h) Documentation of the procedures used to ensure the accuracy of the measurements of all reported parameters, including but not limited to, calibration of weighing equipment, flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided.

Sec. 98.58 Definitions.

All terms used in this subpart have the same meaning given in the

Clean Air Act and subpart A of this part.

Subpart F--Aluminum Production

Sec. 98.60 Definition of the source category.

(a) A primary aluminum production facility manufactures primary aluminum using the Hall-H[eacute]roult manufacturing process. The primary aluminum manufacturing process comprises the following operations:

(1) Electrolysis in prebake and S[oslash]derberg cells.

(2) Anode baking for prebake cells.

(b) This source category does not include experimental cells or research and development process units.

Sec. 98.61 Reporting threshold.

You must report GHG emissions under this subpart if your facility contains an aluminum production process and the facility meets the

Page 56414

requirements of either Sec. 98.2(a)(1) or (a)(2).

Sec. 98.62 GHGs to report.

You must report:

(a) Perfluoromethane (CF4), and perfluoroethane

(C2F6) emissions from anode effects in all prebake and S[oslash]derberg electolysis cells.

(b) CO2emissions from anode consumption during electrolysis in all prebake and S[oslash]derberg electolysis cells.

(d) You must report under subpart C of this part (General

Stationary Fuel Combustion Sources) the emissions of CO2,

N2O, and CH4emissions from each stationary fuel combustion unit by following the requirements of subpart C.

Sec. 98.63 Calculating GHG emissions.

(a) The annual value for PFC emissions shall be estimated from the sum of monthly values using Equation F-1 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.025

Where:

EPFC= Annual PFC emissions from aluminum production

(metric tons PFC).

Em= PFC emissions from aluminum production for the month

``m'' (metric tons PFC).

(b) Use Equation F-2 of this section to estimate CF4 emissions from anode effect duration or Equation F-3 of this section to estimate CF4emissions from overvoltage, and use Equation F- 4 of this section to estimate C2F6emissions from anode effects from each prebake and S[oslash]derberg electolysis cell.

GRAPHIC

TIFF OMITTED TR30OC09.026

Where:

ECF4= Monthly CF4emissions from aluminum production (metric tons CF4).

SCF4= The slope coefficient ((kg CF4/metric ton Al)/(AE-Mins/cell-day)).

AEM = The anode effect minutes per cell-day (AE-Mins/cell-day).

MP = Metal production (metric tons Al), where AEM and MP are calculated monthly.

GRAPHIC

TIFF OMITTED TR30OC09.027

Where:

ECF4= Monthly CF4emissions from aluminum production (metric tons CF4).

EFCF4= The overvoltage emission factor (kg

CF4/metric ton Al).

MP = Metal production (metric tons Al), where MP is calculated monthly.

GRAPHIC

TIFF OMITTED TR30OC09.028

Where:

EC2F6= Monthly C2F6emissions from aluminum production (metric tons C2F6).

ECF4= CF4emissions from aluminum production

(kg CF4).

FC2F6/CF4= The weight fraction of

C2F6/CF4(kg

C2F6/kg CF4). 0.001 = Conversion factor from kg to metric tons, where

ECF4is calculated monthly.

(c) You must calculate and report the annual process CO2 emissions from anode consumption during electrolysis and anode baking of prebake cells using either the procedures in paragraph (d) of this section or the procedures in paragraphs (e) and (f) of this section.

(d) Calculate and report under this subpart the process

CO2emissions by operating and maintaining CEMS according to the Tier 4 Calculation Methodology in Sec. 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General

Stationary Fuel Combustion Sources).

(e) Use the following procedures to calculate CO2 emissions from anode consumption during electrolysis:

(1) For Prebake cells: you must calculate CO2emissions from anode consumption using Equation F-5 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.029

Where:

ECO2= Annual CO2emissions from prebaked anode consumption (metric tons CO2).

NAC = Net annual prebaked anode consumption per metric ton Al

(metric tons C/metric tons Al).

MP = Annual metal production (metric tons Al).

Sa= Sulfur content in baked anode (percent weight).

Asha= Ash content in baked anode (percent weight). 44/12 = Ratio of molecular weights, CO2to carbon.

(2) For S[oslash]derberg cells you must calculate CO2 emissions using Equation F-6 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.030

Page 56415

Where:

ECO2= Annual CO2emissions from paste consumption (metric ton CO2).

PC = Annual paste consumption (metric ton/metric ton Al).

MP = Annual metal production (metric ton Al).

CSM = Annual emissions of cyclohexane soluble matter (kg/metric ton

Al).

BC = Binder content of paste (percent weight).

Sp= Sulfur content of pitch (percent weight).

Ashp= Ash content of pitch (percent weight).

Hp =Hydrogen content of pitch (percent weight).

Sc =Sulfur content in calcined coke (percent weight).

Ashc =Ash content in calcined coke (percent weight).

CD = Carbon in skimmed dust from S[oslash]derberg cells (metric ton

C/metric ton Al). 44/12 = Ratio of molecular weights, CO2to carbon.

(f) Use the following procedures to calculate CO2 emissions from anode baking of prebake cells:

(1) Use Equation F-7 of this section to calculate emissions from pitch volatiles combustion.

GRAPHIC

TIFF OMITTED TR30OC09.031

Where:

ECO2PV= Annual CO2emissions from pitch volatiles combustion (metric tons CO2).

GA = Initial weight of green anodes (metric tons).

Hw= Annual hydrogen content in green anodes (metric tons).

BA = Annual baked anode production (metric tons).

WT = Annual waste tar collected (metric tons). 44/12 = Ratio of molecular weights, CO2to carbon.

(2) Use Equation F-8 of this section to calculate emissions from bake furnace packing material.

GRAPHIC

TIFF OMITTED TR30OC09.032

Where:

ECO2PC= Annual CO2emissions from bake furnace packing material (metric tons CO2).

PCC = Annual packing coke consumption (metric tons/metric ton baked anode).

BA = Annual baked anode production (metric tons).

Spc= Sulfur content in packing coke (percent weight).

Ashpc= Ash content in packing coke (percent weight). 44/12 = Ratio of molecular weights, CO2to carbon.

(g) If process CO2emissions from anode consumption during electrolysis or anode baking of prebake cells are vented through the same stack as any combustion unit or process equipment that reports

CO2emissions using a CEMS that complies with the Tier 4

Calculation Methodology in subpart C of this part (General Stationary

Fuel Combustion Sources), then the calculation methodology in paragraphs (d) and (e) of this section shall not be used to calculate those process emissions. The owner or operation shall report under this subpart the combined stack emissions according to the Tier 4

Calculation Methodology in Sec. 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary

Fuel Combustion Sources).

Sec. 98.64 Monitoring and QA/QC requirements.

(a) Effective one year after publication of the rule for smelters with no prior measurement or effective three years after publication for facilities with historic measurements, the smelter-specific slope coefficients used in Equations F-2, F-3, and F-4 of this subpart must be measured in accordance with the recommendations of the EPA/IAI

Protocol for Measurement of Tetrafluoromethane (CF4) and

Hexafluoroethane (C2F6) Emissions from Primary

Aluminum Production (2008), except the minimum frequency of measurement shall be every 10 years unless a change occurs in the control algorithm that affects the mix of types of anode effects or the nature of the anode effect termination routine. Facilities which operate at less than 0.2 anode effect minutes per cell day or operate with less than 1.4mV anode effect overvoltage can use either smelter-specific slope coefficients or the technology specific default values in Table F-1 of this subpart.

(b) The minimum frequency of the measurement and analysis is annually except as follows: Monthly--anode effect minutes per cell day

(or anode effect overvoltage and current efficiency), production.

(c) Sources may use either smelter-specific values from annual measurements of parameters needed to complete the equations in Sec. 98.63 (e.g., sulfur, ash, and hydrogen contents) or the default values shown in Table F-2 of this subpart.

Sec. 98.65 Procedures for estimating missing data.

A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality- assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required sample measurement is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the following requirements:

(a) Where anode or paste consumption data are missing,

CO2emissions can be estimated from aluminum production using Tier 1 method per Equation F-8 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.033

Where:

ECO2= CO2emissions from anode and/or paste consumption, metric tons CO2.

EFp= Prebake technology specific emission factor (1.6 metric tons CO2/metric ton aluminum produced).

MPp= Metal production from prebake process (metric tons

Al).

EFs= S[oslash]derberg technology specific emission factor (1.7 metric tons CO2/metric ton Al produced).

MPs= Metal production from S[oslash]derberg process

(metric tons Al).

Page 56416

(b) For other parameters, use the average of the two most recent data points after the missing data.

Sec. 98.66 Data reporting requirements.

In addition to the information required by Sec. 98.3(c), you must report the following information at the facility level:

(a) Annual aluminum production in metric tons.

(b) Type of smelter technology used.

(1) Perfluoromethane emissions and perfluoroethane emissions from anode effects in all prebake and all S[oslash]derberg electolysis cells combined.

(2) Anode effect minutes per cell-day (AE-mins/cell-day), anode effect frequency (AE/cell-day), anode effect duration (minutes). (Or anode effect overvoltage factor ((kg CF4/metric ton Al)/(mV/ cell day)), potline overvoltage (mV/cell day), current efficiency (%).)

(3) Smelter-specific slope coefficients (or overvoltage emission factors) and the last date when the smelter-specific-slope coefficients

(or overvoltage emission factors) were measured.

(d) Method used to measure the frequency and duration of anode effects (or overvoltage).

(e) The following CO2-specific information for prebake cells:

(1) Annual anode consumption.

(2) Annual CO2emissions from the smelter.

(f) The following CO2-specific information for

S[oslash]derberg cells:

(1) Annual paste consumption.

(2) Annual CO2emissions from the smelter.

(g) Smelter-specific inputs to the CO2process equations

(e.g., levels of sulfur and ash) that were used in the calculation, on an annual basis.

(h) Exact data elements required will vary depending on smelter technology (e.g., point-feed prebake or S[oslash]derberg) and process control technology (e.g., Pechiney or other).

Sec. 98.67 Records that must be retained.

In addition to the information required by Sec. 98.3(g), you must retain the following records:

(a) Monthly aluminum production in metric tons.

(b) Type of smelter technology used.

(1) Perfluoromethane and perfluoroethane emissions from anode effects in prebake and S[oslash]derberg electolysis cells.

(%).))

(3) Smelter-specific slope coefficients and the last date when the smelter-specific-slope coefficients were measured.

(d) Method used to measure the frequency and duration of anode effects (or to measure anode effect overvoltage and current efficiency).

(e) The following CO2-specific information for prebake cells:

(1) Annual anode consumption.

(2) Annual CO2emissions from the smelter.

(f) The following CO2-specific information for

S[oslash]derberg cells:

(1) Annual paste consumption.

(2) Annual CO2emissions from the smelter.

(g) Smelter-specific inputs to the CO2process equations

(e.g., levels of sulfur and ash) that were used in the calculation, on an annual basis.

(h) Exact data elements required will vary depending on smelter technology (e.g., point-feed prebake or S[oslash]derberg) and process control technology (e.g., Pechiney or other).

Sec. 98.68 Definitions.

All terms used in this subpart have the same meaning given in the

Clean Air Act and subpart A of this part.

Table F-1 to Subpart F of Part 98--Slope and Overvoltage Coefficients for the Calculation of PFC Emissions From

Aluminum Production

CF4 slope

CF4 coefficient

overvoltage

Weight

(kg CF4/

coefficient fraction C2F6/

Technology

metric ton Al)/

[(kg CF4/

CF4 [(kg C2F6/

(AE-Mins/cell- metric ton Al)/ kg CF4)

day)]

(mV)]

CWPB............................................................

0.143

1.16

0.121

SWPB............................................................

0.272

3.65

0.252

VSS.............................................................

0.092

0.053

HSS.............................................................

0.099

0.085

Table F-2 to Subpart F of Part 98--Default Data Sources for Parameters

Used for CO2 Emissions

Parameter

Data source

CO2 Emissions from Prebake Cells (CWPB and SWPB)

MP: metal production (metric tons Individual facility records.

Al).

NAC: net annual prebaked anode

Individual facility records. consumption per metric ton Al

(metric tons C/metric tons Al).

Sa: sulfur content in baked anode 2.0.

(percent weight).

Asha: ash content in baked anode 0.4.

(percent weight).

CO2 Emissions from S[oslash]derberg Cells (VSS and HSS)

MP: metal production (metric tons Individual facility records.

Al).

PC: annual paste consumption

Individual facility records.

(metric ton/metric ton Al).

CSM: annual emissions of

HSS: 4.0. cyclohexane soluble matter (kg/ VSS: 0.5. metric ton Al).

BC: binder content of paste

Dry Paste: 24.

(percent weight).

Wet Paste: 27.

Sp: sulfur content of pitch

0.6.

(percent weight).

Ashp: ash content of pitch

0.2.

(percent weight).

Page 56417

Hp: hydrogen content of pitch

3.3.

(percent weight).

Sc: sulfur content in calcined

1.9. coke (percent weight).

Ashc: ash content in calcined

0.2. coke (percent weight).

CD: carbon in skimmed dust from 0.01.

S[oslash]derberg cells (metric ton C/metric ton Al).

CO2 Emissions from Pitch Volatiles Combustion (VSS and HSS)

GA: initial weight of green

Individual facility records. anodes (metric tons).

Hw: annual hydrogen content in

0.005 x GA. green anodes (metric tons).

BA: annual baked anode production Individual facility records.

(metric tons).

WT: annual waste tar collected

(a) 0.005 x GA.

(metric tons).

(a) Riedhammer furnaces.......... (b) insignificant.

(b) all other furnaces...........

CO2 Emissions From Bake Furnace Packing Materials (CWPB and SWPB)

PCC: annual packing coke

0.015. consumption (metric tons/metric ton baked anode).

BA: annual baked anode production Individual facility records.

(metric tons).

Spc: sulfur content in packing

2. coke (percent weight).

Ashpc: ash content in packing

2.5. coke (percent weight).

Subpart G--Ammonia Manufacturing

Sec. 98.70 Definition of source category.

The ammonia manufacturing source category comprises the process units listed in paragraphs (a) and (b) of this section.

(a) Ammonia manufacturing processes in which ammonia is manufactured from a fossil-based feedstock produced via steam reforming of a hydrocarbon.

(b) Ammonia manufacturing processes in which ammonia is manufactured through the gasification of solid and liquid raw material.

Sec. 98.71 Reporting threshold.

You must report GHG emissions under this subpart if your facility contains an ammonia manufacturing process and the facility meets the requirements of either Sec. 98.2(a)(1) or (2).

Sec. 98.72 GHGs to report.

You must report:

(a) CO2process emissions from steam reforming of a hydrocarbon or the gasification of solid and liquid raw material, reported for each ammonia manufacturing process unit following the requirements in this subpart.

(b) CO2, CH4, and N2O emissions from each stationary fuel combustion unit. You must report these emissions under subpart C of this part (General Stationary Fuel

Combustion Sources), by following the requirements of subpart C.

(c) CO2emissions collected and transferred off site under subpart PP of this part (Suppliers of CO2), following the requirements of subpart PP.

Sec. 98.73 Calculating GHG emissions.

You must calculate and report the annual process CO2 emissions from each ammonia manufacturing process unit using the procedures in either paragraph (a) or (b) of this section.

(a) Calculate and report under this subpart the process

CO2emissions by operating and maintaining CEMS according to the Tier 4 Calculation Methodology specified in Sec. 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part

(General Stationary Fuel Combustion Sources).

(b) Calculate and report under this subpart process CO2 emissions using the procedures in paragraphs (b)(1) through (b)(6) of this section for gaseous feedstock, liquid feedstock, or solid feedstock, as applicable.

(1) Gaseous feedstock. You must calculate, from each ammonia manufacturing unit, the CO2process emissions from gaseous feedstock according to Equation G-1 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.034

Where:

CO2,G= Annual CO2emissions arising from feedstock consumption (metric tons).

Fdstkn= Volume of the gaseous feedstock used in month n

(scf of feedstock).

CCn= Carbon content of the gaseous feedstock, for month n (kg C per kg of feedstock), determined according to 98.74(c).

MW = Molecular weight of the gaseous feedstock (kg/kg-mole).

MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard conditions). 44/12 = Ratio of molecular weights, CO2to carbon. 0.001 = Conversion factor from kg to metric tons. k = Processing unit. n = Number of month.

(2) Liquid feedstock. You must calculate, from each ammonia manufacturing unit, the CO2process emissions from liquid feedstock according to Equation G-2 of this section:

Page 56418

GRAPHIC

TIFF OMITTED TR30OC09.035

Where:

CO2,L= Annual CO2emissions arising from feedstock consumption (metric tons).

Fdstkn= Volume of the liquid feedstock used in month n

(gallons of feedstock).

CCn= Carbon content of the liquid feedstock, for month n

(kg C per gallon of feedstock) determined according to 98.74(c). 44/12 = Ratio of molecular weights, CO2to carbon. 0.001 = Conversion factor from kg to metric tons. k = Processing unit. n = Number of month.

(3) Solid feedstock. You must calculate, from each ammonia manufacturing unit, the CO2process emissions from solid feedstock according to Equation G-3 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.036

Where:

CO2,S= Annual CO2emissions arising from feedstock consumption (metric tons).

Fdstkn= Mass of the solid feedstock used in month n (kg of feedstock).

CCn= Carbon content of the solid feedstock, for month n

(kg C per kg of feedstock), determined according to 98.74(c). 44/12 = Ratio of molecular weights, CO2to carbon. 0.001 = Conversion factor from kg to metric tons. k = Processing unit. n = Number of month.

(4) You must calculate the annual process CO2emissions from each ammonia processing unit k at your facility summing emissions, as applicable from Equation G-1, G-2, and G-3 of this section using

Equation G-4.

GRAPHIC

TIFF OMITTED TR30OC09.037

Where:

ECO2k = Annual CO2emissions from each ammonia processing unit k (metric tons). k = Processing unit.

(5) You must determine the combined CO2emissions from all ammonia processing units at your facility using Equation G-5 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.038

Where:

CO2= Annual combined CO2emissions from all ammonia processing units (metric tons).

ECO2k = Annual CO2emissions from each ammonia processing unit (metric tons). k = Processing unit. n = Total number of ammonia processing units.

(6) If applicable, ammonia manufacturing facilities that utilize the waste recycle stream as a fuel must calculate emissions associated with the waste stream for each ammonia process unit according to

Equation G-6 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.039

Where:

CO2= Annual CO2contained in waste recycle stream (metric tons).

RecycleStreamn= Volume of the waste recycle stream in month n (scf).

CCn= Carbon content of the waste recycle stream, for month n (kg C per kg of waste recycle stream) determined according to 98.74(f).

MW = Molecular weight of the waste recycle stream (kg/kg-mole).

(c) If GHG emissions from an ammonia manufacturing unit are vented through the same stack as any combustion unit or process equipment that reports CO2emissions using a CEMS that complies with the

Tier 4 Calculation Methodology in subpart C of this part (General

Stationary Fuel Combustion Sources), then the calculation methodology in paragraph (b) of this section shall not be used to calculate process emissions. The owner or operator shall report under this subpart the combined stack emissions according to the Tier 4 Calculation

Methodology in Sec. 98.33(a)(4) and all associated requirements for

Tier 4 in subpart C of this part.

Sec. 98.74 Monitoring and QA/QC requirements.

(a) You must continuously measure the quantity of gaseous or liquid feedstock consumed using a flow meter. The quantity of solid feedstock consumed can be obtained from company records and aggregated on a monthly basis.

(b) You must document the procedures used to ensure the accuracy of the estimates of feedstock consumption.

(c) You must determine monthly carbon contents and the average molecular weight of each feedstock consumed from reports from your supplier. As an alternative to using supplier information on carbon

Page 56419

contents, you can also collect a sample of each feedstock on a monthly basis and analyze the carbon content and molecular weight of the fuel using any of the following methods listed in paragraphs (c)(1) through

(c)(8) of this section, as applicable.

(1) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see Sec. 98.7).

(2) ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference, see

Sec. 98.7).

(3) ASTM D2502-04 (Reapproved 2002) Standard Test Method for

Estimation of Mean Relative Molecular Mass of Petroleum Oils from

Viscosity Measurements (incorporated by reference, see Sec. 98.7).

(4) ASTM D2503-92 (Reapproved 2007) Standard Test Method for

Relative Molecular Mass (Molecular Weight) of Hydrocarbons by

Thermoelectric Measurement of Vapor Pressure (incorporated by reference, see Sec. 98.7).

(5) ASTM D3238-95 (Reapproved 2005) Standard Test Method for

Calculation of Carbon Distribution and Structural Group Analysis of

Petroleum Oils by the n-d-M Method (incorporated by reference, see

Sec. 98.7).

(6) ASTM D5291-02 (Reapproved 2007) Standard Test Methods for

Instrumental Determination of Carbon, Hydrogen, and Nitrogen in

Petroleum Products and Lubricants (incorporated by reference, see Sec. 98.7).

(7) ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate

Analysis of Coal and Coke (incorporated by reference, see Sec. 98.7).

(8) ASTM D5373-08 Standard Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal

(incorporated by reference, see Sec. 98.7).

(d) Calibrate all oil and gas flow meters (except for gas billing meters) and perform oil tank measurements according to the monitoring and QA/QC requirements for the Tier 3 methodology in Sec. 98.34(b).

(e) For quality assurance and quality control of the supplier data, on an annual basis, you must measure the carbon contents of a representative sample of the feedstocks consumed using the appropriate

ASTM Method as listed in paragraphs (c)(1) through (c)(8) of this section.

(f) Facilities must continuously measure the quantity of waste gas recycled using a flow meter, as applicable. You must determine the carbon content and the molecular weight of the waste recycle stream by collecting a sample of each waste recycle stream on a monthly basis and analyzing the carbon content using the appropriate ASTM Method as listed in paragraphs (c)(1) through (c)(8) of this section.

(g) If CO2from ammonia production is used to produce urea at the same facility, you must determine the quantity of urea produced using methods or plant instruments used for accounting purposes (such as sales records). You must document the procedures used to ensure the accuracy of the estimates of urea produced.

Sec. 98.75 Procedures for estimating missing data.

A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever the monitoring and quality assurance procedures in Sec. 98.74 cannot be followed

(e.g., if a meter malfunctions during unit operation), a substitute data value for the missing parameter shall be used in the calculations following paragraphs (a) and (b) of this section. You must document and keep records of the procedures used for all such estimates.

(a) For missing data on monthly carbon contents of feedstock or the waste recycle stream, the substitute data value shall be the arithmetic average of the quality-assured values of that carbon content in the month preceding and the month immediately following the missing data incident. If no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality- assured value for carbon content obtained in the month after the missing data period.

(b) For missing feedstock supply rates or waste recycle stream used to determine monthly feedstock consumption or monthly waste recycle stream quantity, you must determine the best available estimate(s) of the parameter(s), based on all available process data.

Sec. 98.76 Data reporting requirements.

In addition to the information required by Sec. 98.3(c), each annual report must contain the information specified in paragraphs (a) and (b) of this section, as applicable for each ammonia manufacturing process unit.

(a) If a CEMS is used to measure CO2emissions, then you must report the relevant information required under Sec. 98.37(e)(2)(vi) for the Tier 4 Calculation Methodology and the following information in this paragraph (a):

(1) Annual quantity of each type of feedstock consumed for ammonia manufacturing (scf of feedstock or gallons of feedstock or kg of feedstock).

(2) Method used for determining quantity of feedstock used.

(b) If a CEMS is not used to measure emissions, then you must report the following information:

(1) Annual CO2process emissions (metric tons) for each ammonia manufacturing process unit.

(2) Monthly quantity of each type of feedstock consumed for ammonia manufacturing for each ammonia processing unit (scf of feedstock or gallons of feedstock or kg of feedstock).

(3) Method used for determining quantity of monthly feedstock used.

(4) Whether carbon content for each feedstock for month n is based on reports from the supplier or analysis of carbon content.

(5) If carbon content of feedstock for month n is based on analysis, the test method used.

(6) Sampling analysis results of carbon content of petroleum coke as determined for QA/QC of supplier data under Sec. 98.74(e).

(7) If a facility uses gaseous feedstock, the carbon content of the gaseous feedstock, for month n, (kg C per kg of feedstock).

(8) If a facility uses gaseous feedstock, the molecular weight of the gaseous feedstock (kg/kg-mole).

(9) If a facility uses gaseous feedstock, the molar volume conversion factor of the gaseous feedstock (scf per kg-mole).

(10) If a facility uses liquid feedstock, the carbon content of the liquid feedstock, for month n, (kg C per gallon of feedstock).

(11) If a facility uses solid feedstock, the carbon content of the solid feedstock, for month n, (kg C per kg of feedstock).

(12) Annual CO2emissions associated with the waste recycle stream for each ammonia process unit (metric tons)

(13) Carbon content of the waste recycle stream for month n for each ammonia process unit (kg C per kg of waste recycle stream).

(14) Volume of the waste recycle stream for month n for each ammonia process unit (scf)

(15) Method used for analyzing carbon content of waste recycle stream.

(16) Annual urea production (metric tons) and method used to determine urea production.

(17) Uses of urea produced, if known, such as but not limited to fertilizer, animal feed, manufacturing of plastics or resins, and pollution control technologies.

Page 56420

Sec. 98.77 Records that must be retained.

In addition to the records required by Sec. 98.3(g), you must retain the following records specified in paragraphs (a) and (b) of this section for each ammonia manufacturing unit.

(a) If a CEMS is used to measure emissions, retain records of all feedstock purchases in addition to the requirements in Sec. 98.37 for the Tier 4 Calculation Methodology.

(b) If a CEMS is not used to measure process CO2 emissions, you must also retain the records specified in paragraphs

(b)(1) through (b)(2) of this section:

(1) Records of all analyses and calculations conducted for reported data as listed in Sec. 98.76(b).

(2) Monthly records of carbon content of feedstock from supplier and/or all analyses conducted of carbon content.

Sec. 98.78 Definitions.

All terms used in this subpart have the same meaning given in the

Clean Air Act and subpart A of this part.

Subpart H--Cement Production

Sec. 98.80 Definition of the source category.

The cement production source category consists of each kiln and each in-line kiln/raw mill at any portland cement manufacturing facility including alkali bypasses, and includes kilns and in-line kiln/raw mills that burn hazardous waste.

Sec. 98.81 Reporting threshold.

You must report GHG emissions under this subpart if your facility contains a cement production process and the facility meets the requirements of either Sec. 98.2(a)(1) or (2).

Sec. 98.82 GHGs to report.

You must report:

(a) CO2process emissions from calcination in each kiln.

(b) CO2combustion emissions from each kiln.

C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.

(d) CO2, CH4, and N2O emissions from each stationary combustion unit other than kilns. You must report these emissions under subpart C of this part (General Stationary Fuel

Combustion Sources) by following the requirements of subpart C.

Sec. 98.83 Calculating GHG emissions.

You must calculate and report the annual process CO2 emissions from each kiln using the procedure in paragraphs (a) and (b) of this section.

(a) For each cement kiln that meets the conditions specified in

Sec. 98.33(b)(4)(ii) or (b)(4)(iii), you must calculate and report under this subpart the combined process and combustion CO2 emissions by operating and maintaining a CEMS to measure CO2 emissions according to the Tier 4 Calculation Methodology specified in

Sec. 98.33(a)(4) and all associated requirements for Tier 4 in subpart

C of this part (General Stationary Fuel Combustion Sources).

(b) For each kiln that is not subject to the requirements in paragraph (a) of this section, calculate and report the process and combustion CO2emissions from the kiln by using the procedure in either paragraph (c) or (d) of this section.

(c) Calculate and report under this subpart the combined process and combustion CO2emissions by operating and maintaining a

CEMS to measure CO2emissions according to the Tier 4

Calculation Methodology specified in Sec. 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General

Stationary Fuel Combustion Sources).

(d) Calculate and report process and combustion CO2 emissions separately using the procedures specified in paragraphs

(d)(1) through (d)(4) of this section.

(1) Calculate CO2process emissions from all kilns at the facility using Equation H-1 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.040

Where:

CO2 CMF= Annual process emissions of CO2from cement manufacturing, metric tons.

CO2 Cli,m= Total annual emissions of CO2from clinker production from kiln m, metric tons.

CO2 rm= Total annual emissions of CO2from raw materials, metric tons. k = Total number of kilns at a cement manufacturing facility.

(2) CO2emissions from clinker production. Calculate

CO2emissions from each kiln using Equations H-2 through H-5 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.041

Where:

Cli,j= Quantity of clinker produced in month j from kiln m, tons.

EFCli,j= Kiln specific clinker emission factor for month j for kiln m, metric tons CO2/metric ton clinker computed as specified in Equation H-3 of this section.

CKD,i= Cement kiln dust (CKD) not recycled to the kiln in quarter i from kiln m, tons.

EFCKD,i= Kiln specific CKD emission factor for quarter i from kiln m, metric tons CO2/metric ton CKD computed as specified in Equation H-4 of this section. p = Number of months for clinker calculation, 12. r = Number of quarters for CKD calculation, 4. 2000/2205 = Conversion factor to convert tons to metric tons.

(i) Kiln-Specific Clinker Emission Factor. (A) Calculate the kiln- specific clinker emission factor using Equation H-3 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.042

Page 56421

Where:

CliCaO= Monthly total CaO content of Clinker, wt- fraction.

ClincCaO= Monthly non-calcined CaO content of Clinker, wt-fraction.

MRCaO= Molecular-weight Ratio of CO2/CaO = 0.785.

CliMgO= Monthly total MgO content of Clinker, wt- fraction.

ClincMgO= Monthly non-calcined MgO content of Clinker, wt-fraction.

MRMgO= Molecular-weight Ratio of CO2/MgO = 1.092.

(B) Non-calcined CaO is CaO that remains in the clinker in the form of CaCO3and CaO in the clinker that entered the kiln as a non-carbonate species. Non-calcined MgO is MgO that remains in the clinker in the form of MgCO3and MgO in the clinker that entered the kiln as a non-carbonate species.

(ii) Kiln-Specific CKD Emission Factor. (A) Calculate the kiln- specific CKD emission factor for CKD not recycled to the kiln using

Equation H-4 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.043

Where:

CKDCaO= Quarterly total CaO content of CKD not recycled to the kiln, wt-fraction.

CKDCaO= Quarterly non-calcined CaO content of CKD not recycled to the kiln, wt-fraction.

MRCaO= Molecular-weight Ratio of CO2/CaO = 0.785.

CKDMgO= Quarterly total MgO content of CKD not recycled to the kiln, wt-fraction.

CKDMgO= Quarterly non-calcined MgO content of CKD not recycled to the kiln, wt-fraction.

MRMgO= Molecular-weight Ratio of CO2/MgO = 1.092.

(B) Non-calcined CaO is CaO that remains in the CKD in the form of

CaCO3and CaO in the CKD that entered the kiln as a non- carbonate species. Non-calcined MgO is MgO that remains in the CKD in the form of MgCO3and MgO in the CKD that entered the kiln as a non-carbonate species.

(3) CO2emissions from raw materials. Calculate

CO2emissions using Equation H-5 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.044

Where: rm = The amount of raw material i consumed annually, tons/yr (dry basis).

CO2,rm= Annual CO2emissions from raw materials.

TOCrm = Organic carbon content of raw material i (dry basis), as determined in Sec. 98.84(c) or using a default factor of 0.2 percent of total raw material weight.

M = Number of raw materials. 44/12 = Ratio of molecular weights, CO2to carbon. 2000/2205 = Conversion factor to convert tons to metric tons.

(4) Calculate and report under subpart C of this part (General

Stationary Fuel Combustion Sources) the combustion CO2 emissions from the kiln according to the applicable requirements in subpart C.

Sec. 98.84 Monitoring and QA/QC requirements.

(a) You must determine the weight fraction of total CaO and total

MgO in CKD not recycled to the kiln from each kiln using ASTM C114-09,

Standard Test Methods for Chemical Analysis of Hydraulic Cement

(incoporated by reference, see Sec. 98.7). The monitoring must be conducted quarterly for each kiln from a CKD sample drawn either as CKD is exiting the kiln or from bulk CKD storage.

(b) You must determine the weight fraction of total CaO and total

MgO in clinker from each kiln using ASTM C114-07 Standard Test Methods for Chemical Analysis of Hydraulic Cement (incorporated by reference, see Sec. 98.7). The monitoring must be conducted monthly for each kiln from a clinker sample drawn from bulk clinker storage.

(c) The total organic carbon contents (dry basis) of each raw material must be determined annually using ASTM C114-09 Standard Test

Methods for Chemical Analysis of Hydraulic Cement (incorporated by reference, see Sec. 98.7) or a similar industry standard practice or method approved for total organic carbon determination in raw mineral materials. The analysis must be conducted on sample material drawn from bulk raw material storage for each category of raw material (i.e., limestone, sand, shale, iron oxide, and alumina). Facilities that opt to use the default total organic carbon factor provided in Sec. 98.83(d)(3), are not required to monitor for TOC.

(d) The quantity of clinker produced monthly by each kiln must be determined by direct weight measurement using the same plant instruments used for accounting purposes, such as weigh hoppers or belt weigh feeders.

(e) The quantity of CKD not recycled to the kiln by each kiln must be determined quarterly by direct weight measurement using the same plant instruments used for accounting purposes, such as weigh hoppers, truck weigh scales, or belt weigh feeders.

(f) The quantity of each category of raw materials consumed annually by the facility (e.g., limestone, sand, shale, iron oxide, and alumina) must be determined monthly by direct weight measurement using the same plant instruments used for accounting purposes, such as weigh hoppers, truck weigh scales, or belt weigh feeders.

(g) The monthly non-calcined CaO and MgO that remains in the clinker in the form of CaCO3or that enters the kiln as a non-carbonate species may be assumed to be a default value of 0.0 or may be determined monthly by careful chemical analysis of feed material and clinker material from each kiln using well documented analytical and calculational methods or the appropriate industry standard practice.

(h) The quarterly non-calcined CaO and MgO that remains in the CKD in the form of CaCO3or that enters the kiln as a non- carbonate species may be assumed to be a default value of 0.0 or may be determined quarterly by careful chemical analysis of feed material and

CKD material from each kiln using well documented analytical and calculational methods or the appropriate industry standard practice.

Sec. 98.85 Procedures for estimating missing data.

A complete record of all measured parameters used in the GHG emissions calculations in Sec. 98.83 is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for

Page 56422

the missing parameter shall be used in the calculations. The owner or operator must document and keep records of the procedures used for all such estimates.

(a) If the CEMS approach is used to determine combined process and combustion CO2emissions, the missing data procedures in

Sec. 98.35 apply.

(b) For CO2process emissions from cement manufacturing facilities calculated according to Sec. 98.83(d), if data on the carbonate content (of clinker or CKD), noncalcined content (of clinker or CKD) or the annual organic carbon content of raw materials are missing, facilities must undertake a new analysis.

(c) For each missing value of monthly clinker production the substitute data value must be the best available estimate of the monthly clinker production based on information used for accounting purposes, or use the maximum tons per day capacity of the system and the number of days per month.

(d) For each missing value of monthly raw material consumption the substitute data value must be the best available estimate of the monthly raw material consumption based on information used for accounting purposes (such as purchase records), or use the maximum tons per day raw material throughput of the kiln and the number of days per month.

Sec. 98.86 Data reporting requirements.

In addition to the information required by Sec. 98.3(c), each annual report must contain the information specified in paragraphs (a) and (b) of this section, as appropriate.

(a) If a CEMS is used to measure CO2emissions, then you must report under this subpart the relevant information required by

Sec. 98.36(e)(2)(vi) and the information listed in this paragraph(a):

(1) Monthly clinker production from each kiln at the facility.

(2) Monthly cement production from each kiln at the facility.

(3) Number of kilns and number of operating kilns.

(b) If a CEMS is not used to measure CO2emissions, then you must report the information listed in this paragraph (b) for each kiln:

(1) Kiln identification number.

(2) Monthly clinker production from each kiln.

(3) Monthly cement production from each kiln.

(4) Number of kilns and number of operating kilns.

(5) Quarterly quantity of CKD not recycled to the kiln for each kiln at the facility.

(6) Monthly fraction of total CaO, total MgO, non-calcined CaO and non-calcined MgO in clinker for each kiln (as wt-fractions).

(7) Method used to determine non-calcined CaO and non-calcined MgO in clinker.

(8) Quarterly fraction of total CaO, total MgO, non-calcined CaO and non-calcined MgO in CKD not recycled to the kiln for each kiln (as wt-fractions).

(9) Method used to determine non-calcined CaO and non-calcined MgO in CKD.

(10) Monthly kiln-specific clinker CO2emission factors for each kiln (metric tons CO2/metric ton clinker produced).

(11) Quarterly kiln-specific CKD CO2emission factors for each kiln (metric tons CO2/metric ton CKD produced).

(12) Annual organic carbon content of each raw material (wt- fraction, dry basis).

(13) Annual consumption of each raw material (dry basis).

(14) Number of times missing data procedures were used to determine the following information:

(i) Clinker production (number of months).

(ii) Carbonate contents of clinker (number of months).

(iii) Non-calcined content of clinker (number of months).

(iv) CKD not recycled to kiln (number of quarters).

(v) Non-calcined content of CKD (number of quarters)

(vi) Organic carbon contents of raw materials (number of times).

(vii) Raw material consumption (number of months).

Sec. 98.87 Records that must be retained.

(a) If a CEMS is used to measure CO2emissions, then you must retain under this subpart the records required for the Tier 4

Calculation Methodology in Sec. 98.37.

(1) Documentation of monthly calculated kiln-specific clinker

CO2emission factor.

(2) Documentation of quarterly calculated kiln-specific CKD

CO2emission factor.

(3) Measurements, records and calculations used to determine reported parameters.

(b) If a CEMS is not used to measure CO2emissions, then in addition to the records required by Sec. 98.3(g), you must retain the records specified in paragraphs (a) through (b) of this section for each portland cement manufacturing facility.

Sec. 98.88 Definitions.

All terms used in this subpart have the same meaning given in the

Clean Air Act and subpart A of this part.

Subpart I--[Reserved]

Subpart J--[Reserved]

Subpart K--Ferroalloy Production

Sec. 98.110 Definition of the source category.

The ferroalloy production source category consists of any facility that uses pyrometallurgical techniques to produce any of the following metals: ferrochromium, ferromanganese, ferromolybdenum, ferronickel, ferrosilicon, ferrotitanium, ferrotungsten, ferrovanadium, silicomanganese, or silicon metal.

Sec. 98.111 Reporting threshold.

You must report GHG emissions under this subpart if your facility contains a ferroalloy production process and the facility meets the requirements of either Sec. 98.2(a)(1) or (2).

Sec. 98.112 GHGs to report.

You must report:

(a) Process CO2emissions from each electric arc furnace

(EAF) used for the production of any ferroalloy listed in Sec. 98.110.

(b) CO2, CH4, and N2O emissions from each stationary combustion unit following the requirements of subpart C of this part. You must report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources).

Sec. 98.113 Calculating GHG emissions.

You must calculate and report the annual process CO2 emissions from each EAF using the procedures in either paragraph (a) or

(b) of this section.

(a) Calculate and report under this subpart the process

CO2emissions by operating and maintaining CEMS according to the Tier 4 Calculation Methodology in Sec. 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General

Stationary Fuel Combustion Sources).

(b) Calculate and report under this subpart the annual process

CO2emissions using the procedure in either paragraph (b)(1) or (b)(2) of this section.

(1) Calculate and report under this subpart the annual process

CO2emissions from EAFs by operating and maintaining a CEMS according to the Tier 4 Calculation Methodology specified in Sec. 98.33(a)(4) and the applicable requirements for Tier 4 in subpart C of this part (General Stationary Fuel Combustion Sources).

(2) Calculate and report under this subpart the annual process

CO2emissions from the EAFs using the carbon mass balance procedure specified in paragraphs (b)(2)(i) and (b)(2)(ii) of this section.

Page 56423

(i) For each EAF, determine the annual mass of carbon in each carbon-containing input and output material for the EAF and estimate annual process CO2emissions from the EAF using Equation K-1 of this section. Carbon-containing input materials include carbon electrodes and carbonaceous reducing agents. If you document that a specific input or output material contributes less than 1 percent of the total carbon into or out of the process, you do not have to include the material in your calculation using Equation K-1 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.045

Where:

ECO2= Annual process CO2emissions from an individual EAF (metric tons). 44/12 = Ratio of molecular weights, CO2to carbon. 2000/2205 = Conversion factor to convert tons to metric tons.

Mreducing agenti = Annual mass of reducing agent i fed, charged, or otherwise introduced into the EAF (tons).

Creducing agenti = Carbon content in reducing agent i

(percent by weight, expressed as a decimal fraction).

Melectrodem = Annual mass of carbon electrode m consumed in the EAF (tons).

Celectrodem = Carbon content of the carbon electrode m

(percent by weight, expressed as a decimal fraction).

Moreh = Annual mass of ore h charged to the EAF (tons).

Coreh = Carbon content in ore h (percent by weight, expressed as a decimal fraction).

Mfluxj = Annual mass of flux material j fed, charged, or otherwise introduced into the EAF to facilitate slag formation

(tons).

Cfluxj = Carbon content in flux material j (percent by weight, expressed as a decimal fraction).

Mproductk = Annual mass of alloy product k tapped from

EAF (tons).

Cproductk = Carbon content in alloy product k. (percent by weight, expressed as a decimal fraction).

Mnon-product outgoingl = Annual mass of non-product outgoing material l removed from EAF (tons).

Cnon-product outgoingl = Carbon content in non-product outgoing material l (percent by weight, expressed as a decimal fraction).

(ii) Determine the combined annual process CO2emissions from the EAFs at your facility using Equation K-2 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.046

Where:

CO2= Annual process CO2emissions from EAFs at facility used for the production of any ferroalloy listed in

Sec. 98.110 (metric tons).

ECO2k = Annual process CO2emissions calculated from EAF k calculated using Equation K-1 of this section

(metric tons). k = Total number of EAFs at facility used for the production of any ferroalloy listed in Sec. 98.110.

(c) If GHG emissions from an EAF are vented through the same stack as any combustion unit or process equipment that reports CO2 emissions using a CEMS that complies with the Tier 4 Calculation

Methodology in subpart C of this part (General Stationary Fuel

Combustion Sources), then the calculation methodology in paragraph (b) of this section shall not be used to calculate process emissions. The owner or operator shall report under this subpart the combined stack emissions according to the Tier 4 Calculation Methodology in Sec. 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part.

(d) For the EAFs at your facility used for the production of any ferroalloy listed in Table K-1 of this subpart, you must calculate and report the annual CH4emissions using the procedure specified in paragraphs (d)(1) and (2) of this section.

(1) For each EAF, determine the annual CH4emissions using Equation K-3 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.047

Where:

ECH4= Annual process CH4emissions from an individual EAF (metric tons).

Mproducti = Annual mass of alloy product i produced in the EAF (tons). 2000/2205 = Conversion factor to convert tons to metric tons.

Page 56424

EFproducti = CH4emission factor for alloy product i from Table K-1 in this subpart (kg of CH4 emissions per metric ton of alloy product i).

(2) Determine the combined process CH4emissions from the EAFs at your facility using Equation K-4 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.048

Where:

CH4= Annual process CH4emissions from EAFs at facility used for the production of ferroalloys listed in Table

K-1 of this subpart (metric tons).

ECH4j = Annual process CH4emissions from EAF j calculated using Equation K-3 of this section (metric tons). j = Total number of EAFs at facility used for the production of ferroalloys listed in Table K-1 of this subpart.

Sec. 98.114 Monitoring and QA/QC requirements.

If you determine annual process CO2emissions using the carbon mass balance procedure in Sec. 98.113(b)(2), you must meet the requirements specified in paragraphs (a) and (b) of this section.

(a) Determine the annual mass for each material used for the calculations of annual process CO2emissions using Equation

K-1 of this subpart by summing the monthly mass for the material determined for each month of the calendar year. The monthly mass may be determined using plant instruments used for accounting purposes, including either direct measurement of the quantity of the material placed in the unit or by calculations using process operating information.

(b) For each material identified in paragraph (a) of this section, you must determine the average carbon content of the material consumed, used, or produced in the calendar year using the methods specified in either paragraph (b)(1) or (b)(2) of this section. If you document that a specific process input or output contributes less than one percent of the total mass of carbon into or out of the process, you do not have to determine the monthly mass or annual carbon content of that input or output.

(1) Information provided by your material supplier.

(2) Collecting and analyzing at least three representative samples of the material inputs and outputs each year. The carbon content of the material must be analyzed at least annually using the standard methods

(and their QA/QC procedures) specified in paragraphs (b)(2)(i) through

(b)(2)(iii) of this section, as applicable.

(i) ASTM E1941-04, Standard Test Method for Determination of Carbon in Refractory and Reactive Metals and Their Alloys (incorporated by reference, see Sec. 98.7) for analysis of metal ore and alloy product.

(ii) ASTM D5373-08 Standard Test Methods for Instrumental

Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see Sec. 98.7), for analysis of carbonaceous reducing agents and carbon electrodes.

(iii) ASTM C25-06, Standard Test Methods for Chemical Analysis of

Limestone, Quicklime, and Hydrated Lime (incorporated by reference, see

Sec. 98.7) for analysis of flux materials such as limestone or dolomite.

Sec. 98.115 Procedures for estimating missing data.

A complete record of all measured parameters used in the GHG emissions calculations in Sec. 98.113 is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in the paragraphs (a) and (b) of this section. You must document and keep records of the procedures used for all such estimates.

(a) If you determine CO2emissions for the EAFs at your facility using the carbon mass balance procedure in Sec. 98.113(b), 100 percent data availability is required for the carbon content of the input and output materials. You must repeat the test for average carbon contents of inputs according to the procedures in Sec. 98.114(b) if data are missing.

(b) For missing records of the monthly mass of carbon-containing inputs and outputs, the substitute data value must be based on the best available estimate of the mass of the inputs and outputs from on all available process data or data used for accounting purposes, such as purchase records.

(c) If you are required to calculate CH4emissions for an EAF at your facility as specified in Sec. 98.113(d), the estimate is based an annual quantity of certain alloy products, so 100 percent data availability is required.

Sec. 98.116 Data reporting requirements.

In addition to the information required by Sec. 98.3(c), each annual report must contain the information specified in paragraphs (a) through (e) of this section, as applicable:

(a) Annual facility ferroalloy product production capacity (tons).

(b) Annual production for each ferroalloy product (tons) identified in Sec. 98.110, as applicable.

(c) Total number of EAFs at facility used for production of ferroalloy products reported in paragraph (a)(4) of this section.

(d) If a CEMS is used to measure CO2emissions, then you must report under this subpart the relevant information required by

Sec. 98.37 for the Tier 4 Calculation Methodology and the following information specified in paragraphs (d)(1) through (d)(3) of this section.

(1) Annual process CO2emissions (in metric tons) from each EAF used for the production of any ferroalloy listed in Table K-1 of this subpart (metric tons).

(2) Annual process CH4emissions (in metric tons) from each EAF used for the production of any ferroalloy listed in Table K-1 of this subpart (metric tons).

(3) Identification number of each EAF.

(e) If a CEMS is not used to measure CO2process emissions, and the carbon mass balance procedure is used to determine

CO2emissions according to the requirements in Sec. 98.113(b), then you must report the following information specified in paragraphs (e)(1) through (e)(7) of this section.

(1) Annual process CO2emissions (in metric tons) from each EAF used for the production of any ferroalloy listed in Table K-1 of this subpart (metric tons).

(3) Identification number for each material.

(4) Annual material quantity for each material included for the calculation of annual process CO2emissions for each EAF.

(5) Annual average of the carbon content determinations for each material included for the calculation of annual process CO2 emissions for each EAF (percent by weight, expressed as a decimal fraction).

(6) List the method used for the determination of carbon content for each material reported in paragraph (e)(5) of this section (e.g., supplier provided information, analyses of representative samples you collected).

(7) If you use the missing data procedures in Sec. 98.115(b), you must report how monthly mass of carbon-containing inputs and outputs with missing data was determined and the number of months the missing data procedures were used.

Sec. 98.117 Records that must be retained.

In addition to the records required by Sec. 98.3(g), you must retain the records specified in paragraphs (a) through (d) of this section for each EAF, as applicable.

(a) If a CEMS is used to measure CO2emissions according to the requirements in Sec. 98.113(a), then you must retain under this subpart the records required

Page 56425

for the Tier 4 Calculation Methodology in Sec. 98.37 and the information specified in paragraphs (a)(1) through (a)(3) of this section.

(1) Monthly EAF production quantity for each ferroalloy product

(tons).

(2) Number of EAF operating hours each month.

(3) Number of EAF operating hours in a calendar year.

(b) If the carbon mass balance procedure is used to determine

CO2emissions according to the requirements in Sec. 98.113(b)(2), then you must retain records for the information specified in paragraphs (b)(1) through (b)(5) of this section.

(1) Monthly EAF production quantity for each ferroalloy product

(tons).

(2) Number of EAF operating hours each month.

(3) Number of EAF operating hours in a calendar year.

(4) Monthly material quantity consumed, used, or produced for each material included for the calculations of annual process CO2 emissions (tons).

(5) Average carbon content determined and records of the supplier provided information or analyses used for the determination for each material included for the calculations of annual process CO2 emissions.

(c) You must keep records that include a detailed explanation of how company records of measurements are used to estimate the carbon input and output to each EAF, including documentation of specific input or output materials excluded from Equation K-1 of this subpart that contribute less than 1 percent of the total carbon into or out of the process. You also must document the procedures used to ensure the accuracy of the measurements of materials fed, charged, or placed in an

EAF including, but not limited to, calibration of weighing equipment and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided.

(d) If you are required to calculate CH4emissions for the EAF as specified in Sec. 98.113(d), you must maintain records of the total amount of each alloy product produced for the specified reporting period, and the appropriate alloy-product specific emission factor used to calculate the CH4emissions.

Sec. 98.118 Definitions.

All terms used of this subpart have the same meaning given in the

Clean Air Act and subpart A of this part.

Table K-1 to Subpart K of Part 98--Electric Arc Furnace (EAF) CH4

Emission Factors

CH4 emission factor (kg CH4 per metric ton product)

EAF Operation

Alloy product produced in EAF --------------------------------------

Sprinkle-

Batch-

Sprinkle-

charging charging

charging

and >750

\a\

degC \b\

Silicon metal....................

1.5

1.2

0.7

Ferrosilicon 90%.................

1.4

1.1

0.6

Ferrosilicon 75%.................

1.3

1.0

0.5

Ferrosilicon 65%.................

1.3

1.0

0.5

\a\ Sprinkle-charging is charging intermittently every minute.

\b\ Temperature measured in off-gas channel downstream of the furnace hood.

Subpart L--[Reserved]

Subpart M--[Reserved]

Subpart N--Glass Production

Sec. 98.140 Definition of the source category.

(a) A glass manufacturing facility manufactures flat glass, container glass, pressed and blown glass, or wool fiberglass by melting a mixture of raw materials to produce molten glass and form the molten glass into sheets, containers, fibers, or other shapes. A glass manufacturing facility uses one or more continuous glass melting furnaces to produce glass.

(b) A glass melting furnace that is an experimental furnace or a research and development process unit is not subject to this subpart.

Sec. 98.141 Reporting threshold.

You must report GHG emissions under this subpart if your facility contains a glass production process and the facility meets the requirements of either Sec. 98.2(a)(1) or (2).

Sec. 98.142 GHGs to report.

You must report:

(a) CO2process emissions from each continuous glass melting furnace.

(b) CO2combustion emissions from each continuous glass melting furnace.

(c) CH4and N2O combustion emissions from each continuous glass melting furnace. You must calculate and report these emissions under subpart C of this part (General Stationary Fuel

Combustion Sources) by following the requirements of subpart C.

(d) CO2, CH4, and N2O emissions from each stationary fuel combustion unit other than continuous glass melting furnaces. You must report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.

Sec. 98.143 Calculating GHG emissions.

You must calculate and report the annual process CO2 emissions from each continuous glass melting furnace using the procedure in paragraphs (a) and (b) of this section.

(a) For each continuous glass melting furnace that meets the conditions specified in Sec. 98.33(b)(4)(ii) or (iii), you must calculate and report under this subpart the combined process and combustion CO2emissions by operating and maintaining a CEMS to measure CO2emissions according to the Tier 4 Calculation

Methodology specified in Sec. 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary

Fuel Combustion Sources).

(b) For each continuous glass melting furnace that is not subject to the requirements in paragraph (a) of this section, calculate and report the process and combustion CO2emissions from the glass melting furnace by using either the procedure in paragraph (b)(1) of this section or the procedure in paragraphs (b)(2) through (b)(7) of this section, except as specified in paragraph (c) of this section.

(1) Calculate and report under this subpart the combined process and combustion CO2emissions by operating

Page 56426

and maintaining a CEMS to measure CO2emissions according to the Tier 4 Calculation Methodology specified in Sec. 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part

(General Stationary Fuel Combustion Sources).

(2) Calculate and report the process and combustion CO2 emissions separately using the procedures specified in paragraphs

(b)(2)(i) through (b)(2)(vi) of this section.

(i) For each carbonate-based raw material charged to the furnace, obtain from the supplier of the raw material the carbonate-based mineral mass fraction.

(ii) Determine the quantity of each carbonate-based raw material charged to the furnace.

(iii) Apply the appropriate emission factor for each carbonate- based raw material charged to the furnace, as shown in Table N-1 to this subpart.

(iv) Use Equation N-1 of this section to calculate process mass emissions of CO2for each furnace:

GRAPHIC

TIFF OMITTED TR30OC09.049

Where:

ECO2= Process emissions of CO2from the furnace (metric tons). n = Number of carbonate-based raw materials charged to furnace.

MFi= Annual average mass fraction of carbonate-based mineral i in carbonate-based raw material i (percentage, expressed as a decimal).

Mi= Annual amount of carbonate-based raw material i charged to furnace (tons). 2000/2205 = Conversion factor to convert tons to metric tons.

EFi= Emission factor for carbonate-based raw material i

(metric ton CO2per metric ton carbonate-based raw material as shown in Table N-1 to this subpart).

Fi= Fraction of calcination achieved for carbonate-based raw material i, assumed to be equal to 1.0 (percentage, expressed as a decimal).

(v) You must calculate the total process CO2emissions from continuous glass melting furnaces at the facility using Equation

N-2 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.050

Where:

CO2= Annual process CO2emissions from glass manufacturing facility (metric tons).

ECO2i= Annual CO2emissions from glass melting furnace i (metric tons). k = Number of continuous glass melting furnaces.

(vi) Calculate and report under subpart C of this part (General

Stationary Fuel Combustion Sources) the combustion CO2 emissions in the glass furnace according to the applicable requirements in subpart C.

(MFi) of carbonate-based mineral i in Equation N-1 of this section.

Sec. 98.144 Monitoring and QA/QC requirements.

(a) You must measure annual amounts of carbonate-based raw materials charged to each continuous glass melting furnace from monthly measurements using plant instruments used for accounting purposes, such as calibrated scales or weigh hoppers. Total annual mass charged to glass melting furnaces at the facility shall be compared to records of raw material purchases for the year.

(b) You must measure carbonate-based mineral mass fractions at least annually to verify the mass fraction data provided by the supplier of the raw material; such measurements shall be based on sampling and chemical analysis conducted by a certified laboratory using ASTM D3682-01 (Reapproved 2006) Standard Test Method for Major and Minor Elements in Combustion Residues from Coal Utilization

Processes (incorporated by reference, see Sec. 98.7).

(c) You must determine the annual average mass fraction for the carbonate-based mineral in each carbonate-based raw material by calculating an arithmetic average of the monthly data obtained from raw material suppliers or sampling and chemical analysis.

(d) You must determine on an annual basis the calcination fraction for each carbonate consumed based on sampling and chemical analysis using an industry consensus standard. This chemical analysis must be conducted using an x-ray fluorescence test or other enhanced testing method published by an industry consensus standards organization (e.g.,

ASTM, ASME, API, etc.).

Sec. 98.145 Procedures for estimating missing data.

A complete record of all measured parameters used in the GHG emissions calculations is required (e.g., carbonate raw materials consumed, etc.). If the monitoring and quality assurance procedures in

Sec. 98.144 cannot be followed and data is missing, you must use the most appropriate of the missing data procedures in paragraphs (a) and

(b) of this section. You must document and keep records of the procedures used for all such missing value estimates.

(a) For missing data on the monthly amounts of carbonate-based raw materials charged to any continuous glass melting furnace use the best available estimate(s) of the parameter(s), based on all available process data or data used for accounting purposes, such as purchase records.

(b) For missing data on the mass fractions of carbonate-based minerals in the carbonate-based raw materials assume that the mass fraction of each carbonate based mineral is 1.0.

Sec. 98.146 Data reporting requirements.

In addition to the information required by Sec. 98.3(c), each annual report must contain the information specified in paragraphs (a) and (b) of this section, as applicable.

(a) If a CEMS is used to measure CO2emissions, then you must report under this subpart the relevant information required under

Sec. 98.37 for the Tier 4 Calculation Methodology and the following information specified in paragraphs (a)(1) and (a)(2) of this section:

(1) Annual quantity of each carbonate-based raw material charged to each continuous glass melting furnace and for all furnaces combined

(tons).

(2) Annual quantity of glass produced (tons).

(b) If a CEMS is not used to determine CO2emissions from continuous glass melting furnaces, and process CO2 emissions are calculated according to the procedures specified in Sec. 98.143(b), then you must report the following information as specified in paragraphs (b)(1) through (b)(9) of this section:

(1) Annual process emissions of CO2(metric tons) for each continuous glass melting furnace and for all furnaces combined.

(2) Annual quantity of each carbonate-based raw material charged

(tons) to each continuous glass melting furnace and for all furnaces combined.

Page 56427

(3) Annual quantity of glass produced (tons) from each continuous glass melting furnace and from all furnaces combined.

(4) Carbonate-based mineral mass fraction (percentage, expressed as a decimal) for each carbonate-based raw material charged to a continuous glass melting furnace.

(5) Results of all tests used to verify the carbonate-based mineral mass fraction for each carbonate-based raw material charged to a continuous glass melting furnace, as specified in paragraphs (b)(5)(i) through (b)(5)(iii) of this section.

(i) Date of test.

(ii) Method(s) and any variations used in the analyses.

(iii) Mass fraction of each sample analyzed.

(6) The fraction of calcination achieved for each carbonate-based raw material, if a value other than 1.0 is used to calculate process mass emissions of CO2.

(7) Method used to determine fraction of calcination (percentage, expressed as a decimal).

(8) Total number of continuous glass melting furnaces.

(9) The number of times in the reporting year that missing data procedures were followed to measure monthly quantities of carbonate- based raw materials any continuous glass melting furnace or mass fraction of the carbonate-based minerals (months).

Sec. 98.147 Records that must be retained.

In addition to the information required by Sec. 98.3(g), you must retain the records listed in paragraphs (a), (b), and (c) of this section.

(a) If a CEMS is used to measure emissions, then you must retain the records required under Sec. 98.37 for the Tier 4 Calculation

Methodology and the following information specified in paragraphs

(a)(1) and (a)(2) of this section:

(1) Monthly glass production rate for each continuous glass melting furnace (tons).

(2) Monthly amount of each carbonate-based raw material charged to each continuous glass melting furnace (tons).

(b) If process CO2emissions are calculated according to the procedures specified in Sec. 98.143(b), you must retain the records in paragraphs (b)(1) through (b)(5) of this section.

(1) Monthly glass production rate for each continuous glass melting furnace (metric tons).

(2) Monthly amount of each carbonate-based raw material charged to each continuous glass melting furnace (metric tons).

(3) Data on carbonate-based mineral mass fractions provided by the raw material supplier for all raw materials consumed annually and included in calculating process emissions in Equation N-1 of this subpart.

(4) Results of all tests used to verify the carbonate-based mineral mass fraction for each carbonate-based raw material charged to a continuous glass melting furnace, including the data specified in paragraphs (b)(4)(i) through (b)(4)(v) of this section.

(i) Date of test.

(ii) Method(s), and any variations of the methods, used in the analyses.

(iii) Mass fraction of each sample analyzed.

(iv) Relevant calibration data for the instrument(s) used in the analyses.

(v) Name and address of laboratory that conducted the tests.

(5) The fraction of calcination achieved for each carbonate-based raw material (percentage, expressed as a decimal), if a value other than 1.0 is used to calculate process mass emissions of CO2.

Sec. 98.148 Definitions.

All terms used in this subpart have the same meaning given in the

Clean Air Act and subpart A of this part.

Table N-1 to Subpart N of Part 98--CO2 Emission Factors for Carbonate-

Based Raw Materials

CO2

Carbonate-based raw material--mineral

emission factor \a\

Limestone--CaCO3...........................................

0.440

Dolomite--CaMg(CO3)2.......................................

0.477

Sodium carbonate/soda ash--Na2CO3..........................

0.415

\a\ Emission factors in units of metric tons of CO2 emitted per metric ton of carbonate-based raw material charged to the furnace.

Subpart O--HCFC-22 Production and HFC-23 Destruction

Sec. 98.150 Definition of the source category.

The HCFC-22 production and HFC-23 destruction source category consists of HCFC-22 production processes and HFC-23 destruction processes.

(a) An HCFC-22 production process produces HCFC-22

(chlorodifluoromethane, or CHClF2) from chloroform

(CHCl3) and hydrogen fluoride (HF).

(b) An HFC-23 destruction process is any process in which HFC-23 undergoes destruction. An HFC-23 destruction process may or may not be co-located with an HCFC-22 production process at the same facility.

Sec. 98.151 Reporting threshold.

You must report GHG emissions under this subpart if your facility contains an HCFC-22 production or HFC-23 destruction process and the facility meets the requirements of either Sec. 98.2(a)(1) or (a)(2).

Sec. 98.152 GHGs to report.

(a) You must report under subpart C of this part (General

Stationary Fuel Combustion Sources) the emissions of CO2,

CH4, and N2O from each stationary combustion unit following the requirements of subpart C.

(b) You must report HFC-23 emissions from HCFC-22 production processes and HFC-23 destruction processes.

Sec. 98.153 Calculating GHG emissions.

(a) The mass of HFC-23 generated from each HCFC-22 production process shall be estimated by using one of two methods, as applicable:

(1) Where the mass flow of the combined stream of HFC-23 and another reaction product (e.g., HCl) is measured, multiply the weekly

(or more frequent) HFC-23 concentration measurement (which may be the average of more frequent concentration measurements) by the weekly (or more frequent) mass flow of the combined stream of HFC-23 and the other product. To estimate annual HFC-23 production, sum the weekly (or more frequent) estimates of the quantities of HFC-23 produced over the year.

This calculation is summarized in Equation O-1 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.051

Where:

G23= Mass of HFC-23 generated annually (metric tons). c23= Fraction HFC-23 by weight in HFC-23/other product stream.

Fp= Mass flow of HFC-23/other product stream during the period p (kg). p = Period over which mass flows and concentrations are measured. n = Number of concentration and flow measurement periods for the year. 10-3= Conversion factor from kilograms to metric tons.

(2) Where the mass of only a reaction product other than HFC-23

(either HCFC-22 or HCl) is measured, multiply the ratio of the weekly

(or more frequent) measurement of the HFC-23 concentration and the weekly (or more frequent) measurement of the other product concentration by the weekly (or more frequent) mass produced of the other product. To estimate annual HFC-23 production, sum the weekly (or more

Page 56428

frequent) estimates of the quantities of HFC-23 produced over the year.

This calculation is summarized in Equation O-2 of this section, assuming that the other product is HCFC-22. If the other product is

HCl, HCl may be substituted for HCFC-22 in Equations O-2 and O-3 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.052

Where:

G23= Mass of HFC-23 generated annually (metric tons). c23= Fraction HFC-23 by weight in HCFC-22/HFC-23 stream. c22= Fraction HCFC-22 by weight in HCFC-22/HFC-23 stream.

P22= Mass of HCFC-22 produced over the period p (kg), calculated using Equation O-3 of this section. p = Period over which masses and concentrations are measured. n = Number of concentration and mass measurement periods for the year. 10-3= Conversion factor from kilograms to metric tons.

(b) The mass of HCFC-22 produced over the period p shall be estimated by using Equation O-3 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.053

Where:

P22= Mass of HCFC-22 produced over the period p (kg).

O22= mass of HCFC-22 that is measured coming out of the

Production process over the period p (kg).

U22= Mass of used HCFC-22 that is added to the production process upstream of the output measurement over the period p (kg).

LF = Factor to account for the loss of HCFC-22 upstream of the measurement. The value for LF shall be determined pursuant to Sec. 98.154(e).

(c) For HCFC-22 production facilities that do not use a thermal oxidizer or that have a thermal oxidizer that is not directly connected to the HCFC-22 production equipment, HFC-23 emissions shall be estimated using Equation O-4 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.054

Where:

E23= Mass of HFC-23 emitted annually (metric tons).

G23= Mass of HFC-23 generated annually (metric tons).

S23= Mass of HFC-23 sent off site for sale annually

(metric tons).

OD23= Mass of HFC-23 sent off site for destruction

(metric tons).

D23= Mass of HFC-23 destroyed on site (metric tons).

I23= Increase in HFC-23 inventory = HFC-23 in storage at end of year--HFC-23 in storage at beginning of year (metric tons).

(d) For HCFC-22 production facilities that use a thermal oxidizer connected to the HCFC-22 production equipment, HFC-23 emissions shall be estimated using Equation O-5 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.055

Where:

E23= Mass of HFC-23 emitted annually (metric tons).

EL= Mass of HFC-23 emitted annually from equipment leaks, calculated using Equation O-6 of this section (metric tons).

EPV= Mass of HFC-23 emitted annually from process vents, calculated using Equation O-7 of this section (metric tons).

ED= Mass of HFC-23 emitted annually from thermal oxidizer (metric tons), calculated using Equation O-8 of this section.

(1) The mass of HFC-23 emitted annually from equipment leaks (for use in Equation O-5 of this section) shall be estimated by using

Equation O-6 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.056

Where:

EL= Mass of HFC-23 emitted annually from equipment leaks

(metric tons). c23= Fraction HFC-23 by weight in the stream(s) in the equipment.

FGt= The applicable leak rate specified in Table O-1 of this subpart for each source of equipment type and service t with a screening value greater than or equal to 10,000 ppmv (kg/hr/source).

NGt= The number of sources of equipment type and service t with screening values greater than or equal to 10,000 ppmv as determined according to Sec. 98.154(i).

FLt= The applicable leak rate specified in Table O-1 of this subpart for each source of equipment type and service t with a screening value of less than 10,000 ppmv (kg/hr/source).

NLt= The number of sources of equipment type and service t with screening values less than 10,000 ppmv as determined according to Sec. 98.154(j). p = One hour. n = Number of hours during the year during which equipment contained

HFC-23. t = Equipment type and service as specified in Table O-1 of this subpart . 10-3= Factor converting kg to metric tons.

(2) The mass of HFC-23 emitted annually from process vents (for use in Equation O-5 of this section) shall be estimated by using Equation

O-7 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.057

Where:

EPV= Mass of HFC-23 emitted annually from process vents

(metric tons).

ERT= The HFC-23 emission rate from the process vents during the period of the most recent test (kg/hr).

PRp= The HCFC-22 production rate during the period p

(kg/hr).

PRT= The HCFC-22 production rate during the most recent test period (kg/hr). lp= The length of the period p (hours). 10-3= Factor converting kg to metric tons. n = The number of periods in a year.

(3) The total mass of HFC-23 emitted from destruction devices shall be estimated by using Equation O-8 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.058

Page 56429

Where:

ED= Mass of HFC-23 emitted annually from the destruction device (metric tons).

FD= Mass of HFC-23 fed into the destruction device annually (metric tons).

D23= Mass of HFC-23 destroyed annually (metric tons).

(4) For facilities that destroy HFC-23, the total mass of HFC-23 destroyed shall be estimated by using Equation O-9 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.059

Where:

D23= Mass of HFC-23 destroyed annually (metric tons).

FD= Mass of HFC-23 fed into the destruction device annually (metric tons).

DE = Destruction Efficiency of the destruction device (fraction).

Sec. 98.154 Monitoring and QA/QC requirements.

These requirements apply to measurements that are reported under this subpart or that are used to estimate reported quantities pursuant to Sec. 98.153.

(a) The concentrations (fractions by weight) of HFC-23 and HCFC-22 in the product stream shall be measured at least weekly using equipment and methods (e.g., gas chromatography) with an accuracy and precision of 5 percent or better at the concentrations of the process samples.

(b) The mass flow of the product stream containing the HFC-23 shall be measured at least weekly using weigh scales, flowmeters, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better.

(c) The mass of HCFC-22 or HCl coming out of the production process shall be measured at least weekly using weigh scales, flowmeters, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better.

(d) The mass of any used HCFC-22 added back into the production process upstream of the output measurement in paragraph (c) of this section shall be measured (when being added) using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better. If the mass in paragraph (c) of this section is measured by weighing containers that include returned heels as well as newly produced fluorinated GHGs, the returned heels shall be considered used fluorinated HCFC-22 for purposes of this paragraph (d) of this section and Sec. 98.153(b).

(e) The loss factor LF in Equation O-3 of this subpart for the mass of HCFC-22 produced shall have the value 1.015 or another value that can be demonstrated, to the satisfaction of the Administrator, to account for losses of HCFC-22 between the reactor and the point of measurement at the facility where production is being estimated.

(f) The mass of HFC-23 sent off site for sale shall be measured at least weekly (when being packaged) using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better.

(g) The mass of HFC-23 sent off site for destruction shall be measured at least weekly (when being packaged) using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than HFC-23, the concentration of the fluorinated GHG shall be measured at least weekly using equipment and methods (e.g., gas chromatography) with an accuracy and precision of 5 percent or better at the concentrations of the process samples. This concentration (mass fraction) shall be multiplied by the mass measurement to obtain the mass of the HFC-23 sent to another facility for destruction.

(h) The masses of HFC-23 in storage at the beginning and end of the year shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better.

(i) The number of sources of equipment type t with screening values greater than or equal to 10,000 ppmv shall be determined using EPA

Method 21 at 40 CFR part 60, appendix A-7, and defining a leak as follows:

(1) A leak source that could emit HFC-23, and

(2) A leak source at whose surface a concentration of fluorocarbons equal to or greater than 10,000 ppm is measured.

(j) The number of sources of equipment type t with screening values less than 10,000 ppmv shall be the difference between the number of leak sources of equipment type t that could emit HFC-23 and the number of sources of equipment type t with screening values greater than or equal to 10,000 ppmv as determined under paragraph (h) of this section.

(k) The mass of HFC-23 emitted from process vents shall be estimated at least monthly by incorporating the results of the most recent emissions test into Equation O-6 of this subpart. HCFC-22 production facilities that use a thermal oxidizer connected to the

HCFC-22 production equipment shall conduct emissions tests at process vents at least once every five years or after significant changes to the process. Emissions tests shall be conducted in accordance with EPA

Method 18 at 40 CFR part 60, appendix A-6, under conditions that are typical for the production process at the facility. The sensitivity of the tests shall be sufficient to detect an emission rate that would result in annual emissions of 200 kg of HFC-23 if sustained over one year.

(l) For purposes of Equation O-9 of this subpart, the destruction efficiency must be equated to the destruction efficiency determined during a new or previous performance test of the destruction device.

HFC-23 destruction facilities shall conduct annual measurements of HFC- 23 concentrations at the outlet of the thermal oxidizer in accordance with EPA Method 18 at 40 CFR part 60, appendix A-6. Three samples shall be taken under conditions that are typical for the production process and destruction device at the facility, and the average concentration of HFC-23 shall be determined. The sensitivity of the concentration measurement shall be sufficient to detect an outlet concentration equal to or less than the outlet concentration determined in the destruction efficiency performance test. If the concentration measurement indicates that the HFC-23 concentration is less than or equal to that measured during the performance test that is the basis for the destruction efficiency, continue to use the previously determined destruction efficiency. If the concentration measurement indicates that the HFC-23 concentration is greater than that measured during the performance test that is the basis for the destruction efficiency, facilities shall either:

(1) Substitute the higher HFC-23 concentration for that measured during the destruction efficiency performance test and calculate a new destruction efficiency, or

(2) Estimate the mass emissions of HFC-23 from the destruction device based on the measured HFC-23 concentration and volumetric flow rate determined by measurement of volumetric flow rate using EPA Method 2, 2A, 2C,2D, or 2F at 40 CFR part 60, appendix A-1, or Method 26 at 40

CFR part 60, appendix A-2. Determine the mass rate of HFC-23 into the destruction device by measuring the HFC-23 concentration and volumetric flow rate at the inlet or by a metering device for HFC-23 sent to the device. Determine a new destruction efficiency

Page 56430

based on the mass flow rate of HFC-23 into and out of the destruction device.

(m) HCFC-22 production facilities shall account for HFC-23 generation and emissions that occur as a result of startups, shutdowns, and malfunctions, either recording HFC-23 generation and emissions during these events, or documenting that these events do not result in significant HFC-23 generation and/or emissions.

(n) The mass of HFC-23 fed into the destruction device shall be measured at least weekly using flow meters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than HFC-23, the concentrations of the HFC-23 shall be measured at least weekly using equipment and methods (e.g., gas chromatography) with an accuracy and precision of 5 percent or better at the concentrations of the process samples. This concentration (mass fraction) shall be multiplied by the mass measurement to obtain the mass of the HFC-23 destroyed.

(o) In their estimates of the mass of HFC-23 destroyed, HFC-23 destruction facilities shall account for any temporary reductions in the destruction efficiency that result from any startups, shutdowns, or malfunctions of the destruction device, including departures from the operating conditions defined in state or local permitting requirements and/or oxidizer manufacturer specifications.

(p) Calibrate all flow meters, weigh scales, and combinations of volumetric and density measures using NIST-traceable standards and suitable methods published by a consensus standards organization (e.g.,

ASTM, ASME, ISO, or others). Recalibrate all flow meters, weigh scales, and combinations of volumetric and density measures at the minimum frequency specified by the manufacturer.

(q) All gas chromatographs used to determine the concentration of

HFC-23 in process streams shall be calibrated at least monthly through analysis of certified standards (or of calibration gases prepared from a high-concentration certified standard using a gas dilution system that meets the requirements specified in Method 205 at 40 CFR part 51, appendix M) with known HFC-23 concentrations that are in the same range

(fractions by mass) as the process samples.

Sec. 98.155 Procedures for estimating missing data.

(a) A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality- assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required process sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the following requirements:

(1) For each missing value of the HFC-23 or HCFC-22 concentration, the substitute data value shall be the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality- assured value obtained after the missing data period.

(2) For each missing value of the product stream mass flow or product mass, the substitute value of that parameter shall be a secondary product measurement where such a measurement is available. If that measurement is taken significantly downstream of the usual mass flow or mass measurement (e.g., at the shipping dock rather than near the reactor), the measurement shall be multiplied by 1.015 to compensate for losses. Where a secondary mass measurement is not available, the substitute value of the parameter shall be an estimate based on a related parameter. For example, if a flowmeter measuring the mass fed into a destruction device is rendered inoperable, then the mass fed into the destruction device may be estimated using the production rate and the previously observed relationship between the production rate and the mass flow rate into the destruction device.

Sec. 98.156 Data reporting requirements.

(a) In addition to the information required by Sec. 98.3(c), the

HCFC-22 production facility shall report the following information at the facility level:

(1) Annual mass of HCFC-22 produced in metric tons.

(2) Loss Factor used to account for the loss of HCFC- 22 upstream of the measurement.

(3) Annual mass of reactants fed into the process in metric tons of reactant.

(4) The mass (in metric tons) of materials other than HCFC-22 and

HFC-23 (i.e., unreacted reactants, HCl and other by-products) that occur in more than trace concentrations and that are permanently removed from the process.

(5) The method for tracking startups, shutdowns, and malfunctions and HFC-23 generation/emissions during these events.

(6) The names and addresses of facilities to which any HFC-23 was sent for destruction, and the quantities of HFC-23 (metric tons) sent to each.

(7) Annual mass of the HFC-23 generated in metric tons.

(8) Annual mass of any HFC-23 sent off site for sale in metric tons.

(9) Annual mass of any HFC-23 sent off site for destruction in metric tons.

(10) Mass of HFC-23 in storage at the beginning and end of the year, in metric tons.

(11) Annual mass of HFC-23 emitted in metric tons.

(12) Annual mass of HFC-23 emitted from equipment leaks in metric tons.

(13) Annual mass of HFC-23 emitted from process vents in metric tons.

(b) In addition to the information required by Sec. 98.3(c), facilities that destroy HFC-23 shall report the following for each HFC- 23 destruction process:

(1) Annual mass of HFC-23 fed into the thermal oxidizer.

(2) Annual mass of HFC-23 destroyed.

(3) Annual mass of HFC-23 emitted from the thermal oxidizer.

(c) Each HFC-23 destruction facility shall report the results of the facility's annual HFC-23 concentration measurements at the outlet of the destruction device, including:

(1) Flow rate of HFC-23 being fed into the destruction device in kg/hr.

(2) Concentration (mass fraction) of HFC-23 at the outlet of the destruction device.

(3) Flow rate at the outlet of the destruction device in kg/hr.

(d) Emission rate calculated from paragraphs (c)(2) and (3) of this section in kg/hr.

(e) HFC-23 destruction facilities shall submit a one-time report including the following information for each the destruction process:

(1) Destruction efficiency (DE).

(2) The methods used to determine destruction efficiency.

(3) The methods used to record the mass of HFC-23 destroyed.

(4) The name of other relevant federal or state regulations that may apply to the destruction process.

(5) If any changes are made that affect HFC-23 destruction efficiency or the methods used to record volume destroyed, then these changes must be reflected in a revision to this report. The revised report must be submitted to EPA within 60 days of the change.

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Sec. 98.157 Records that must be retained.

(a) In addition to the data required by Sec. 98.3(g), HCFC-22 production facilities shall retain the following records:

(1) The data used to estimate HFC-23 emissions.

(2) Records documenting the initial and periodic calibration of the gas chromatographs, weigh scales, volumetric and density measurements, and flowmeters used to measure the quantities reported under this rule, including the industry standards or manufacturer directions used for calibration pursuant to Sec. 98.154(p) and (q).

(b) In addition to the data required by Sec. 98.3(g), the HFC-23 destruction facilities shall retain the following records:

(1) Records documenting their one-time and annual reports in Sec. 98.156(b) through (d).

(2) Records documenting the initial and periodic calibration of the gas chromatographs, weigh scales, volumetric and density measurements, and flowmeters used to measure the quantities reported under this subpart, including the industry standard practice or manufacturer directions used for calibration pursuant to Sec. 98.154(p) and (q).

Sec. 98.158 Definitions.

All terms used in this subpart have the same meaning given in the

Clean Air Act and subpart A of this part.

Table O-1 to Subpart O of Part 98--Emission Factors for Equipment Leaks

Emission factor (kg/hr/ source)

Equipment type

Service

-------------------------

>=10,000

2process emissions from each hydrogen production process unit.

(b) CO2, CH4and N2O combustion emissions from each hydrogen production process unit. You must calculate and report these combustion emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.

(c) CO2, CH4, and N2O emissions from each stationary combustion unit other than hydrogen production process units. You must calculate and report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.

(d) For CO2collected and transferred off site, you must follow the requirements of subpart PP of this part.

Sec. 98.163 Calculating GHG emissions.

You must calculate and report the annual process CO2 emissions from each hydrogen production process unit using the procedures specified in either paragraph (a) or (b) of this section.

(a) Continuous Emissions Montoring Systems (CEMS). Calculate and report under this subpart the process CO2emissions by operating and maintaining CEMS according to the Tier 4 Calculation

Methodology specified in Sec. 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary

Fuel Combustion Sources).

(b) Fuel and feedstock material balance approach. Calculate and report process CO2emissions as the sum of the annual emissions associated with each fuel and feedstock used for hydrogen production by following paragraphs (b)(1) through (b)(3) of this section.

(1) Gaseous fuel and feedstock. You must calculate the annual

CO2process emissions from gaseous fuel and feedstock according to Equation P-1 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.060

Where:

CO2= Annual CO2process emissions arising from fuel and feedstock consumption (metric tons/yr).

Fdstkn= Volume of the gaseous fuel and feedstock used in month n (scf (at standard conditions of 68 [deg]F and atmospheric pressure) of fuel and feedstock).

CCn= Average carbon content of the gaseous fuel and feedstock, from the results of one or more analyses for month n (kg carbon per kg of fuel and feedstock).

MW = Molecular weight of the gaseous fuel and feedstock (kg/kg- mole).

Page 56432

MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard conditions). k = Months in the year. 44/12 = Ratio of molecular weights, CO2to carbon. 0.001

= Conversion factor from kg to metric tons.

(2) Liquid fuel and feedstock. You must calculate the annual

CO2process emissions from liquid fuel and feedstock according to Equation P-2 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.061

Where:

CO2= Annual CO2emissions arising from fuel and feedstock consumption (metric tons/yr).

Fdstkn= Volume of the liquid fuel and feedstock used in month n (gallons of fuel and feedstock).

CCn= Average carbon content of the liquid fuel and feedstock, from the results of one or more analyses for month n (kg carbon per gallon of fuel and feedstock). k = Months in the year. 44/12 = Ratio of molecular weights, CO2to carbon. 0.001 = Conversion factor from kg to metric tons.

(3) Solid fuel and feedstock. You must calculate the annual

CO2process emissions from solid fuel and feedstock according to Equation P-3 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.062

Where:

CO2= Annual CO2emissions from fuel and feedstock consumption in metric tons per month (metric tons/yr).

Fdstkn= Mass of solid fuel and feedstock used in month n

(kg of fuel and feedstock).

CCn= Average carbon content of the solid fuel and feedstock, from the results of one or more analyses for month n (kg carbon per kg of fuel and feedstock). k = Months in the year. 44/12 = Ratio of molecular weights, CO2to carbon. 0.001 = Conversion factor from kg to metric tons.

(c) If GHG emissions from a hydrogen production process unit are vented through the same stack as any combustion unit or process equipment that reports CO2emissions using a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Fuel Combustion Sources), then the calculation methodology in paragraph (b) of this section shall not be used to calculate process emissions. The owner or operator shall report under this subpart the combined stack emissions according to the Tier 4

Calculation Methodology in Sec. 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary

Fuel Combustion Sources).

Sec. 98.164 Monitoring and QA/QC requirements.

The GHG emissions data for hydrogen production process units must be quality-assured as specified in paragraphs (a) or (b) of this section, as appropriate for each process unit:

(a) If a CEMS is used to measure GHG emissions, then the facility must comply with the monitoring and QA/QC procedures specified in Sec. 98.34(c).

(b) If a CEMS is not used to measure GHG emissions, then you must:

(1) Calibrate all oil and gas flow meters (except for gas billing meters), solids weighing equipment, and oil tank drop measurements (if used to determine liquid fuel and feedstock use volume) according to the calibration accuracy requirements in Sec. 98.3(i) of this part.

(2) Determine the carbon content and the molecular weight annually of standard gaseous hydrocarbon fuels and feedstocks having consistent composition (e.g., natural gas). For other gaseous fuels and feedstocks

(e.g., biogas, refinery gas, or process gas), weekly sampling and analysis is required to determine the carbon content and molecular weight of the fuel and feedstock.

(3) Determine the carbon content of fuel oil, naphtha, and other liquid fuels and feedstocks at least monthly, except annually for standard liquid hydrocarbon fuels and feedstocks having consistent composition, or upon delivery for liquid fuels delivered by bulk transport (e.g., by truck or rail).

(4) Determine the carbon content of coal, coke, and other solid fuels and feedstocks at least monthly, except annually for standard solid hydrocarbon fuels and feedstocks having consistent composition, or upon delivery for solid fuels delivered by bulk transport (e.g., by truck or rail).

(5) You must use the following applicable methods to determine the carbon content for all fuels and feedstocks, and molecular weight of gaseous fuels and feedstocks.

(i) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see Sec. 98.7).

(ii) ASTM D1946-90 (Reapproved 2006), Standard Practice for

Analysis of Reformed Gas by Gas Chromatography (incorporated by reference, see Sec. 98.7).

(iii) ASTM D2013-07 Standard Practice of Preparing Coal Samples for

Analysis (incorporated by reference, see Sec. 98.7).

(iv) ASTM D2234/D2234M-07 Standard Practice for Collection of a

Gross Sample of Coal (incorporated by reference, see Sec. 98.7).

(v) ASTM D2597-94 (Reapproved 2004) Standard Test Method for

Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing

Nitrogen and Carbon Dioxide by Gas Chromatography (incorporated by reference, see Sec. 98.7).

(vi) ASTM D3176-89 (Reapproved 2002), Standard Practice for

Ultimate Analysis of Coal and Coke (incorporated by reference, see

Sec. 98.7).

(vii) ASTM D3238-95 (Reapproved 2005), Standard Test Method for

Calculation of Carbon Distribution and Structural Group Analysis of

Petroleum Oils by the n-d-M Method (incorporated by reference, see

Sec. 98.7).

(viii) ASTM D4057-06 Standard Practice for Manual Sampling of

Petroleum and Petroleum Products (incorporated by reference, see Sec. 98.7).

Page 56433

(ix) ASTM D4177-95 (Reapproved 2005) Standard Practice for

Automatic Sampling of Petroleum and Petroleum Products (incorporated by reference, see Sec. 98.7).

(x) ASTM D5291-02 (Reapproved 2007), Standard Test Methods for

Instrumental Determination of Carbon, Hydrogen, and Nitrogen in

Petroleum Products and Lubricants (incorporated by reference, see Sec. 98.7).

(xi) ASTM D5373-08 Standard Test Methods for Instrumental

Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see Sec. 98.7).

(xii) ASTM D6609-08 Standard Guide for Part-Stream Sampling of Coal

(incorporated by reference, see Sec. 98.7).

(xiii) ASTM D6883-04 Standard Practice for Manual Sampling of

Stationary Coal from Railroad Cars, Barges, Trucks, or Stockpiles

(incorporated by reference, see Sec. 98.7).

(xiv) ASTM D7430-08ae1 Standard Practice for Mechanical Sampling of

Coal (incorporated by reference, see Sec. 98.7).

(xv) ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography

(incorporated by reference, see Sec. 98.7).

(xvi) GPA 2261-00 Analysis for Natural Gas and Similar Gaseous

Mixtures by Gas Chromatography (incorporated by reference, see Sec. 98.7).

(xvii) ISO 3170: Petroleum Liquids--Manual sampling--Third Edition

(incorporated by reference, see Sec. 98.7).

(xviii) ISO 3171: Petroleum Liquids--Automatic pipeline sampling--

Second Edition (incorporated by reference, see Sec. 98.7).

(c) For units using the calculation methodologies described in this section, the records required under Sec. 98.3(g) must include both the company records and a detailed explanation of how company records are used to estimate the following:

(1) Fuel and feedstock consumption, when solid fuel and feedstock is combusted and a CEMS is not used to measure GHG emissions.

(2) Fossil fuel consumption, when, pursuant to Sec. 98.33(e), the owner or operator of a unit that uses CEMS to quantify CO2 emissions and that combusts both fossil and biogenic fuels separately reports the biogenic portion of the total annual CO2 emissions.

(3) Sorbent usage, if the methodology in Sec. 98.33(d) is used to calculate CO2emissions from sorbent.

(d) The owner or operator must document the procedures used to ensure the accuracy of the estimates of fuel and feedstock usage and sorbent usage (as applicable) in paragraph (b) of this section, including, but not limited to, calibration of weighing equipment, fuel and feedstock flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided.

Sec. 98.165 Procedures for estimating missing data.

A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality- assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation), a substitute data value for the missing parameter must be used in the calculations as specified in paragraphs (a), (b), and (c) of this section:

(a) For each missing value of the monthly fuel and feedstock consumption, the substitute data value must be the best available estimate of the fuel and feedstock consumption, based on all available process data (e.g., hydrogen production, electrical load, and operating hours). You must document and keep records of the procedures used for all such estimates.

(b) For each missing value of the carbon content or molecular weight of the fuel and feedstock, the substitute data value must be the arithmetic average of the quality-assured values of carbon contents or molecular weight of the fuel and feedstock immediately preceding and immediately following the missing data incident. If no quality-assured data on carbon contents or molecular weight of the fuel and feedstock are available prior to the missing data incident, the substitute data value must be the first quality-assured value for carbon contents or molecular weight of the fuel and feedstock obtained after the missing data period. You must document and keep records of the procedures used for all such estimates.

Sec. 98.166 Data reporting requirements.

In addition to the information required by Sec. 98.3(c), each annual report must contain the information specified in paragraphs (a) or (b) of this section, as appropriate:

(a) If a CEMS is used to measure CO2emissions, then you must report the relevant information required under Sec. 98.36 for the

Tier 4 Calculation Methodology and the following information in this paragraph (a):

(1) Unit identification number and annual CO2process emissions.

(2) Annual quantity of hydrogen produced (metric tons) for each process unit and for all units combined.

(3) Annual quantity of ammonia produced (metric tons), if applicable, for each process unit and for all units combined.

(b) If a CEMS is not used to measure CO2emissions, then you must report the following information for each hydrogen production process unit:

(1) Unit identification number and annual CO2process emissions.

(2) Monthly consumption of each fuel and feedstock used for hydrogen production and its type (scf of gaseous fuels and feedstocks, gallons of liquid fuels and feedstocks, kg of solid fuels and feedstocks).

(3) Annual quantity of hydrogen produced (metric tons).

(4) Annual quantity of ammonia produced, if applicable (metric tons).

(5) Monthly analyses of carbon content for each fuel and feedstock used in hydrogen production (kg carbon/kg of gaseous and solid fuels and feedstocks, (kg carbon per gallon of liquid fuels and feedstocks).

(6) Monthly analyses of the molecular weight of gaseous fuels and feedstocks (kg/kg-mole) used, if any.

(c) Quarterly quantity of CO2collected and transferred off site in either gas, liquid, or solid forms (kg), following the requirements of subpart PP of this part.

(d) Annual quantity of carbon other than CO2collected and transferred off site in either gas, liquid, or solid forms (kg carbon).

Sec. 98.167 Records that must be retained.

In addition to the information required by Sec. 98.3(g), you must retain the records specified in paragraphs (a) through (b) of this section for each hydrogen production facility.

(a) If a CEMS is used to measure CO2emissions, then you must retain under this subpart the records required for the Tier 4

Calculation Methodology in Sec. 98.37.

(b) If a CEMS is not used to measure CO2emissions, then you must retain records of all analyses and calculations conducted as listed in Sec. Sec. 98.166(b), (c), and (d).

Sec. 98.168 Definitions.

All terms used in this subpart have the same meaning given in the

Clean Air Act and subpart A of this part.

Subpart Q--Iron and Steel Production

Sec. 98.170 Definition of the source category.

The iron and steel production source category includes facilities with any of the following processes: taconite iron

Page 56434

ore processing, integrated iron and steel manufacturing, cokemaking not colocated with an integrated iron and steel manufacturing process, and electric arc furnace (EAF) steelmaking not colocated with an integrated iron and steel manufacturing process. Integrated iron and steel manufacturing means the production of steel from iron ore or iron ore pellets. At a minimum, an integrated iron and steel manufacturing process has a basic oxygen furnace for refining molten iron into steel.

Each cokemaking process and EAF process located at a facility with an integrated iron and steel manufacturing process is part of the integrated iron and steel manufacturing facility.

Sec. 98.171 Reporting threshold.

You must report GHG emissions under this subpart if your facility contains an iron and steel production process and the facility meets the requirements of either Sec. 98.2(a)(1) or (2).

Sec. 98.172 GHGs to report.

(a) You must report under subpart C of this part (General

Stationary Fuel Combustion Sources) the emissions of CO2,

CH4, and N2O from each stationary combustion unit following the requirements of subpart C except for flares. Stationary combustion units include, but are not limited to, by-product recovery coke oven battery combustion stacks, blast furnace stoves, boilers, process heaters, reheat furnaces, annealing furnaces, flame suppression, ladle reheaters, and other miscellaneous combustion sources.

(b) You must report CO2emissions from flares according to the procedures in Sec. 98.253(b)(1) of subpart Y (Petroleum

Refineries) of this part except you must use the default CO2 emission factors for coke oven gas and blast furnace gas from Table C-1 of subpart C in Equation Y-1 of subpart Y of this part. You must report

CH4and N2O emissions from flares according to the requirements in Sec. 98.33(c)(2) using the emission factors for coke oven gas and blast furnace gas in Table C-2 of subpart C of this part.

(c) You must report process CO2emissions from each taconite indurating furnace; basic oxygen furnace; non-recovery coke oven battery combustion stack; coke pushing process; sinter process;

EAF; argon-oxygen decarburization vessel; and direct reduction furnace by following the procedures in this subpart.

Sec. 98.173 Calculating GHG emissions.

You must calculate and report the annual process CO2 emissions from each taconite indurating furnace, basic oxygen furnace, non-recovery coke oven battery, sinter process, EAF, argon-oxygen decarburization vessel, and direct reduction furnace using the procedures in either paragraph (a) or (b) of this section. Calculate and report the annual process CO2emissions from the coke pushing process according to paragraph (c) of this section.

(a) Calculate and report under this subpart the process

CO2emissions by operating and maintaining CEMS according to the Tier 4 Calculation Methodology in Sec. 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General

Stationary Fuel Combustion Sources).

(b) Calculate and report under this subpart the process

CO2emissions using the procedure in paragraph (b)(1) or

(b)(2) of this section.

(1) Carbon mass balance method. Calculate the annual mass emissions of CO2for the process as specified in paragraphs (b)(1)(i) through (b)(1)(vii) of this section. The calculations are based on the annual mass of inputs and outputs to the process and an annual analysis of the respective weight fraction of carbon as determined according to the procedures in Sec. 98.174(b). If you have a process input or output other than CO2in the exhaust gas that contains carbon that is not included in Equations Q-1 through Q-7 of this section, you must account for the carbon and mass rate of that process input or output in your calculations according to the procedures in

Sec. 98.174(b)(5).

(i) For taconite indurating furnaces, estimate CO2 emissions using Equation Q-1 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.063

Where:

CO2= Annual CO2mass emissions from the taconite indurating furnace (metric tons). 44/12 = Ratio of molecular weights, CO2to carbon.

(Fs) = Annual mass of the solid fuel combusted (metric tons).

(Csf) = Carbon content of the solid fuel, from the fuel analysis (percent by weight, expressed as a decimal fraction, e.g., 95% = 0.95).

(Fg) = Annual volume of the gaseous fuel combusted (scf).

(Cgf) = Average carbon content of the gaseous fuel, from the fuel analysis results (kg C per kg of fuel).

MW = Molecular weight of the gaseous fuel (kg/kg-mole).

MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard conditions). 0.001 = Conversion factor from kg to metric tons.

(Fl) = Annual volume of the liquid fuel combusted

(gallons).

(Clf) = Carbon content of the liquid fuel, from the fuel analysis results (kg C per gallon of fuel).

(O) = Annual mass of greenball (taconite) pellets fed to the furnace

(metric tons).

(C0) = Carbon content of the greenball (taconite) pellets, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(P) = Annual mass of fired pellets produced by the furnace (metric tons).

(Cp) = Carbon content of the fired pellets, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(R) = Annual mass of air pollution control residue collected (metric tons).

(CR) = Carbon content of the air pollution control residue, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(ii) For basic oxygen process furnaces, estimate CO2 emissions using Equation Q-2 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.064

Page 56435

Where:

CO2= Annual CO2mass emissions from the basic oxygen furnace (metric tons). 44/12 = Ratio of molecular weights, CO2to carbon.

(Iron) = Annual mass of molten iron charged to the furnace (metric tons).

(CIron) = Carbon content of the molten iron, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(Scrap) = Annual mass of ferrous scrap charged to the furnace

(metric tons).

(CScrap) = Carbon content of the ferrous scrap, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(Flux) = Annual mass of flux materials (e.g., limestone, dolomite) charged to the furnace (metric tons).

(CFlux) = Carbon content of the flux materials, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(Carbon) = Annual mass of carbonaceous materials (e.g., coal, coke) charged to the furnace (metric tons).

(CCarbon) = Carbon content of the carbonaceous materials, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(Steel) = Annual mass of molten raw steel produced by the furnace

(metric tons).

(CSteel) = Carbon content of the steel, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(Slag) = Annual mass of slag produced by the furnace (metric tons).

(CSlag) = Carbon content of the slag, from the carbon analysis (percent by weight, expressed as a decimal fraction).

(R) = Annual mass of air pollution control residue collected (metric tons).

(CR) = Carbon content of the air pollution control residue, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(iii) For non-recovery coke oven batteries, estimate CO2 emissions using Equation Q-3 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.065

Where:

CO2= Annual CO2mass emissions from the non- recovery coke oven battery (metric tons). 44/12 = Ratio of molecular weights, CO2to carbon.

(Coal) = Annual mass of coal charged to the battery (metric tons).

(CCoal) = Carbon content of the coal, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(Coke) = Annual mass of coke produced by the battery (metric tons).

(CCoke) = Carbon content of the coke, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(R) = Annual mass of air pollution control residue collected (metric tons).

(CR) = Carbon content of the air pollution control residue, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(iv) For sinter processes, estimate CO2emissions using

Equation Q-4 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.066

Where:

CO2= Annual CO2mass emissions from the sinter process (metric tons). 44/12 = Ratio of molecular weights, CO2to carbon.

(Fg) = Annual volume of the gaseous fuel combusted (scf).

(Cgf) = Carbon content of the gaseous fuel, from the fuel analysis results (kg C per kg of fuel).

MW = Molecular weight of the gaseous fuel (kg/kg-mole).

MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard conditions). 0.001 = Conversion factor from kg to metric tons.

(Feed) = Annual mass of sinter feed material (metric tons).

(CFeed) = Carbon content of the mixed sinter feed materials that form the bed entering the sintering machine, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(Sinter) = Annual mass of sinter produced (metric tons).

(CSinter) = Carbon content of the sinter pellets, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(R) = Annual mass of air pollution control residue collected (metric tons).

(CR) = Carbon content of the air pollution control residue, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(v) For EAFs, estimate CO2emissions using Equation Q-5 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.067

Where:

CO2= Annual CO2mass emissions from the EAF

(metric tons). 44/12 = Ratio of molecular weights, CO2to carbon.

(Iron) = Annual mass of direct reduced iron (if any) charged to the furnace (metric tons).

(CIron) = Carbon content of the direct reduced iron, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(Scrap) = Annual mass of ferrous scrap charged to the furnace

(metric tons).

(CScrap) = Carbon content of the ferrous scrap, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(Flux) = Annual mass of flux materials (e.g., limestone, dolomite) charged to the furnace (metric tons).

(CFlux) = Carbon content of the flux materials, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

Page 56436

(Electrode) = Annual mass of carbon electrode consumed (metric tons).

(CElectrode) = Carbon content of the carbon electrode, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(Carbon) = Annual mass of carbonaceous materials (e.g., coal, coke) charged to the furnace (metric tons).

(CCarbon) = Carbon content of the carbonaceous materials, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(Steel) = Annual mass of molten raw steel produced by the furnace

(metric tons).

(CSteel) = Carbon content of the steel, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(Slag) = Annual mass of slag produced by the furnace (metric tons).

(CSlag) = Carbon content of the slag, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(R) = Annual mass of air pollution control residue collected (metric tons).

(CR) = Carbon content of the air pollution control residue, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(vi) For argon-oxygen decarburization vessels, estimate

CO2emissions using Equation Q-6 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.068

Where:

CO2= Annual CO2mass emissions from the argon-oxygen decarburization vessel (metric tons). 44/12 = Ratio of molecular weights, CO2to carbon.

(Steel) = Annual mass of molten steel charged to the vessel (metric tons).

(CSteelin) = Carbon content of the molten steel before decarburization, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(CSteelout) = Carbon content of the molten steel after decarburization, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(R) = Annual mass of air pollution control residue collected (metric tons).

(CR) = Carbon content of the air pollution control residue, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(vii) For direct reduction furnaces, estimate CO2 emissions using Equation Q-7 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.069

Where:

CO2= Annual CO2mass emissions from the direct reduction furnace (metric tons). 44/12 = Ratio of molecular weights, CO2to carbon.

(Fg) = Annual volume of the gaseous fuel combusted (scf).

(Cgf) = Carbon content of the gaseous fuel, from the fuel analysis results (kg C per kg of fuel).

MW = Molecular weight of the gaseous fuel (kg/kg-mole).

MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard conditions). 0.001 = Conversion factor from kg to metric tons.

(Ore) = Annual mass of iron ore or iron ore pellets fed to the furnace (metric tons).

(COre) = Carbon content of the iron ore or iron ore pellets, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(Carbon) = Annual mass of carbonaceous materials (e.g., coal, coke) charged to the furnace (metric tons).

(CCarbon) = Carbon content of the carbonaceous materials, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(Other) = Annual mass of other materials charged to the furnace

(metric tons).

(COther) = Average carbon content of the other materials charged to the furnace, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(Iron) = Annual mass of iron produced (metric tons).

(CIron) = Carbon content of the iron, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(NM) = Annual mass of non-metallic materials produced by the furnace

(metric tons).

(CNM) = Carbon content of the non-metallic materials, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(R) = Annual mass of air pollution control residue collected (metric tons).

(CR) = Carbon content of the air pollution control residue, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(2) Site-specific emission factor method. Conduct a performance test and measure CO2emissions from all exhaust stacks for the process and measure either the feed rate of materials into the process or the production rate during the test as described in paragraphs (b)(2)(i) through (b)(2)(iv) of this section.

(i) You must measure the process production rate or process feed rate, as applicable, during the performance test according to the procedures in Sec. 98.174(c)(5) and calculate the average rate for the test period in metric tons per hour.

(ii) You must calculate the hourly CO2emission rate using Equation Q-8 of this section and determine the average hourly

CO2emission rate for the test.

GRAPHIC

TIFF OMITTED TR30OC09.070

Where:

CO2= CO2mass emission rate, corrected for moisture (metric tons/hr). 5.18 x 10-7= Conversion factor (metric tons/scf-%

CO2).

Page 56437

CCO2= Hourly CO2concentration, dry basis (%

CO2).

Q = Hourly stack gas volumetric flow rate (scfh).

%H2O = Hourly moisture percentage in the stack gas.

(iii) You must calculate a site-specific emission factor for the process in metric tons of CO2per metric ton of feed or production, as applicable, by dividing the average hourly

CO2emission rate during the test by the average hourly feed or production rate during the test.

(iv) You must calculate CO2emissions for the process by multiplying the emission factor by the total amount of feed or production, as applicable, for the reporting period.

(c) You must determine emissions of CO2from the coke pushing process in mtCO2e by multiplying the metric tons of coal charged to the coke ovens during the reporting period by 0.008.

(d) If GHG emissions from a taconite indurating furnace, basic oxygen furnace, non-recovery coke oven battery, sinter process, EAF, argon-oxygen decarburization vessel, or direct reduction furnace are vented through the same stack as any combustion unit or process equipment that reports CO2emissions using a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Fuel Combustion Sources), then the calculation methodology in paragraph (b) of this section shall not be used to calculate process emissions. The owner or operator shall report under this subpart the combined stack emissions according to the Tier 4

Calculation Methodology in Sec. 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary

Fuel Combustion Sources).

Sec. 98.174 Monitoring and QA/QC requirements.

(a) If you operate and maintain a CEMS that measures CO2 emissions consistent with subpart C of this part, you must meet the monitoring and QA/QC requirements of Sec. 98.34(c).

(b) If you determine CO2emissions using the carbon mass balance procedure in Sec. 98.173(b)(1), you must:

(1) Except as provided in paragraph (b)(4) of this section, determine the mass of each process input and output other than fuels using the same plant instruments or procedures that are used for accounting purposes (such as weigh hoppers, belt weigh feeders, weighed purchased quantities in shipments or containers, combination of bulk density and volume measurements, etc.), record the totals for each process input and output for each calendar month, and sum the monthly mass to determine the annual mass for each process input and output.

Determine the mass rate of fuels using the procedures for combustion units in Sec. 98.34.

(2) Except as provided in paragraph (b)(4) of this section, determine the carbon content of each process input and output annually for use in the applicable equations in Sec. 98.173(b)(1) based on analyses provided by the supplier or by the average carbon content determined by collecting and analyzing at least three samples each year using the standard methods specified in paragraphs (b)(2)(i) through

(b)(2)(vi) of this section as applicable.

(i) ASTM C25-06, Standard Test Methods for Chemical Analysis of

Limestone, Quicklime, and Hydrated Lime (incorporated by reference, see

Sec. 98.7) for limestone, dolomite, and slag.

(ii) ASTM D5373-08 Standard Test Methods for Instrumental

Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see Sec. 98.7) for coal, coke, and other carbonaceous materials.

(iii) ASTM E1915-07a, Standard Test Methods for Analysis of Metal

Bearing Ores and Related Materials by Combustion Infrared-Absorption

Spectrometry (incorporated by reference, see Sec. 98.7) for iron ore, taconite pellets, and other iron-bearing materials.

(iv) ASTM E1019-08, Standard Test Methods for Determination of

Carbon, Sulfur, Nitrogen, and Oxygen in Steel, Iron, Nickel, and Cobalt

Alloys by Various Combustion and Fusion Techniques (incorporated by reference, see Sec. 98.7) for iron and ferrous scrap.

(v) ASM CS-104 UNS No. G10460--Alloy Digest April 1985 (Carbon

Steel of Medium Carbon Content) (incorporated by reference, see Sec. 98.7); ISO/TR 15349-1:1998, Unalloyed steel--Determination of low carbon content, Part 1: Infrared absorption method after combustion in an electric resistance furnace (by peak separation) (1998-10-15) First

Edition (incorporated by reference, see Sec. 98.7); or ISO/TR 15349- 3:1998, Unalloyed steel-Determination of low carbon content Part 3:

Infrared absorption method after combustion in an electric resistance furnace (with preheating) (1998-10-15) First Edition (incorporated by reference, see Sec. 98.7) as applicable for steel.

(vi) For each process input that is a fuel, determine the carbon content and molecular weight (if applicable) using the applicable methods listed in Sec. 98.34.

(3) For solid ferrous materials charged to basic oxygen process furnaces or EAFs that differ in carbon content, you may determine a weighted average carbon content based on the carbon content of each type of ferrous material and the average weight percent of each type that is used. Examples of these different ferrous materials include carbon steel, low carbon steel, stainless steel, high alloy steel, pig iron, iron scrap, and direct reduced iron.

(4) If you document that a specific process input or output contributes less than one percent of the total mass of carbon into or out of the process, you do not have to determine the monthly mass or annual carbon content of that input or output.

(5) Except as provided in paragraph (b)(4) of this section, you must determine the annual carbon content and monthly mass rate of any input or output that contains carbon that is not listed in the equations in Sec. 98.173(b)(1) using the procedures in paragraphs

(b)(1) and (b)(2) of this section.

(1) Conduct an annual performance test that is based on representative performance (i.e., performance based on normal operating conditions) of the affected process.

(2) For the furnace exhaust from basic oxygen furnaces, EAFs, argon-oxygen decarburization vessels, and direct reduction furnaces, sample the furnace exhaust for at least three complete production cycles that start when the furnace is being charged and end after steel or iron and slag have been tapped. For EAFs that produce both carbon steel and stainless or specialty (low carbon) steel, develop an emission factor for the production of both types of steel.

(3) For taconite indurating furnaces, non-recovery coke batteries, and sinter processes, sample for at least 3 hours.

(4) Conduct the stack test using EPA Method 3A at 40 CFR part 60, appendix A-2 to measure the CO2concentration, Method 2, 2A, 2C, 2D, or 2F at 40 CFR part 60, appendix A-1 or Method 26 at 40 CFR part 60, appendix A-2 to determine the stack gas volumetric flow rate, and Method 4 at 40 CFR part 60, at appendix A-3 to determine the moisture content of the stack gas.

(5) Determine the mass rate of process feed or process production

(as applicable) during the test using the same plant instruments or procedures that are used for accounting purposes (such as weigh hoppers, belt weigh feeders, combination of bulk density and volume measurements, etc.)

(6) If your process operates under different conditions as part of normal operations in such a manner that CO2emissions change by more than 20

Page 56438

percent (e.g., routine changes in the carbon content of the sinter feed or change in grade of product), you must perform emission testing and develop separate emission factors for these different operating conditions and determine emissions based on the number of hours the process operates and the production or feed rate (as applicable) at each specific different condition.

(7) If your EAF and argon-oxygen decarburization vessel exhaust to a common emission control device and stack, you must sample each process in the ducts before the emissions are combined, sample each process when only one process is operating, or sample the combined emissions when both processes are operating and base the site-specific emission factor on the steel production rate of the EAF.

(8) The results of a performance test must include the analysis of samples, determination of emissions, and raw data. The performance test report must contain all information and data used to derive the emission factor.

(d) For a coke pushing process, determine the metric tons of coal charged to the coke ovens and record the totals for each pushing process for each calendar month. Coal charged to coke ovens can be measured using weigh belts or a combination of measuring volume and bulk density.

Sec. 98.175 Procedures for estimating missing data.

A complete record of all measured parameters used in the GHG emissions calculations in Sec. 98.173 is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in the paragraphs (a) and (b) of this section. You must document and keep records of the procedures used for all such estimates.

(a) For each missing data for the carbon content of inputs and outputs for facilities that estimate emissions using the carbon mass balance procedure in Sec. 98.173(b)(1) or for facilities that estimate emissions using the site-specific emission factor procedure in Sec. 98.173(b)(2); 100 percent data availability is required. You must repeat the test for average carbon contents of inputs and outputs according to the procedures in Sec. 98.174(b)(2). Similarly, you must repeat the test to determine the site-specific emission factor if data on the CO2emission rate, process production rate or process feed rate are missing.

(b) For missing records of the monthly mass or volume of carbon- containing inputs and outputs using the carbon mass balance procedure in Sec. 98.173(b)(1), the substitute data value must be based on the best available estimate of the mass of the input or output material from all available process data or data used for accounting purposes.

Sec. 98.176 Data reporting requirements.

In addition to the information required by Sec. 98.3(c), each annual report must contain the information required in paragraphs (a) through (f) of this section for each coke pushing operation; taconite indurating furnace; basic oxygen furnace; non-recovery coke oven battery; sinter process; EAF; argon-oxygen decarburization vessel; and direct reduction furnace:

(a) Unit identification number and annual CO2emissions

(in metric tons).

(b) Annual production quantity (in metric tons) for taconite pellets, coke, sinter, iron, and raw steel.

(c) If a CEMS is used to measure CO2emissions, then you must report the relevant information required under Sec. 98.37 for the

Tier 4 Calculation Methodology.

(d) If a CEMS is not used to measure CO2emissions, then you must report for each process whether the emissions were determined using the carbon mass balance method in Sec. 98.173(b)(1) or the site- specific emission factor method in Sec. 98.173(b)(2).

(e) If you use the carbon mass balance method in Sec. 98.173(b)(1) to determine CO2emissions, you must report the following information for each process:

(1) The carbon content of each process input and output used to determine CO2emissions.

(2) Whether the carbon content was determined from information from the supplier or by laboratory analysis, and if by laboratory analysis, the method used.

(3) The annual volume of gaseous fuel (in standard cubic feet), the annual volume of liquid fuel (in gallons), and the annual mass (in metric tons) of all other process inputs and outputs used to determine

CO2emissions.

(4) The molecular weight of gaseous fuels.

(5) If you used the missing data procedures in Sec. 98.175(b), you must report how the monthly mass for each process input or output with missing data was determined and the number of months the missing data procedures were used.

(f) If you used the site-specific emission factor method in Sec. 98.173(b)(2) to determine CO2emissions, you must report the following information for each process:

(1) The measured average hourly CO2emission rate during the test (in metric tons per hour).

(2) The average hourly feed or production rate (as applicable) during the test (in metric tons per hour).

(3) The site-specific emission factor (in metric tons of

CO2per metric ton of feed or production, as applicable).

(4) The annual feed or production rate (as applicable) used to estimate annual CO2emissions (in metric tons).

Sec. 98.177 Records that must be retained.

In addition to the records required by Sec. 98.3(g), you must retain the records specified in paragraphs (a) through (e) of this section, as applicable. Facilities that use CEMS to measure emissions must also retain records of the verification data required for the Tier 4 Calculating Methodology in Sec. 98.36(e).

(a) Records of all analyses and calculations conducted, including all information reported as required under Sec. 98.176.

(b) When the carbon mass balance method is used to estimate emissions for a process, the monthly mass of each process input and output that are used to determine the annual mass.

(c) Production capacity (in metric tons per year) for the production of taconite pellets, coke, sinter, iron, and raw steel.

(d) Annual operating hours for taconite furnaces, coke oven batteries, sinter production, blast furnaces, direct reduced iron furnaces, and electric arc furnaces.

(e) Facilities must keep records that include a detailed explanation of how company records or measurements are used to determine all sources of carbon input and output and the metric tons of coal charged to the coke ovens (e.g., weigh belts, a combination of measuring volume and bulk density). You also must document the procedures used to ensure the accuracy of the measurements of fuel usage including, but not limited to, calibration of weighing equipment, fuel flow meters, coal usage including, but not limited to, calibration of weighing equipment and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided.

Sec. 98.178 Definitions.

All terms used in this subpart have the same meaning given in the

Clean Air Act and subpart A of this part.

Page 56439

Subpart R--Lead Production

Sec. 98.180 Definition of the source category.

The lead production source category consists of primary lead smelters and secondary lead smelters. A primary lead smelter is a facility engaged in the production of lead metal from lead sulfide ore concentrates through the use of pyrometallurgical techniques. A secondary lead smelter is a facility at which lead-bearing scrap materials (including but not limited to, lead-acid batteries) are recycled by smelting into elemental lead or lead alloys.

Sec. 98.181 Reporting threshold.

You must report GHG emissions under this subpart if your facility contains a lead production process and the facility meets the requirements of either Sec. 98.2(a)(1) or (a)(2).

Sec. 98.182 GHGs to report.

You must report:

(a) Process CO2emissions from each smelting furnace used for lead production.

(b) CO2combustion emissions from each smelting furnace used for lead production.

(c) CH4and N2O combustion emissions from each smelting furnace used for lead production. You must calculate and report these emissions under subpart C of this part (General Stationary

Fuel Combustion Sources) by following the requirements of subpart C.

(d) CO2, CH4, and N2O emissions from each stationary combustion unit other than smelting furnaces used for lead production. You must report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.

Sec. 98.183 Calculating GHG emissions.

You must calculate and report the annual process CO2 emissions from each smelting furnace using the procedure in paragraphs

(a) and (b) of this section.

(a) For each smelting furnace that meets the conditions specified in Sec. 98.33(b)(4)(ii) or (b)(4)(iii), you must calculate and report combined process and combustion CO2emissions by operating and maintaining a CEMS to measure CO2emissions according to the Tier 4 Calculation Methodology specified in Sec. 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part

(General Stationary Fuel Combustion Sources).

(b) For each smelting furnace that is not subject to the requirements in paragraph (a) of this section, calculate and report the process and combustion CO2emissions from the smelting furnace by using the procedure in either paragraph (b)(1) or (b)(2) of this section.

(1) Calculate and report under this subpart the combined process and combustion CO2emissions by operating and maintaining a

CEMS to measure CO2emissions according to the Tier 4

Calculation Methodology specified in Sec. 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General

Stationary Fuel Combustion Sources).

(2) Calculate and report process and combustion CO2 emissions separately using the procedures specified in paragraphs

(b)(2)(i) through (b)(2)(iii) of this section.

(i) For each smelting furnace, determine the annual mass of carbon in each carbon-containing material, other than fuel, that is fed, charged, or otherwise introduced into the smelting furnace and estimate annual process CO2emissions using Equation R-1 of this section. Carbon-containing materials include carbonaceous reducing agents. If you document that a specific material contributes less than 1 percent of the total carbon into the process, you do not have to include the material in your calculation using Equation R-1 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.071

Where:

ECO2= Annual process CO2emissions from an individual smelting furnace (metric tons). 44/12 = Ratio of molecular weights, CO2to carbon. 2000/2205 = Conversion factor to convert tons to metric tons.

Ore = Annual mass of lead ore charged to the smelting furnace

(tons).

COre= Carbon content of the lead ore, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

Scrap = Annual mass of lead scrap charged to the smelting furnace

(tons).

CScrap= Carbon content of the lead scrap, from the carbon analysis (percent by weight, expressed as a decimal fraction).

Flux = Annual mass of flux materials (e.g., limestone, dolomite) charged to the smelting furnace (tons).

CFlux= Carbon content of the flux materials, from the carbon analysis (percent by weight, expressed as a decimal fraction).

Carbon = Annual mass of carbonaceous materials (e.g., coal, coke) charged to the smelting furnace (tons).

CCarbon= Carbon content of the carbonaceous materials, from the carbon analysis (percent by weight, expressed as a decimal fraction).

Other = Annual mass of any other material containing carbon, other than fuel, fed, charged, or otherwise introduced into the smelting furnace (tons).

COther= Carbon content of the other material from the carbon analysis results (percent by weight, expressed as a decimal fraction).

(ii) Determine the combined annual process CO2emissions from the smelting furnaces at your facility using Equation R-2 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.072

Where:

CO2= Annual process CO2emissions from smelting furnaces at facility used for lead production (metric tons).

ECO2k = Annual process CO2emissions from smelting furnace k calculated using Equation R-1 of this section

(metric tons/year). k = Total number of smelting furnaces at facility used for lead production.

(iii) Calculate and report under subpart C of this part (General

Stationary Fuel Combustion Sources) the combustion CO2 emissions from the smelting furnaces according to the applicable requirements in subpart C.

Sec. 98.184 Monitoring and QA/QC requirements.

If you determine process CO2emissions using the carbon mass balance procedure in Sec. 98.183(b)(2)(i) and (b)(2)(ii), you must meet the requirements specified in paragraphs (a) and (b) of this section.

(a) Determine the annual mass for each material used for the calculations of annual process CO2emissions using Equation

R-1 of this subpart by summing the monthly mass for the material determined for each month of the calendar year. The monthly mass may be determined using plant instruments used for accounting purposes, including either direct measurement of the quantity of the material placed in the unit or by calculations using process operating information.

(b) For each material identified in paragraph (a) of this section, you must determine the average carbon content of

Page 56440

the material consumed or used in the calendar year using the methods specified in either paragraph (b)(1) or (b)(2) of this section. If you document that a specific process input or output contributes less than one percent of the total mass of carbon into or out of the process, you do not have to determine the monthly mass or annual carbon content of that input or output.

(1) Information provided by your material supplier.

(2) Collecting and analyzing at least three representative samples of the material each year. The carbon content of the material must be analyzed at least annually using the methods (and their QA/QC procedures) specified in paragraphs (b)(2)(i) through (b)(2)(iii) of this section, as applicable.

(ii) ASTM D5373-08 Standard Test Methods for Instrumental

Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see Sec. 98.7), for analysis of carbonaceous reducing agents and carbon electrodes.

(iii) ASTM C25-06, Standard Test Methods for Chemical Analysis of

Limestone, Quicklime, and Hydrated Lime (incorporated by reference, see

Sec. 98.7) for analysis of flux materials such as limestone or dolomite.

Sec. 98.185 Procedures for estimating missing data.

A complete record of all measured parameters used in the GHG emissions calculations in Sec. 98.183 is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in the paragraphs (a) and (b) of this section. You must document and keep records of the procedures used for all such estimates.

(a) For each missing data for the carbon content for the smelting furnaces at your facility that estimate annual process CO2 emissions using the carbon mass balance procedure in Sec. 98.183(b)(2)(i) and (ii), 100 percent data availability is required.

You must repeat the test for average carbon contents of inputs according to the procedures in Sec. 98.184(b) if data are missing.

(b) For missing records of the monthly mass of carbon-containing materials, the substitute data value must be based the best available estimate of the mass of the material from all available process data or data used for accounting purposes (such as purchase records).

Sec. 98.186 Data reporting procedures.

In addition to the information required by Sec. 98.3(c), each annual report must contain the information specified in paragraphs (a) or (b) of this section, as applicable.

(a) If a CEMS is used to measure CO2emissions according to the requirements in Sec. 98.183(a) or (b)(1), then you must report under this subpart the relevant information required by Sec. 98.36 and the information specified in paragraphs (a)(1) through (a)(4) of this section.

(1) Identification number of each smelting furnace.

(2) Annual lead product production capacity (tons).

(3) Annual production for each lead product (tons).

(4) Total number of smelting furnaces at facility used for lead production.

(b) If a CEMS is not used to measure CO2emissions, and you measure CO2emissions according to the requirements in

Sec. 98.183(b)(2)(i) and (b)(2)(ii), then you must report the information specified in paragraphs (b)(1) through (b)(9) of this section.

(1) Identification number of each smelting furnace. (2) Annual process CO2emissions (in metric tons) from each smelting furnace as determined by Equation R-1 of this subpart.

(3) Annual lead product production capacity for the facility and each smelting furnace(tons).

(4) Annual production for each lead product (tons).

(5) Total number of smelting furnaces at facility used for production of lead products reported in paragraph (b)(4) of this section.

(6) Annual material quantity for each material used for the calculation of annual process CO2emissions using Equation

R-1 of this subpart for each smelting furnace (tons).

(7) Annual average of the carbon content determinations for each material used for the calculation of annual process CO2 emissions using Equation R-1 of this subpart for each smelting furnace.

(8) List the method used for the determination of carbon content for each material reported in paragraph (b)(7) of this section (e.g., supplier provided information, analyses of representative samples you collected).

(9) If you use the missing data procedures in Sec. 98.185(b), you must report how the monthly mass of carbon-containing materials with missing data was determined and the number of months the missing data procedures were used.

Sec. 98.187 Records that must be retained.

In addition to the records required by Sec. 98.3(g), each annual report must contain the information specified in paragraphs (a) through

(a) If a CEMS is used to measure combined process and combustion

CO2emissions according to the requirements in Sec. 98.183(a) or (b)(1), then you must retain the records required for the

Tier 4 Calculation Methodology in Sec. 98.37 and the information specified in paragraphs (a)(1) through (a)(3) of this section.

(1) Monthly smelting furnace production quantity for each lead product (tons).

(2) Number of smelting furnace operating hours each month.

(3) Number of smelting furnace operating hours in calendar year.

(b) If the carbon mass balance procedure is used to determine process CO2emissions according to the requirements in Sec. 98.183(b)(2)(i) and (b)(2)(ii), then you must retain under this subpart the records specified in paragraphs (b)(1) through (b)(5) of this section.

(1) Monthly smelting furnace production quantity for each lead product (tons).

(2) Number of smelting furnace operating hours each month.

(3) Number of smelting furnace operating hours in calendar year.

(4) Monthly material quantity consumed, used, or produced for each material included for the calculations of annual process CO2 emissions using Equation R-1 of this subpart (tons).

(c) You must keep records that include a detailed explanation of how company records of measurements are used to estimate the carbon input to each smelting furnace, including documentation of any materials excluded from Equation R-1 of this subpart that contribute less than 1 percent of the total carbon into or out of the process. You also must document the procedures used to ensure the accuracy of the measurements of materials fed, charged, or placed in an smelting furnace including, but not limited to, calibration of weighing equipment and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical

Page 56441

basis for these estimates must be provided.

Sec. 98.188 Definitions.

All terms used in this subpart have the same meaning given in the

Clean Air Act and subpart A of this part.

Subpart S--Lime Manufacturing

Sec. 98.190 Definition of the source category.

(a) Lime manufacturing plants (LMPs) engage in the manufacture of a lime product (e.g., calcium oxide, high-calcium quicklime, calcium hydroxide, hydrated lime, dolomitic quicklime, dolomitic hydrate, or other products) by calcination of limestone, dolomite, shells or other cacareous substances as defined in 40 CFR 63.7081(a)(1).

(b) This source category includes all LMPs unless the LMP is located at a kraft pulp mill, soda pulp mill, sulfite pulp mill, or only processes sludge containing calcium carbonate from water softening processes. The lime manufacturing source category consists of marketed and non-marketed lime manufacturing facilities.

(c) Lime kilns at pulp and paper manufacturing facilities must report emissions under subpart AA of this part (Pulp and Paper

Manufacturing).

Sec. 98.191 Reporting threshold.

You must report GHG emissions under this subpart if your facility is a lime manufacturing plant as defined in Sec. 98.190 and the facility meets the requirements of either Sec. 98.2(a)(1) or (a)(2).

Sec. 98.192 GHGs to report.

You must report:

(a) CO2process emissions from lime kilns.

(b) CO2emissions from fuel combustion at lime kilns.

CFR part 98, subpart C (General Stationary Fuel Combustion Sources).

(d) CO2, N2O, and CH4emissions from each stationary fuel combustion unit other than lime kilns. You must report these emissions under 40 CFR part 98, subpart C (General

Stationary Fuel Combustion Sources).

(e) CO2collected and transferred off site under 40 CFR part 98, following the requirements of subpart PP of this part

(Suppliers of Carbon Dioxide (CO2)).

Sec. 98.193 Calculating GHG emissions.

You must calculate and report the annual process CO2 emissions from all lime kilns combined using the procedure in paragraphs (a) and (b) of this section.

(a) If all lime kilns meet the conditions specified in Sec. 98.33(b)(4)(ii) or (b)(4)(iii), you must calculate and report under this subpart the combined process and combustion CO2 emissions by operating and maintaining a CEMS to measure CO2 emissions according to the Tier 4 Calculation Methodology specified in

Sec. 98.33(a)(4) and all associated requirements for Tier 4 in subpart

C of this part (General Stationary Fuel Combustion Sources).

(b) If CEMS are not required to be used to determine CO2 emissions from all lime kilns under paragraph (a) of this section, then you must calculate and report the process and combustion CO2 emissions from the lime kilns by using the procedures in either paragraph (b)(1) or (b)(2) of this section.

(1) Calculate and report under this subpart the combined process and combustion CO2emissions by operating and maintaining a

CEMS to measure CO2emissions from all lime kilns according to the Tier 4 Calculation Methodology specified in Sec. 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part

(General Stationary Fuel Combustion Sources).

(2) Calculate and report process and combustion CO2 emissions separately using the procedures specified in paragraphs

(b)(2)(i) through (b)(2)(v) of this section.

(i) You must calculate a monthly emission factor for each type of lime produced using Equation S-1 of this section. Calcium oxide and magnesium oxide content must be analyzed monthly for each lime type:

GRAPHIC

TIFF OMITTED TR30OC09.073

Where:

EFLIME,i,n= Emission factor for lime type i, for month n

(metric tons CO2/ton lime).

SRCaO= Stoichiometric ratio of CO2and CaO for calcium carbonate [see Table S-1 of this subpart] (metric tons

CO2/metric tons CaO).

SRMgO= Stoichiometric ratio of CO2and MgO for magnesium carbonate (See Table S-1 of this subpart) (metric tons

CO2/metric tons MgO).

CaOi,n= Calcium oxide content for lime type i, for month n, determined according to Sec. 98.194(c) (metric tons CaO/metric ton lime).

MgOi,n= Magnesium oxide content for lime type i, for month n, determined according to Sec. 98.194(c) (metric tons MgO/ metric ton lime). 2000/2205 = Conversion factor for metric tons to tons.

(ii) You must calculate a monthly emission factor for each type of byproduct/waste sold (including lime kiln dust) using Equation S-2 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.074

Where:

EFLKD,i,n= Emission factor for sold lime byproduct/waste type i, for month n (metric tons CO2/ton lime byproduct).

SRCaO= Stoichiometric ratio of CO2and CaO for calcium carbonate (see Table S-1 of this subpart((metric tons

CO2/metric tons CaO).

SRMgO= Stoichiometric ratio of CO2and MgO for magnesium carbonate (See Table S-1 of this subpart) (metric tons

CO2/metric tons MgO).

CaOLKD,i,n= Calcium oxide content for sold lime byproduct/waste type i, for month n (metric tons CaO/metric ton lime).

MgOLKD,i,n= Magnesium oxide content for sold lime byproduct/waste type i, for month n (metric tons MgO/metric ton lime). 2000/2205 = Conversion factor for metric tons to tons.

(iii) You must calculate the annual CO2emissions from each type of byproduct/waste that is not sold (including lime kiln dust and scrubber sludge) using Equation S-3 of this section:

Page 56442

GRAPHIC

TIFF OMITTED TR30OC09.075

Where:

Ewaste,i= Annual CO2emissions for unsold lime byproduct/waste type i (metric tons CO2).

SRCaO= Stoichiometric ratio of CO2and CaO for calcium carbonate (see Table S-1 of this subpart) (metric tons

CO2/metric tons CaO).

SRMgO= Stoichiometric ratio of CO2and MgO for magnesium carbonate (See Table S-1 of this subpart) (metric tons

CO2/metric tons MgO).

CaOwaste,i= Calcium oxide content for unsold lime byproduct/waste type i (metric tons CaO/metric ton lime).

MgOwaste,i= Magnesium oxide content for unsold lime byproduct/waste type i (metric tons MgO/metric ton lime).

Mwaste,i= Annual weight or mass of unsold byproducts/ wastes for lime type i (tons). 2000/2205 = Conversion factor for metric tons to tons.

(iv) You must calculate annual CO2process emissions for all kilns using Equation S-4 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.076

Where:

ECO2= Annual CO2process emissions from lime production from all kilns (metric tons/year).

EFLIME,i,n= Emission factor for lime type i, in calendar month n (metric tons CO2/ton lime) from Equation S-1 of this section.

MLIME,i,n= Weight or mass of lime type i in calendar month n (tons).

EFLKD,i,n= Emission factor of byproducts/wastes sold for lime type i in calendar month n, (metric tons CO2/ton byproduct/waste) from Equation S-2 of this section.

MLKD,i,n= Monthly weight or mass of byproducts/waste sold (such as lime kiln dust, LKD) for lime type i in calendar month n (tons).

Ewaste,i= Annual CO2emissions for unsold lime byproduct/waste type i (metric tons CO2) from

Equation S-3 of this section. t = Number of lime types b = Number of byproducts/wastes sold z = Number of byproducts/wastes not sold

(v) Calculate and report under subpart C of this part (General

Stationary Fuel Combustion Sources) the combustion CO2 emissions from each lime kiln according to the applicable requirements in subpart C.

Sec. 98.194 Monitoring and QA/QC requirements.

(a) You must determine the total quantity of each product type of lime and each calcined byproduct/waste (such as lime kiln dust) that is sold. The quantities of each should be directly measured monthly with the same plant instruments used for accounting purposes, including but not limited to, calibrated weigh feeders, rail or truck scales, and barge measurements. The direct measurements of each lime product shall be reconciled annually with the difference in the beginning of and end of year inventories for these products, when measurements represent lime sold.

(b) You must determine the annual quantity of each calcined byproduct/waste generated that is not sold by either direct measurement using the same instruments identified in paragraph (a) of this section or by using a calcined byproduct/waste generation rate.

(c) You must determine the chemical composition (percent total CaO and percent total MgO) of each type of lime and each type of calcined byproduct/waste sold according to paragraph (c)(1) or (c)(2) of this section. You must determine the chemical composition of each type of lime on a monthly basis. You must determine the chemical composition for each type of calcined byproduct/waste that is not sold on an annual basis.

(1) ASTM C25-06 Standard Test Methods for Chemical Analysis of

Limestone, Quicklime, and Hydrated Lime (incorporated by reference--see

Sec. 98.7).

(2) The National Lime Association's CO2Emissions

Calculation Protocol for the Lime Industry English Units Version,

February 5, 2008 Revision-National Lime Association (incorporated by reference--see Sec. 98.7).

(d) You must use the analysis of calcium oxide and magnesium oxide content of each lime product collected during the same month as the production data in monthly calculations.

(e) You must follow the quality assurance/quality control procedures (including documentation) in National Lime Association's

CO2Emissions Calculation Protocol for the Lime Industry

English Units Version, February 5, 2008 Revision--National Lime

Association (incorporated by reference--see Sec. 98.7).

Sec. 98.195 Procedures for estimating missing data.

For the procedure in Sec. 98.193(b)(2), a complete record of all measured parameters used in the GHG emissions calculations is required

(e.g., oxide content, quantity of lime products, etc.). Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in paragraphs (a) or (b) of this section. You must document and keep records of the procedures used for all such estimates.

(a) For each missing value of the quantity of lime produced (by lime type), and quantity of byproduct/waste produced and sold, the substitute data value shall be the best available estimate based on all available process data or data used for accounting purposes.

(b) For missing values related to the CaO and MgO content, you must conduct a new composition test according to the standard methods in

Sec. 98.194 (c)(1) or (c)(2).

Sec. 98.196 Data reporting requirements.

In addition to the information required by Sec. 98.3(c), each annual report must contain the information specified in paragraphs (a) or (b) of this section, as applicable.

(a) If a CEMS is used to measure CO2emissions, then you must report under this subpart the relevant information required by

Sec. 98.36 and the information listed in paragraphs (a)(1) through

(a)(8) of this section.

(1) Method used to determine the quantity of lime sold.

(2) Method used to determine the quantity of lime byproduct/waste sold.

(3) Beginning and end of year inventories for each lime product.

(4) Beginning and end of year inventories for lime byproducts/ wastes.

Page 56443

(5) Annual amount of lime byproduct/waste sold, by type (tons).

(6) Annual amount of lime product sold, by type (tons).

(7) Annual amount of lime byproduct/waste not sold, by type (tons).

(8) Annual amount of lime product not sold, by type (tons).

(b) If a CEMS is not used to measure CO2emissions, then you must report the information listed in paragraphs (b)(1) through

(b)(17) of this section.

(1) Annual CO2process emissions from all kilns combined

(metric tons).

(2) Monthly emission factors for each lime type.

(3) Monthly emission factors for each sold byproduct/waste by lime type.

(4) Standard method used (ASTM or NLA testing method) to determine chemical compositions of each lime type and lime byproduct/waste type.

(5) Monthly results of chemical composition analysis of each lime product and byproduct/waste sold.

(6) Annual results of chemical composition analysis of each type of lime byproduct/waste not sold.

(7) Method used to determine the quantity of lime sold.

(8) Monthly amount of lime product sold, by type (tons).

(9) Method used to determine the quantity of lime byproduct/waste sold.

(10) Monthly amount of lime byproduct/waste sold, by type (tons).

(11) Annual amount of lime byproduct/waste not sold (tons).

(12) Monthly mass of each lime type produced (tons).

(13) Beginning and end of year inventories for each lime product.

(14) Beginning and end of year inventories for lime byproducts/ wastes.

(15) Annual lime production capacity (tons) per facility.

(16) Number of times in the reporting year that missing data procedures were followed to measure lime production (months) or the chemical composition of lime products sold (months).

(17) Indicate whether CO2was used on-site (i.e. for use in a purification process). If CO2was used on-site, provide the information in paragraphs (b)(17)(i) and (b)(17)(ii) of this section.

(i) The annual amount of CO2captured for use in the on- site process.

(ii) The method used to determine the amount of CO2 captured.

Sec. 98.197 Records that must be retained.

In addition to the records required by Sec. 98.3(g), you must retain the records specified in paragraphs (a) and (b) of this section.

(a) Annual operating hours in calendar year.

(b) Records of all analyses (e.g. chemical composition of lime products, by type) and calculations conducted.

Sec. 98.198 Definitions.

All terms used in this subpart have the same meaning given in the

Clean Air Act and subpart A of this part.

Table S-1 to Subpart S of Part 98--Basic Parameters for the Calculation of Emission Factors for Lime Production

Stoichiometric

Variable

ratio

SRCaO................................................

0.7848

SRMgO................................................

1.0918

Subpart T--[Reserved]

Subpart U--Miscellaneous Uses of Carbonate

Sec. 98.210 Definition of the source category.

(a) This source category includes any equipment that uses carbonates listed in Table U-1 in manufacturing processes that emit carbon dioxide. Table U-1 includes the following carbonates: limestone, dolomite, ankerite, magnesite, siderite, rhodochrosite, or sodium carbonate. Facilities are considered to emit CO2if they consume at least 2,000 tons per year of carbonates heated to a temperature sufficient to allow the calcination reaction to occur.

(b) This source category does not include equipment that uses carbonates or carbonate containing minerals that are consumed in the production of cement, glass, ferroalloys, iron and steel, lead, lime, phosphoric acid, pulp and paper, soda ash, sodium bicarbonate, sodium hydroxide, or zinc.

(c) This source category does not include carbonates used in sorbent technology used to control emissions from stationary fuel combustion equipment. Emissions from carbonates used in sorbent technology are reported under 40 CFR 98, subpart C (Stationary Fuel

Combustion Sources).

Sec. 98.211 Reporting threshold.

You must report GHG emissions from miscellaneous uses of carbonate if your facility uses carbonates as defined in Sec. 98.210 of this subpart and the facility meets the requirements of either Sec. 98.2(a)(1) or (a)(2).

Sec. 98.212 GHGs to report.

You must report CO2process emissions from all miscellaneous carbonate use at your facility as specified in this subpart.

Sec. 98.213 Calculating GHG emissions.

You must determine CO2process emissions from carbonate use in accordance with the procedures specified in either paragraphs

(a) or (b) of this section.

(a) Calculate the process emissions of CO2using calcination fractions with Equation U-1 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.077

Where:

ECO2= Annual CO2mass emissions from consumption of carbonates (metric tons).

Mi= Annual mass of carbonate type i consumed (tons).

EFi= Emission factor for the carbonate type i, as specified in Table U-1 to this subpart, metric tons CO2/ metric ton carbonate consumed.

Fi= Fraction calcination achieved for each particular carbonate type i (decimal fraction). As an alternative to measuring the calcination fraction, a value of 1.0 can be used. n = Number of carbonate types. 2000/2205 = Conversion factor to convert tons to metric tons.

(b) Calculate the process emissions of CO2using actual mass of output carbonates with Equation U-2 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.078

Page 56444

Where:

ECO2= Annual CO2mass emissions from consumption of carbonates (metric tons).

Mk= Annual mass of input carbonate type k (tons).

EFk= Emission factor for the carbonate type k, as specified in Table U-1 of this subpart (metric tons CO2/ metric ton carbonate input).

Mj= Annual mass of output carbonate type j (tons).

EFj= Emission factor for the output carbonate type j, as specified in Table U-1 of this subpart (metric tons CO2/ metric ton carbonate input). m = Number of input carbonate types. n = Number of output carbonate types.

Sec. 98.214 Monitoring and QA/QC requirements.

(a) The annual mass of carbonate consumed (for Equation U-1 of this subpart) or carbonate inputs (for Equation U-2 of this subpart) must be determined annually from monthly measurements using the same plant instruments used for accounting purposes including purchase records or direct measurement, such as weigh hoppers or weigh belt feeders.

(b) The annual mass of carbonate outputs (for Equation U-2 of this subpart) must be determined annually from monthly measurements using the same plant instruments used for accounting purposes including purchase records or direct measurement, such as weigh hoppers or belt weigh feeders.

(c) If you follow the procedures of Sec. 98.213(a), as an alternative to assuming a calcination fraction of 1.0, you can determine on an annual basis the calcination fraction for each carbonate consumed based on sampling and chemical analysis using a suitable method such as using an x-ray fluorescence standard method or other enhanced industry consensus standard method published by an industry consensus standard organization (e.g., ASTM, ASME, etc.).

Sec. 98.215 Procedures for estimating missing data.

(a) A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality- assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in paragraph (b) of this section. You must document and keep records of the procedures used for all such estimates.

(b) For each missing value of monthly carbonate consumed, monthly carbonate output, or monthly carbonate input, the substitute data value must be the best available estimate based on the all available process data or data used for accounting purposes.

Sec. 98.216 Data reporting requirements.

In addition to the information required by Sec. 98.3(c), each annual report must contain the information specified in paragraphs (a) through (g) of this section at the facility level, as applicable.

(a) Annual CO2emissions from miscellaneous carbonate use (metric tons).

(b) Annual mass of each carbonate type consumed (tons).

(d) Method used to calculate emissions.

(e) If you followed the calculation method of Sec. 98.213(b)(1)(i), you must report the information in paragraphs (e)(1) through (e)(3) of this section.

(1) Annual carbonate consumption by carbonate type (tons).

(2) Annual calcination fractions used in calculations.

(3) If you determined the calcination fraction, indicate which standard method was used.

(f) If you followed the calculation method of Sec. 98.213(b)(1)(ii), you must report the information in paragraphs (f)(1) and (f)(2) of this section.

(1) Annual carbonate input by carbonate type (tons).

(2) Annual carbonate output by carbonate type (tons).

(g) Number of times in the reporting year that missing data procedures were followed to measure carbonate consumption, carbonate input or carbonate output (months).

Sec. 98.217 Records that must be retained.

In addition to the records required by Sec. 98.3(g), you must retain the records specified in paragraphs (a) through (d) of this section:

(a) Monthly carbonate consumption (by carbonate type in tons).

(b) You must document the procedures used to ensure the accuracy of the monthly measurements of carbonate consumption, carbonate input or carbonate output including, but not limited to, calibration of weighing equipment and other measurement devices.

(d) Records of all calculations conducted.

Sec. 98.218 Definitions.

All terms used in this subpart have the same meaning given in the

Clean Air Act and subpart A of this part.

Table U-1 to Subpart U of Part 98--CO2 Emission Factors for Common

Carbonates

CO2 emission factor

Mineral name--carbonate

(tons CO2/ ton carbonate)

Limestone--CaCO3...........................................

0.43971

Magnesite--MgCO3...........................................

0.52197

Dolomite--CaMg(CO3)2.......................................

0.47732

Siderite--FeCO3............................................

0.37987

Ankerite--Ca(Fe, Mg, Mn)(CO3)2.............................

0.47572

Rhodochrosite--MnCO3.......................................

0.38286

Sodium Carbonate/Soda Ash--Na2CO3..........................

0.41492

Subpart V--Nitric Acid Production

Sec. 98.220 Definition of source category.

A nitric acid production facility uses one or more trains to produce weak nitric acid (30 to 70 percent in strength). A nitric acid train produces weak nitric acid through the catalytic oxidation of ammonia.

Sec. 98.221 Reporting threshold.

You must report GHG emissions under this subpart if your facility contains a nitric acid train and the facility meets the requirements of either Sec. 98.2(a)(1) or (a)(2).

Sec. 98.222 GHGs to report.

(a) You must report N2O process emissions from each nitric acid production train as required by this subpart.

(b) You must report under subpart C of this part (General

Stationary Fuel Combustion Sources) the emissions of CO2,

CH4, and N2O from each stationary combustion unit by following the requirements of subpart C.

Sec. 98.223 Calculating GHG emissions.

(a) You must determine annual N2O process emissions from each nitric acid train according to paragraphs (a)(1) or (a)(2) of this section.

(1) Use a site-specific emission factor and production data according to paragraphs (b) through (h) of this section.

(2) Request Administrator approval for an alternative method of determining N2O emissions according to paragraphs (a)(2)(i) and (a)(2)(ii) of this section.

(i) You must submit the request within 45 days following promulgation of this subpart or within the first 30 days of each subsequent reporting year.

(ii) If the Administrator does not approve your requested alternative method within 150 days of the end of the reporting year, you must determine the N2O emissions factor for the current

Page 56445

reporting period using the procedures specified in paragraph (a)(1) of this section.

(b) You must conduct an annual performance test according to paragraphs (b)(1) through (b)(3) of this section.

(1) You must measure N2O emissions from the absorber tail gas vent for each nitric acid train using the methods specified in

Sec. 98.224(b) through (d).

(2) You must conduct the performance test under normal process operating conditions and without using N2O abatement technology (if applicable).

(3) You must measure the production rate during the performance test and calculate the production rate for the test period in metric tons (100 percent acid basis) per hour.

Equation V-3 of this section according to paragraphs (c)(1) or (c)(2) of this section.

(1) You may request Administrator approval for an alternative method of determining N2O concentration according to the procedures in paragraphs (a)(2)(i) and (a)(2)(ii) of this section.

Alternative methods include the use of N2O CEMs.

(2) Using the results of the performance test in paragraph (b) of this section, you must calculate an average site-specific emission factor for each nitric acid train ``t'' according to Equation V-1 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.079

Where:

EFN2Ot= Average site-specific N2O emissions factor for nitric acid train ``t'' (lb N2O generated/ton nitric acid produced, 100 percent acid basis).

CN2O= N2O concentration for each test run during the performance test (ppm N2O). 1.14 x 10-7= Conversion factor (lb/dscf-ppm

N2O).

Q = Volumetric flow rate of effluent gas for each test run during the performance test (dscf/hr).

P = Production rate for each test run during the performance test

(tons nitric acid produced per hour, 100 percent acid basis). n = Number of test runs.

(d) If applicable, you must determine the destruction efficiency for each N2O abatement technology according to paragraphs

(d)(1), (d)(2), or (d)(3) of this section.

(1) Use the manufacturer's specified destruction efficiency.

(2) Estimate the destruction efficiency through process knowledge.

(if applicable) was used to determine the destruction efficiency.

(3) Calculate the destruction efficiency by conducting an additional performance test on the emissions stream following the

N2O abatement technology.

(e) If applicable, you must determine the abatement factor for each

N2O abatement technology. The abatement factor is calculated for each nitric acid train according to Equation V-2 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.080

Where:

AFN t= Abatement factor of N2O abatement technology at nitric acid train ``t'' (fraction of annual production that abatement technology is operating).

Pa t= Total annual nitric acid production from nitric acid train ``t'' (ton acid produced, 100 percent acid basis).

Pa t Abate= Annual nitric acid production from nitric acid train ``t'' during which N2O abatement was used (ton acid produced, 100 percent acid basis).

(f) You must determine the annual amount of nitric acid produced and the annual amount of nitric acid produced while each N2O abatement technology is operating from each nitric acid train (100 percent basis).

(g) You must calculate N2O emissions for each nitric acid train by multiplying the emissions factor (determined in Equation

V-1 of this section) by the annual nitric acid production and accounting for N2O abatement, according to Equation V-3 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.081

Where:

EN2Ot= N2O mass emissions per year for nitric acid train ``t'' (metric tons).

EFN2Ot= Average site-specific N2O emissions factor for nitric acid train ``t'' (lb N2O generated/ton acid produced, 100 percent acid basis).

Pa t= Annual nitric acid production from the train ``t''

(ton acid produced, 100 percent acid basis).

DFN t= Destruction efficiency of N2O abatement technology N that is used on nitric acid train ``t''

(percent of N2O removed from air stream).

AFN t= Abatement factor of N2O abatement technology for nitric acid train ``t'' (fraction of annual production that abatement technology is operating). 2204.63 = Conversion factor (lb/metric ton). z = Number of different N2O abatement technologies.

(h) You must determine the annual nitric acid production emissions combined from all nitric acid trains at your facility using Equation V- 4 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.082

Page 56446

Where:

N2O = Annual process N2O emissions from nitric acid production facility (metric tons).

EN2Ot= N2O mass emissions per year for nitric acid train ``t'' (metric tons). m = Number of nitric acid trains.

Sec. 98.224 Monitoring and QA/QC requirements.

(a) You must conduct a new performance test and calculate a new site-specific emissions factor according to a test plan as specified in paragraphs (a)(1) through (a)(3) of this section.

(1) Conduct the performance test annually.

(2) Conduct the performance test when your nitric acid production process is changed, specifically when abatement equipment is installed.

(3) If you requested Administrator approval for an alternative method of determining N2O concentration under Sec. 98.223(a)(2), you must conduct the performance test if your request has not been approved by the Administrator within 150 days of the end of the reporting year in which it was submitted.

(b) You must measure the N2O concentration during the performance test using one of the methods in paragraphs (b)(1) through

(b)(3) of this section.

(1) EPA Method 320 at 40 CFR part 63, appendix A, Measurement of

Vapor Phase Organic and Inorganic Emissions by Extractive Fourier

Transform Infrared (FTIR) Spectroscopy.

(2) ASTM D6348-03 Standard Test Method for Determination of Gaseous

Compounds by Extractive Direct Interface Fourier Transform Infrared

(FTIR) Spectroscopy (incorporated by reference in Sec. 98.7).

(3) An equivalent method, with Administrator approval.

(c) You must determine the production rate(s) (100 percent basis) from each nitric acid train during the performance test according to paragraphs (c)(1) or (c)(2) of this section.

(1) Direct measurement of production and concentration (such as using flow meters, weigh scales, for production and concentration measurements).

(2) Existing plant procedures used for accounting purposes (i.e. dedicated tank-level and acid concentration measurements).

(d) You must conduct all performance tests in conjunction with the applicable EPA methods in 40 CFR part 60, appendices A-1 through A-4.

Conduct three emissions test runs of 1 hour each. All QA/QC procedures specified in the reference test methods and any associated performance specifications apply. For each test, the facility must prepare an emission factor determination report that must include the items in paragraphs (d)(1) through (d)(3) of this section.

(1) Analysis of samples, determination of emissions, and raw data.

(2) All information and data used to derive the emissions factor(s).

(3) The production rate during each test and how it was determined.

(e) You must determine the monthly nitric acid production and the monthly nitric acid production during which N2O abatement technology is operating from each nitric acid train according to the methods in paragraphs (c)(1) or (c)(2) of this section.

(f) You must determine the annual nitric acid production and the annual nitric acid production during which N2O abatement technology is operating for each train by summing the respective monthly nitric acid production quantities.

Sec. 98.225 Procedures for estimating missing data.

(a) For each missing value of nitric acid production, the substitute data shall be the best available estimate based on all available process data or data used for accounting purposes (such as sales records).

(b) For missing values related to the performance test, including emission factors, production rate, and N2O concentration, you must conduct a new performance test according to the procedures in

Sec. 98.224 (a) through (d).

Sec. 98.226 Data reporting requirements.

In addition to the information required by Sec. 98.3(c), each annual report must contain the information specified in paragraphs (a) through (o) of this section for each nitric acid production train.

(a) Train identification number.

(b) Annual process N2O emissions from each nitric acid train (metric tons).

(tons, 100 percent acid basis).

(d) Annual nitric acid production from each nitric acid train during which N2O abatement technology is operating (ton acid produced, 100 percent acid basis).

(e) Annual nitric acid production from the nitric acid facility

(tons, 100 percent acid basis).

(f) Number of nitric acid trains.

(g) Number of abatement technologies (if applicable).

(h) Abatement technologies used (if applicable).

(i) Abatement technology destruction efficiency for each abatement technology (percent destruction).

(j) Abatement utilization factor for each abatement technology

(fraction of annual production that abatement technology is operating).

(k) Type of nitric acid process used for each nitric acid train

(low, medium, high, or dual pressure).

(l) Number of times in the reporting year that missing data procedures were followed to measure nitric acid production (months).

(m) If you conducted a performance test and calculated a site- specific emissions factor according to Sec. 98.223(a)(1), each annual report must also contain the information specified in paragraphs (m)(1) through (m)(7) of this section for each nitric acid production facility.

(1) Emission factor calculated for each nitric acid train (lb

N2O/ton nitric acid, 100 percent acid basis).

(2) Test method used for performance test.

(3) Production rate per test run during performance test (tons nitric acid produced/hr, 100 percent acid basis).

(4) N2O concentration per test run during performance test (ppm N2O).

(5) Volumetric flow rate per test run during performance test

(dscf/hr).

(6) Number of test runs during performance test.

(7) Number of times in the reporting year that a performance test had to be repeated (number).

(n) If you requested Administrator approval for an alternative method of determining N2O concentration under Sec. 98.223(a)(2), each annual report must also contain the information specified in paragraphs (n)(1) through (n)(4) of this section for each nitric acid production facility.

(1) Name of alternative method.

(2) Description of alternative method.

(3) Request date.

(4) Approval date.

(o) Total pounds of synthetic fertilizer produced through and total nitrogen contained in that fertilizer.

Sec. 98.227 Records that must be retained.

In addition to the information required by Sec. 98.3(g), you must retain the records specified in paragraphs (a) through (g) of this section for each nitric acid production facility:

Page 56447

(a) Records of significant changes to process.

(b) Documentation of how process knowledge was used to estimate abatement technology destruction efficiency (if applicable).

(d) Number of operating hours in the calendar year for each nitric acid train (hours).

(e) Annual nitric acid permitted production capacity (tons).

(f) Measurements, records, and calculations used to determine reported parameters.

(g) Documentation of the procedures used to ensure the accuracy of the measurements of all reported parameters, including but not limited to, calibration of weighing equipment, flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided.

Sec. 98.228 Definitions.

All terms used in this subpart have the same meaning given in the

Clean Air Act and subpart A of this part.

Subpart W--[Reserved]

Subpart X--Petrochemical Production

Sec. 98.240 Definition of the source category.

(a) The petrochemical production source category consists of all processes that produce acrylonitrile, carbon black, ethylene, ethylene dichloride, ethylene oxide, or methanol, except as specified in paragraphs (b) through (f) of this section. The source category includes processes that produce the petrochemical as an intermediate in the onsite production of other chemicals as well as processes that produce the petrochemical as an end product for sale or shipment offsite.

(b) A process that produces a petrochemical as a byproduct is not part of the petrochemical production source category.

(c) A facility that makes methanol, hydrogen, and/or ammonia from synthesis gas is part of the petrochemical source category if the annual mass of methanol produced exceeds the individual annual mass production levels of both hydrogen recovered as product and ammonia.

The facility is part of subpart P of this part (Hydrogen Production) if the annual mass of hydrogen recovered as product exceeds the individual annual mass production levels of both methanol and ammonia. The facility is part of subpart G of this part (Ammonia Manufacturing) if the annual mass of ammonia produced exceeds the individual annual mass production levels of both hydrogen recovered as product and methanol.

(d) A direct chlorination process that is operated independently of an oxychlorination process to produce ethylene dichloride is not part of the petrochemical production source category.

(e) A process that produces bone black is not part of the petrochemical source category.

(f) A process that produces a petrochemical from bio-based feedstock is not part of the petrochemical production source category.

Sec. 98.241 Reporting threshold.

You must report GHG emissions under this subpart if your facility contains a petrochemical process as specified in Sec. 98.240, and the facility meets the requirements of either Sec. 98.2(a)(1) or (2).

Sec. 98.242 GHGs to report.

You must report the information in paragraphs (a) through (c) of this section:

(a) CO2CH4, and N2O process emissions from each petrochemical process unit. Process emissions include CO2generated by reaction in the process and by combustion of process off-gas in stationary combustion units and flares.

(1) If you comply with Sec. 98.243(b) or (d), report under this subpart the calculated CO2, CH4, and

N2O emissions for each stationary combustion source and flare that burns any amount of petrochemical process off-gas.

(2) If you comply with Sec. 98.243(c), report under this subpart the calculated CO2emissions for each petrochemical process unit.

(b) CO2, CH4, and N2O combustion emissions from stationary combustion units and flares.

(1) If you comply with Sec. 98.243(b) or (d), report these emissions from stationary combustion units that are associated with petrochemical process units and burn only supplemental fuel under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.

(2) If you comply with Sec. 98.243(c), report CO2,

CH4, and N2O combustion emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C only for the combustion of supplemental fuel. Determine the applicable Tier in subpart C of this part (General

Stationary Fuel Combustion Sources) based on the maximum rated heat input capacity of the stationary combustion source.

CO2captured under, subpart PP of this part (Suppliers of

Carbon Dioxide (CO2) by following the requirements of subpart PP.

Sec. 98.243 Calculating GHG emissions.

(a) If you route all process vent emissions and emissions from combustion of process off-gas to one or more stacks and use CEMS on each stack to measure CO2emissions (except flare stacks), then you must determine process-based GHG emissions in accordance with paragraph (b) of this section. Otherwise, determine process-based GHG emissions in accordance with the procedures specified in paragraph (c) or (d) of this section.

(b) Continuous emission monitoring system (CEMS). Route all process vent emissions and emissions from combustion of process off-gas to one or more stacks and determine CO2emissions from each stack

(except flare stacks) according to the Tier 4 Calculation Methodology requirements in subpart C of this part. For each stack (except flare stacks) that includes emissions from combustion of petrochemical process off-gas, calculate CH4and N2O emissions in accordance with subpart C of this part (use the Tier 3 methodology and emission factors for ``Petroleum'' in Table C-2 of subpart C of this part). For each flare, calculate CO2, CH4, and N2O emissions using the methodology specified in Sec. 98.253(b)(1) through (b)(3).

(c) Mass balance for each petrochemical process unit. Calculate the emissions of CO2from each process unit, for each calendar month as described in paragraphs (c)(1) through (c)(5) of this section.

(1) For each gaseous and liquid feedstock and product, measure the volume or mass used or produced each calendar month with a flow meter by following the procedures specified in Sec. 98.244(b)(2).

Alternatively, for liquids, you may calculate the volume used or collected in each month based on measurements of the liquid level in a storage tank at least once per month (and just prior to each change in direction of the level of the liquid) following the procedures specified in Sec. 98.244(b)(3). Fuels used for combustion purposes are not considered to be feedstocks.

(2) For each solid feedstock and product, measure the mass used or produced each calendar month by following the procedures specified in

Sec. 98.244(b)(1).

(3) Collect a sample of each feedstock and product at least once per month and determine the carbon content of each

Page 56448

sample according to the procedures in Sec. 98.244(b)(4).

Alternatively, you may use the results of analyses conducted by a fuel or feedstock supplier, provided the sampling and analysis are conducted at least once per month using any of the procedures specified in Sec. 98.244(b)(4). If multiple valid carbon content measurements are made during the monthly measurement period, average them arithmetically.

(4) If you determine that the monthly average concentration of a specific compound in a feedstock or product is greater than 99.5 percent by volume (or mass for liquids and solids), then as an alternative to the sampling and analysis specified in paragraph (c)(3) of this section, you may calculate the carbon content assuming 100 percent of that feedstock or product is the specific compound during periods of normal operation. You must maintain records of any determination made in accordance with this paragraph (c)(4) along with all supporting data, calculations, and other information. This alternative may not be used for products during periods of operation when off-specification product is produced. You must reevaluate determinations made under this paragraph (c)(4) after any process change that affects the feedstock or product composition. You must keep records of the process change and the corresponding composition determinations. If the feedstock or product composition changes so that the average monthly concentration falls below 99.5 percent, you are no longer permitted to use this alternative method.

(5) Calculate the CO2mass emissions for each petrochemical process unit using Equations X-1 through X-4 of this section.

(i) Gaseous feedstocks and products. Use Equation X-1 of this section to calculate the net annual carbon input or output from gaseous feedstocks and products. Note that the result will be a negative value if there are no gaseous feedstocks in the process but there are gaseous products.

GRAPHIC

TIFF OMITTED TR30OC09.083

Where:

Cg= Annual net contribution to calculated emissions from carbon (C) in gaseous materials (kilograms/year, kg/yr).

(Fgf)i,n= Volume of gaseous feedstock i introduced in month ``n'' (standard cubic feet, scf).

(CCgf)i,n= Average carbon content of the gaseous feedstock i for month ``n'' (kg C per kg of feedstock).

(MWf)i= Molecular weight of gaseous feedstock i (kg/kg-mole).

MVC = Molar volume conversion factor (849.5 scf per kg-mole at standard conditions).

(Pgp)i,n= Volume of gaseous product i produced in month ``n'' (scf).

(CCgp)i,n= Average carbon content of gaseous product i, including streams containing CO2recovered for sale or use in another process, for month ``n'' (kg C per kg of product).

(MWp)i= Molecular weight of gaseous product i

(kg/kg-mole). j = Number of feedstocks. k = Number of products.

(ii) Liquid feedstocks and products. Use Equation X-2 of this section to calculate the net carbon input or output from liquid feedstocks and products. Note that the result will be a negative value if there are no liquid feedstocks in the process but there are liquid products.

GRAPHIC

TIFF OMITTED TR30OC09.084

Where:

Cl= Annual net contribution to calculated emissions from carbon in liquid materials, including liquid organic wastes (kg/yr).

(Flf)i,n= Volume or mass of liquid feedstock i introduced in month ``n'' (gallons or kg).

(CClf)i,n= Average carbon content of liquid feedstock i for month ``n'' (kg C per gallon or kg of feedstock).

(Plp)i,n= Volume or mass of liquid product i produced in month ``n'' (gallons or kg).

(CClp)i,n= Average carbon content of liquid product i, including organic liquid wastes, for month ``n'' (kg C per gallon or kg of product). j = Number of feedstocks. k = Number of products.

(iii) Solid feedstocks and products. Use Equation X-3 of this section to calculate the net annual carbon input or output from solid feedstocks and products. Note that the result will be a negative value if there are no solid feedstocks in the process but there are solid products.

GRAPHIC

TIFF OMITTED TR30OC09.085

Where:

Cs= Annual net contribution to calculated emissions from carbon in solid materials (kg/yr).

(Fsf)i,n= Mass of solid feedstock i introduced in month ``n'' (kg).

(CCsf)i,n= Average carbon content of solid feedstock i for month ``n'' (kg C per kg of feedstock).

(Psp)i,n= Mass of solid product i produced in month ``n'' (kg).

(CCsp)i,n= Average carbon content of solid product i in month ``n'' (kg C per kg of product). j = Number of feedstocks. k = Number of products.

(iv) Annual emissions. Use the results from Equations X-1 through

X-3 of this section, as applicable, in Equation X-4 of this section to calculate annual CO2emissions.

Page 56449

GRAPHIC

TIFF OMITTED TR30OC09.086

Where:

CO2= Annual CO2mass emissions from process operations and process off-gas combustion (metric tons/year). 0.001 = Conversion factor from kg to metric tons. 44 = Molecular weight of CO2(kg/kg-mole). 12 = Atomic weight of carbon (C) (kg/kg-mole).

(d) Optional combustion methodology for ethylene production processes. For any ethylene production process, calculate

CO2emissions from combustion of fuel that contains ethylene process off-gas using the Tier 3 or Tier 4 methodology in subpart C of this part, and calculate CH4and N2O emissions using the applicable procedures in Sec. 98.33(c) (use the emission factors for ``Petroleum'' in Table C-2 of subpart C of this part

(General Stationary Fuel Combustion Sources)). You are not required to use the same Tier for each stationary combustion unit that burns ethylene process off-gas. For each flare, calculate CO2,

CH4, and N2O emissions using the methodology specified in Sec. 98.253(b)(1) through (b)(3).

Sec. 98.244 Monitoring and QA/QC requirements.

(a) If you use CEMS to determine emissions from process vents, you must comply with the procedures specified in Sec. 98.34(c).

(b) If you use the mass balance methodology in Sec. 98.243(c), use the procedures specified in paragraphs (b)(1) through (b)(4) of this section to determine feedstock and product flows and carbon contents.

(1) Operate and maintain belt scales or other weighing devices as described in Specifications, Tolerances, and Other Technical

Requirements For Weighing and Measuring Devices NIST Handbook 44 (2009)

(incorporated by reference, see Sec. 98.7) or follow procedures specified by the measurement device manufacturer. Calibrate the measurement device according to the procedures specified by the method, the procedures specified by the manufacturer, or Sec. 98.3(i).

Recalibrate either biennially or at the minimum frequency specified by the manufacturer.

(2) Operate and maintain all flow meters for gas and liquid feedstocks and products by following the procedures in Sec. 98.3(i) and using any of the flow meter methods specified in paragraphs

(b)(2)(i) through (b)(2)(xv) of this section, as applicable, use a standard method published by a consensus-based standards organization

(e.g., ASTM, API, etc.), or follow procedures specified by the flow meter manufacturer or Sec. 98.3(i). Recalibrate each flow meter either biennially or at the minimum frequency specified by the manufacturer.

(i) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using

Orifice, Nozzle, and Venturi (incorporated by reference, see Sec. 98.7).

(ii) ASME MFC-4M-1986 (Reaffirmed 1997) Measurement of Gas Flow by

Turbine Meters (incorporated by reference, see Sec. 98.7).

(iii) ASME MFC-5M-1985 (Reaffirmed 1994) Measurement of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flowmeters

(incorporated by reference, see Sec. 98.7).

(iv) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using

Vortex Flowmeters (incorporated by reference, see Sec. 98.7).

(v) ASME MFC-7M-1987 (Reaffirmed 1992) Measurement of Gas Flow by

Means of Critical Flow Venturi Nozzles (incorporated by reference, see

Sec. 98.7).

(vi) ASME MFC-9M-1988 (Reaffirmed 2001) Measurement of Liquid Flow in Closed Conduits by Weighing Method (incorporated by reference, see

Sec. 98.7).

(vii) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of

Coriolis Mass Flowmeters (incorporated by reference, see Sec. 98.7).

(viii) ASME MFC-14M-2003 (Reaffirmed 2008), Measurement of Fluid

Flow Using Small Bore Precision Orifice Meters (incorporated by reference, see Sec. 98.7).

(ix) ASME MFC-16-2007 Measurement of Liquid Flow in Closed Conduits with Electromagnetic Flowmeters (incorporated by reference, see Sec. 98.7).

(x) ASME MFC-18M-2001 (Reaffirmed 2006), Measurement of Fluid Flow

Using Variable Area Meters (incorporated by reference, see Sec. 98.7).

(xi) ASME MFC-22-2007 Measurement of Liquid by Turbine Flowmeters

(incorporated by reference, see Sec. 98.7).

(xii) AGA Report No. 3: Orifice Metering of Natural Gas and Other

Related Hydrocarbon Fluids, Part 1: General Equations and Uncertainty

Guidelines (1990), Part 2: Specification and Installation Requirements

(2000) (incorporated by reference, see Sec. 98.7).

(xiii) AGA Transmission Measurement Committee Report No. 7:

Measurement of Natural Gas by Turbine Meter (2006)/February

(incorporated by reference, see Sec. 98.7).

(xiv) AGA Report No. 11: Measurement of Natural Gas by Coriolis

Meter (2003) (incorporated by reference, see Sec. 98.7).

(xv) ISO 8316: Measurement of Liquid Flow in Closed Conduits--

Method by Collection of the Liquid in a Volumetric Tank (1987-10-01)

First Edition (incorporated by reference, see Sec. 98.7).

(3) Perform tank level measurements (if used to determine feedstock or product flows) according to any standard method published by a consensus-based standards organization (e.g., ASTM, API, etc.) or follow procedures specified by the measurement device manufacturer or

Sec. 98.3(i). Calibrate the measurement devices prior to the effective date of the rule, and recalibrate either biennially or at the minimum frequency specified by the manufacturer or Sec. 98.3(i).

(4) Use any of the standard methods specified in paragraphs

(b)(4)(i) through (b)(4)(x) of this section, as applicable, to determine the carbon content or composition of feedstocks and products and the average molecular weight of gaseous feedstocks and products.

Calibrate instruments in accordance with the method and as specified in paragraphs (b)(4)(i) through (b)(4)(x), as applicable. For coal used as a feedstock, the samples for carbon content determinations shall be taken at a location that is representative of the coal feedstock used during the corresponding monthly period. For carbon black products, samples shall be taken of each grade or type of product produced during the monthly period. Samples of coal feedstock or carbon black product for carbon content determinations may be either grab samples collected and analyzed monthly or a composite of samples collected more frequently and analyzed monthly. Analyses conducted in accordance with methods specified in paragraphs (b)(4)(i) through (b)(4)(x) of this section may be performed by the owner or operator, by an indpendent laboratory, or by the supplier of a feedstock.

(i) ASTM D1945-03, Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see Sec. 98.7).

(ii) ASTM D6060-96 (Reapproved 2001) Standard Practice for Sampling of Process Vents With a Portable Gas

Page 56450

Chromatograph (incorporated by reference, see Sec. 98.7).

(iii) ASTM D2505-88(Reapproved 2004)e1 Standard Test Method for

Ethylene, Other Hydrocarbons, and Carbon Dioxide in High-Purity

Ethylene by Gas Chromatography (incorporated by reference, see Sec. 98.7).

(iv) ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography

(incorporated by reference, see Sec. 98.7).

(v) ASTM D3176-89 (Reapproved 2002) Standard Practice Method for

Ultimate Analysis of Coal and Coke (incorporated by reference, see

Sec. 98.7).

(vi) ASTM D5291-02 (Reapproved 2007) Standard Test Methods for

Instrumental Determination of Carbon, Hydrogen, and Nitrogen in

Petroleum Products and Lubricants (incorporated by reference, see Sec. 98.7).

(vii) ASTM D5373-08 Standard Test Methods for Instrumental

Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see Sec. 98.7).

(viii) Methods 8031, 8021, or 8015 in ``Test Methods for Evaluating

Solid Waste, Physical/Chemical Methods,'' EPA Publication No. SW-846,

Third Edition, September 1986, as amended by Update I, November 15, 1992.

(ix) Method 18 at 40 CFR part 60, appendix A-6.

(x) Performance Specification 9 in 40 CFR part 60, appendix B for continuous online gas analyzers. The 7-day calibration error test period must be completed prior to the effective date of the rule.

Sec. 98.245 Procedures for estimating missing data.

For missing feedstock flow rates, product flow rates, and carbon contents, use the same procedures as for missing flow rates and carbon contents for fuels as specified in Sec. 98.35.

Sec. 98.246 Data reporting requirements.

In addition to the information required by Sec. 98.3(c), each annual report must contain the information specified in paragraphs (a),

(b), or (c) of this section, as appropriate for each process unit.

(a) If you use the mass balance methodology in Sec. 98.243(c), you must report the information specified in paragraphs (a)(1) through

(a)(10) of this section for each type of petrochemical produced, reported by process unit.

(1) The petrochemical process unit ID number or other appropriate descriptor.

(2) The type of petrochemical produced, names of other products, and names of carbon-containing feedstocks.

(3) Annual CO2emissions calculated using Equation X-4 of this subpart.

(4) Each of the monthly volume, mass, and carbon content values used in Equations X-1 through X-3 of this subpart (i.e., the directly measured values, substitute values, or the calculated values based on other measured data such as tank levels or gas composition) and the molecular weights for gaseous feedstocks and products used in Equation

X-1 of this subpart. Indicate whether you used the alternative to sampling and analysis specified in Sec. 98.243(c)(4).

(5) Annual quantity of each type of petrochemical produced from each process unit (metric tons).

(6) Name of each method listed in Sec. 98.244 used to determine a measured parameter (or description of manufacturer's recommended method).

(7) The dates and summarized results (e.g., percent calibration error) of the calibrations of each measurement device.

(8) Identification of each combustion unit that burned both process off-gas and supplemental fuel.

(9) If you comply with the alternative to sampling and analysis specified in Sec. 98.243(c)(4), the amount of time during which off- specification product was produced, the volume or mass of off- specification product produced, and if applicable, the date of any process change that reduced the composition to less than 99.5 percent.

(10) You may elect to report the flow and carbon content of wastewater, and you may elect to report the carbon content of hydrocarbons in fugitive emissions and in process vents that are not controlled with a combustion device. These values may be estimated based on engineering analyses. These values are not to be used in the mass balance calculation.

(b) If you use CEMS to measure CO2emissions in accordance with Sec. 98.243(b), then you must report the relevant information required under Sec. 98.36 for the Tier 4 Calculation

Methodology and the information listed in paragraphs (b)(1) through

(b)(6) of this section.

(1) For CEMS used on stacks for stationary combustion units, report the relevant information required under Sec. 98.36 for the Tier 4 calculation methodology.

(2) For CEMS used on stacks that are not used for stationary combustion units, report the information required under Sec. 98.36(e)(2)(vi) and (vii).

(3) The petrochemical process unit ID or other appropriate descriptor, and the type of petrochemical produced.

(4) The CO2emissions from each stack and the combined

CO2emissions from all stacks (except flare stacks) that handle process vent emissions and emissions from stationary combustion units that burn process off-gas for the petrochemical process unit. If a stationary combustion source serves multiple petrochemical process units or units other than the petrochemical process unit, estimate based on engineering judgment the fraction of fuel energy and emissions attributable to each petrochemical process unit.

(5) The CH4and N2O emissions from each stack and the combined CH4and N2O emissions from all stationary combustion units that burn process off-gas from the petrochemical process unit, the cumulative annual heat input used in

Equation C-10 in Sec. 98.33(c) of this subpart, and the annual flow of each fuel on which this heat input is based.

(6) ID or other appropriate descriptor of each stationary combustion unit that burns process off-gas.

(7) Information listed in Sec. 98.256(e) of subpart Y of this part for each flare that burns process off-gas.

(8) Annual quantity of each type of petrochemical produced from each process unit (metric tons).

Sec. 98.243(d), you must report under this subpart the information listed in paragraphs (c)(1) through (c)(4) of this section.

(1) For each stationary combustion unit that burns ethylene process off-gas (or group of stationary sources with a common pipe), the relevant information listed in Sec. 98.36 for the selected Tier 3 or

Tier 4 methodology. If a stationary combustion source serves multiple ethylene process units or units other than the ethylene process unit, estimate based on engineering judgment the fraction of fuel energy and emissions attributable to each ethylene process unit.

(2) Information listed in Sec. 98.256(e) for each flare that burns ethylene process off-gas.

(3) Name and annual quantity of each feedstock.

(4) Annual quantity of each type of petrochemical produced from each process unit (metric tons).

Sec. 98.247 Records that must be retained.

In addition to the recordkeeping requirements in Sec. 98.3(g), you must retain the records specified in paragraphs (a) through (c) of this section, as applicable.

(a) If you comply with the CEMS measurement methodology in Sec. 98.243(b), then you must retain under this subpart the records required for the Tier 4 Calculation Methodology in Sec. 98.37.

Page 56451

(b) If you comply with the mass balance methodology in Sec. 98.243(c), then you must retain records of the information listed in paragraphs (b)(1) through (b)(3) of this section.

(1) Results of feedstock or product composition determinations conducted in accordance with Sec. 98.243(c)(4).

(2) Start and end times and calculated carbon contents for time periods when off-specification product is produced, if you comply with the alternative methodology in Sec. 98.243(c)(4) for determining carbon content of feedstock or product.

(3) A part of the monitoring plan required under Sec. 98.3(g)(5), record the estimated accuracy of measurement devices and the technical basis for these estimates.

(c) If you comply with the combustion methodology in Sec. 98.243(d), then you must retain under this subpart the records required for the Tier 3 and/or Tier 4 Calculation Methodologies in Sec. 98.37.

Sec. 98.248 Definitions.

Except as specified in this section, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.

Product, as used in Sec. 98.243, means each of the following carbon-containing outputs from a process: the petrochemical, recovered byproducts, and liquid organic wastes that are not incinerated onsite.

Product does not include process vent emissions, fugitive emissions, or wastewater.

Subpart Y--Petroleum Refineries

Sec. 98.250 Definition of source category.

(a) A petroleum refinery is any facility engaged in producing gasoline, gasoline blending stocks, naphtha, kerosene, distillate fuel oils, residual fuel oils, lubricants, or asphalt (bitumen) through distillation of petroleum or through redistillation, cracking, or reforming of unfinished petroleum derivatives, except as provided in paragraph (b) of this section.

(b) For the purposes of this subpart, facilities that distill only pipeline transmix (off-spec material created when different specification products mix during pipeline transportation) are not petroleum refineries, regardless of the products produced.

(c) This source category consists of the following sources at petroleum refineries: Catalytic cracking units; fluid coking units; delayed coking units; catalytic reforming units; coke calcining units; asphalt blowing operations; blowdown systems; storage tanks; process equipment components (compressors, pumps, valves, pressure relief devices, flanges, and connectors) in gas service; marine vessel, barge, tanker truck, and similar loading operations; flares; sulfur recovery plants; and non-merchant hydrogen plants (i.e., hydrogen plants that are owned or under the direct control of the refinery owner and operator).

Sec. 98.251 Reporting threshold.

You must report GHG emissions under this subpart if your facility contains a petroleum refineries process and the facility meets the requirements of either Sec. 98.2(a)(1) or (a)(2).

Sec. 98.252 GHGs to report.

You must report:

(a) CO2, CH4, and N2O combustion emissions from stationary combustion units and from each flare.

Calculate and report these emissions under subpart C of this part

(General Stationary Fuel Combustion Sources) by following the requirements of subpart C, except for CO2emissions from combustion of refinery fuel gas. For CO2emissions from combustion of fuel gas, use either equation C-5 in subpart C of this part or the Tier 4 methodology in subpart C of this part. You may aggregate units, monitor common stacks, or monitor common (fuel) pipes as provided in Sec. 98.36(c) when calculating and reporting emissions from stationary combustion units.

(b) CO2, CH4, and N2O coke burn- off emissions from each catalytic cracking unit, fluid coking unit, and catalytic reforming unit under this subpart.

(c) CO2emissions from sour gas sent off site for sulfur recovery operations under this subpart. You must follow the calculation methodologies from Sec. 98.253(f) and the monitoring and QA/QC methods, missing data procedures, reporting requirements, and recordkeeping requirements of this subpart.

(d) CO2process emissions from each on-site sulfur recovery plant under this subpart.

(e) CO2, CH4, and N2O emissions from each coke calcining unit under this subpart.

(f) CO2and CH4emissions from asphalt blowing operations under this subpart.

(g) CH4emissions from equipment leaks, storage tanks, loading operations, delayed coking units, and uncontrolled blowdown systems under this subpart.

(h) CO2, CH4, and N2O emissions from each process vent not specifically included in paragraphs (a) through (g) of this section under this subpart.

(i) CO2and CH4emissions from non-merchant hydrogen production under this subpart. You must follow the calculation methodologies, monitoring and QA/QC methods, missing data procedures, reporting requirements, and recordkeeping requirements of subpart P of this part.

Sec. 98.253 Calculating GHG emissions.

(a) Calculate GHG emissions required to be reported in Sec. 98.252(b) through (i) using the applicable methods in paragraphs (b) through (n) of this section.

(b) For flares, calculate GHG emissions according to the requirements in paragraphs (b)(1) through (b)(3) of this section.

(1) Calculate the CO2emissions according to the applicable requirements in paragraphs (b)(1)(i) through (b)(1)(iii) of this section.

(i) Flow measurement. If you have a continuous flow monitor on the flare, you must use the measured flow rates when the monitor is operational and the flow rate is within the calibrated range of the measurement device to calculate the flare gas flow. If you do not have a continuous flow monitor on the flare and for periods when the monitor is not operational or the flow rate is outside the calibrated range of the measurement device, you must use engineering calculations, company records, or similar estimates of volumetric flare gas flow.

(ii) Heat value or carbon content measurement. If you have a continuous higher heating value monitor or gas composition monitor on the flare or if you monitor these parameters at least weekly, you must use the measured heat value or carbon content value in calculating the

CO2emissions from the flare using the applicable methods in paragraphs (b)(1)(ii)(A) and (b)(1)(ii)(B).

(A) If you monitor gas composition, calculate the CO2 emissions from the flare using Equation Y-1 of this section. If daily or more frequent measurement data are available, you must use daily values when using Equation Y-1 of this section; otherwise, use weekly values.

Page 56452

GRAPHIC

TIFF OMITTED TR30OC09.087

Where:

CO2= Annual CO2emissions for a specific fuel type (metric tons/year). 0.98 = Assumed combustion efficiency of a flare. 0.001 = Unit conversion factor (metric tons per kilogram, mt/kg). n = Number of measurement periods. The minimum value for n is 52

(for weekly measurements); the maximum value for n is 366 (for daily measurements during a leap year). p = Measurement period index. 44 = Molecular weight of CO2(kg/kg-mole). 12 = Atomic weight of C (kg/kg-mole).

(Flare)p= Volume of flare gas combusted during measurement period (standard cubic feet per period, scf/period). If a mass flow meter is used, measure flare gas flow rate in kg/period and replace the term ``(MW)p/MVC'' with ``1''.

(MW)p= Average molecular weight of the flare gas combusted during measurement period (kg/kg-mole). If measurements are taken more frequently than daily, use the arithmetic average of measurement values within the day to calculate a daily average.

MVC = Molar volume conversion factor (849.5 scf/kg-mole).

(CC)p= Average carbon content of the flare gas combusted during measurement period (kg C per kg flare gas). If measurements are taken more frequently than daily, use the arithmetic average of measurement values within the day to calculate a daily average.

(B) If you monitor heat content but do not monitor gas composition, calculate the CO2emissions from the flare using Equation Y- 2 of this section. If daily or more frequent measurement data are available, you must use daily values when using Equation Y-2 of this section; otherwise, use weekly values.

GRAPHIC

TIFF OMITTED TR30OC09.088

Where:

(for weekly measurements); the maximum value for n is 366 (for daily measurements during a leap year). p = Measurement period index.

(Flare)p= Volume of flare gas combusted during measurement period (million (MM) scf/period). If a mass flow meter is used, you must also measure molecular weight and convert the mass flow to a volumetric flow as follows: Flare[MMscf] = 0.000001 x

Flare[kg] x MVC/(MW)p, where MVC is the molar volume conversion factor (849.5 scf/kg-mole) and (MW)pis the average molecular weight of the flare gas combusted during measurement period (kg/kg-mole).

(HHV)p= Higher heating value for the flare gas combusted during measurement period (British thermal units per scf, Btu/scf =

MMBtu/MMscf). If measurements are taken more frequently than daily, use the arithmetic average of measurement values within the day to calculate a daily average.

EmF = Default CO2emission factor of 60 kilograms

CO2/MMBtu (HHV basis).

(iii) Alternative to heat value or carbon content measurements. If you do not measure the higher heating value or carbon content of the flare gas at least weekly, determine the quantity of gas discharged to the flare separately for periods of routine flare operation and for periods of start-up, shutdown, or malfunction, and calculate the

CO2emissions as specified in paragraphs (b)(1)(iii)(A) through (b)(1)(iii)(C) of this section.

(A) For periods of start-up, shutdown, or malfunction, use engineering calculations and process knowledge to estimate the carbon content of the flared gas for each start-up, shutdown, or malfunction event exceeding 500,000 scf/day.

(B) For periods of normal operation, use the average heating value measured for the fuel gas for the heating value of the flare gas. If heating value is not measured, the heating value may be estimated from historic data or engineering calculations.

GRAPHIC

TIFF OMITTED TR30OC09.089

Where:

CO2= Annual CO2emissions for a specific fuel type (metric tons/year). 0.98 = Assumed combustion efficiency of a flare. 0.001 = Unit conversion factor (metric tons per kilogram, mt/kg).

FlareNorm= Annual volume of flare gas combusted during normal operations from company records, (million (MM) standard cubic feet per year, MMscf/year).

HHV = Higher heating value for fuel gas or flare gas from company records (British thermal units per scf, Btu/scf = MMBtu/MMscf).

EmF = Default CO2emission factor for flare gas of 60 kilograms CO2/MMBtu (HHV basis). n = Number of start-up, shutdown, and malfunction events during the reporting year exceeding 500,000 scf/day. p = Start-up, shutdown, and malfunction event index. 44 = Molecular weight of CO2(kg/kg-mole). 12 = Atomic weight of C (kg/kg-mole).

(FlareSSM)p= Volume of flare gas combusted during indexed start-up, shutdown, or malfunction event from engineering calculations, (scf/event).

(MW)p= Average molecular weight of the flare gas, from the analysis results or engineering calculations for the event (kg/ kg-mole).

MVC = Molar volume conversion factor (849.5 scf/kg-mole).

(CC)p= Average carbon content of the flare gas, from analysis results or engineering calculations for the event (kg C per kg flare gas).

(2) Calculate CH4using Equation Y-4 of this section.

Page 56453

GRAPHIC

TIFF OMITTED TR30OC09.090

Where:

CH4= Annual methane emissions from flared gas (metric tons CH4/year).

CO2= Emission rate of CO2from flared gas calculated in paragraph (b)(1) of this section (metric tons/year).

EmFCH4= Default CH4emission factor for

``PetroleumProducts'' from Table C-2 of subpart C of this part

(General Stationary Fuel Combustion Sources) (kg CH4/

MMBtu).

EmF = Default CO2emission factor for flare gas of 60 kg

CO2/MMBtu (HHV basis). 0.02/0.98 = Correction factor for flare combustion efficiency. 16/44 = Correction factor ratio of the molecular weight of

CH4to CO2. fCH4= Weight fraction of carbon in the flare gas prior to combustion that is contributed by methane from measurement values or engineering calculations (kg C in methane in flare gas/kg C in flare gas); default is 0.4.

(3) Calculate N2O emissions using Equation Y-5 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.091

Where:

N2O = Annual nitrous oxide emissions from flared gas

(metric tons N2O/year).

CO2= Emission rate of CO2from flared gas calculated in paragraph (b)(1) of this section (metric tons/year).

EmFN2O= Default N2O emission factor for

``PetroleumProducts'' from Table C-2 of subpart C of this part

(General Stationary Fuel Combustion Sources) (kg N2O/

MMBtu).

EmF = Default CO2emission factor for flare gas of 60 kg

CO2/MMBtu (HHV basis).

(c) For catalytic cracking units and traditional fluid coking units, calculate the GHG emissions using the applicable methods described in paragraphs (c)(1) through (c)(5) of this section.

(1) If you operate and maintain a CEMS that measures CO2 emissions according to subpart C of this part (General Stationary Fuel

Combustion Sources), you must calculate and report CO2 emissions as provided in paragraphs (c)(1)(i) and (c)(1)(ii) of this section. Other catalytic cracking units and traditional fluid coking units must either install a CEMS that complies with the Tier 4

Calculation Methodology in subpart C of this part (General Stationary

Combustion Sources), or follow the requirements of paragraphs (c)(2) or

(3) of this section.

(i) Calculate CO2emissions by following the Tier 4

Calculation Methodology specified in Sec. 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General

Stationary Fuel Combustion Sources).

(ii) If a CO boiler or other post-combustion device is used, you must also calculate the CO2emissions from the fuel fired to the CO boiler or post-combustion device using the applicable methods for stationary combustion units in subpart C of this part. Calculate the process emissions from the catalytic cracking unit or fluid coking unit as the difference in the CO2CEMS emissions and the calculated combustion emissions associated with the CO boiler.

(2) For catalytic cracking units and fluid coking units with rated capacities greater than 10,000 barrels per stream day (bbls/sd) that do not use a continuous CO2CEMS for the final exhaust stack, you must continuously or no less frequently than hourly monitor the

O2, CO2, and (if necessary) CO concentrations in the exhaust stack from the catalytic cracking unit regenerator or fluid coking unit burner prior to the combustion of other fossil fuels and calculate the CO2emissions according to the requirements of paragraphs (c)(2)(i) through (c)(2)(iii) of this section:

(i) Calculate the CO2emissions from each catalytic cracking unit and fluid coking unit using Equation Y-6 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.092

Where:

CO2= Annual CO2mass emissions (metric tons/ year).

Qr= Volumetric flow rate of exhaust gas from the fluid catalytic cracking unit regenerator or fluid coking unit burner prior to the combustion of other fossil fuels (dry standard cubic feet per hour, dscfh).

%CO2= Hourly average percent CO2 concentration in the exhaust gas stream from the fluid catalytic cracking unit regenerator or fluid coking unit burner (percent by volume--dry basis).

%CO = Hourly average percent CO concentration in the exhaust gas stream from the fluid catalytic cracking unit regenerator or fluid coking unit burner (percent by volume--dry basis). When there is no post-combustion device, assume %CO to be zero. 44 = Molecular weight of CO2(kg/kg-mole).

MVC = Molar volume conversion factor (849.5 scf/kg-mole). 0.001 = Conversion factor (metric ton/kg). n = Number of hours in calendar year.

(ii) Either continuously monitor the volumetric flow rate of exhaust gas from the fluid catalytic cracking unit regenerator or fluid coking unit burner prior to the combustion of other fossil fuels or calculate the volumetric flow rate of this exhaust gas stream using

Equation Y-7 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.093

Where:

Qr= Volumetric flow rate of exhaust gas from the fluid catalytic cracking unit regenerator or fluid coking unit burner prior to the combustion of other fossil fuels (dscfh).

Qa= Volumetric flow rate of air to the fluid catalytic cracking unit regenerator or fluid coking unit burner, as determined from control room instrumentation (dscfh).

Qoxy= Volumetric flow rate of oxygen enriched air to the fluid catalytic cracking unit regenerator or fluid coking unit burner as determined from control room instrumentation (dscfh).

Page 56454

%O2= Hourly average percent oxygen concentration in exhaust gas stream from the fluid catalytic cracking unit regenerator or fluid coking unit burner (percent by volume--dry basis).

%Ooxy= O2concentration in oxygen enriched gas stream inlet to the fluid catalytic cracking unit regenerator or fluid coking unit burner based on oxygen purity specifications of the oxygen supply used for enrichment (percent by volume--dry basis).

%CO2= Hourly average percent CO2 concentration in the exhaust gas stream from the fluid catalytic cracking unit regenerator or fluid coking unit burner (percent by volume--dry basis).

%CO = Hourly average percent CO concentration in the exhaust gas stream from the fluid catalytic cracking unit regenerator or fluid coking unit burner (percent by volume--dry basis). When no auxiliary fuel is burned and a continuous CO monitor is not required under 40

CFR part 63 subpart UUU, assume %CO to be zero.

(iii) If you have a CO boiler that uses auxiliary fuels or combusts materials other than catalytic cracking unit or fluid coking unit exhaust gas, you must determine the CO2emissions resulting from the combustion of these fuels or other materials following the requirements in subpart C and report those emissions by following the requirements of subpart C of this part.

(3) For catalytic cracking units and fluid coking units with rated capacities of 10,000 barrels per stream day (bbls/sd) or less that do not use a continuous CO2CEMS for the final exhaust stack, comply with the requirements in paragraph (c)(3)(i) of this section or paragraphs (c)(3)(ii) and (c)(3)(iii) of this section, as applicable.

(i) If you continuously or no less frequently than daily monitor the O2, CO2, and (if necessary) CO concentrations in the exhaust stack from the catalytic cracking unit regenerator or fluid coking unit burner prior to the combustion of other fossil fuels, you must calculate the CO2emissions according to the requirements of paragraphs (c)(2)(i) through (c)(2)(iii) of this section, except that daily averages are allowed and the summation can be performed on a daily basis.

(ii) If you do not monitor at least daily the O2,

CO2, and (if necessary) CO concentrations in the exhaust stack from the catalytic cracking unit regenerator or fluid coking unit burner prior to the combustion of other fossil fuels, calculate the

CO2emissions from each catalytic cracking unit and fluid coking unit using Equation Y-8 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.094

Where:

CO2= Annual CO2mass emissions (metric tons/ year).

Qunit= Annual throughput of unit from company records

(barrels (bbls) per year, bbl/yr).

CBF = Coke burn-off factor from engineering calculations (kg coke per barrel of feed); default for catalytic cracking units = 7.3; default for fluid coking units = 11. 0.001 = Conversion factor (metric ton/kg).

CC = Carbon content of coke based on measurement or engineering estimate (kg C per kg coke); default = 0.94. 44/12 = Ratio of molecular weight of CO2to C (kg

CO2per kg C).

Combustion Sources) and report those emissions by following the requirements of subpart C of this part.

(4) Calculate CH4emissions using either unit specific measurement data, a unit-specific emission factor based on a source test of the unit, or Equation Y-9 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.095

Where:

CH4= Annual methane emissions from coke burn-off (metric tons CH4/year).

CO2= Emission rate of CO2from coke burn-off calculated in paragraphs (c)(1), (c)(2), (e)(1), (e)(2), (g)(1), or

(g)(2) of this section, as applicable (metric tons/year).

EmF1= Default CO2emission factor for petroleum coke from Table C-1 of subpart C of this part (General

Stationary Fuel Combustion Sources) (kg CO2/MMBtu).

EmF2= Default CH4emission factor for

``PetroleumProducts'' from Table C-2 of subpart C of this part

(General Stationary Fuel Combustion Sources) (kg CH4/

MMBtu).

(5) Calculate N2O emissions using either unit specific measurement data, a unit-specific emission factor based on a source test of the unit, or Equation Y-10 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.096

Where:

N2O = Annual nitrous oxide emissions from coke burn-off

(mt N2O/year).

CO2= Emission rate of CO2from coke burn-off calculated in paragraphs (c)(1), (c)(2), (e)(1), (e)(2), (g)(1), or

(g)(2) of this section, as applicable (metric tons/year).

EmF1= Default CO2emission factor for petroleum coke from Table C-1 of subpart C of this part (General

Stationary Fuel Combustion Sources) (kg CO2/MMBtu).

EmF3 =Default N2O emission factor for

``PetroleumProducts'' from Table C-2 of subpart C of this part (kg

N2O/MMBtu).

(d) For fluid coking units that use the flexicoking design, the GHG emissions from the resulting use of the low value fuel gas must be accounted for only once. Typically, these emissions will be accounted for using the methods described in subpart C of this part (General

Stationary Fuel Combustion Sources). Alternatively, you may use the methods in paragraph (c) of this section provided that you do not otherwise account for the subsequent combustion of this low value fuel gas.

(e) For catalytic reforming units, calculate the CO2 emissions using the applicable methods described in paragraphs (e)(1) through (e)(3) of this section and calculate the CH4and

N2O emissions using the methods described in paragraphs

(c)(4) and (c)(5) of this section, respectively.

(1) If you operate and maintain a CEMS that measures CO2 emissions according to subpart C of this part (General Stationary Fuel

Combustion Sources), you must calculate CO2emissions as provided in paragraphs (c)(1)(i) and (c)(1)(ii) of this section. Other catalytic reforming units must either install a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part, or follow the requirements of paragraph (e)(2) or (e)(3) of this section.

(2) If you continuously or no less frequently than daily monitor the O2, CO2, and (if necessary) CO concentrations in the exhaust stack from the catalytic reforming unit catalyst regenerator prior to the combustion of other fossil fuels, you must calculate the CO2emissions according to the requirements of paragraphs (c)(2)(i) through (c)(2)(iii) of this section.

Page 56455

(3) Calculate CO2emissions from the catalytic reforming unit catalyst regenerator using Equation Y-11 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.097

Where:

CO2= Annual CO2emissions (metric tons/year).

CBQ= Coke burn-off quantity per regeneration cycle from engineering estimates (kg coke/cycle). n = Number of regeneration cycles in the calendar year.

CC = Carbon content of coke based on measurement or engineering estimate (kg C per kg coke); default = 0.94. 44/12 = Ratio of molecular weight of CO2to C (kg

CO2per kg C). 0.001 = Conversion factor (metric ton/kg).

(f) For on-site sulfur recovery plants, calculate and report

CO2process emissions from sulfur recovery plants according to the requirements in paragraphs (f)(1) through (f)(5) of this section. Combustion emissions from the sulfur recovery plant (e.g., from fuel combustion in the Claus burner or the tail gas treatment incinerator) must be reported under subpart C of this part (General

Stationary Fuel Combustion Sources). For the purposes of this subpart, the sour gas stream for which monitoring is required according to paragraphs (f)(2) through (f)(5) of this section is not considered a fuel.

(1) If you operate and maintain a CEMS that measures CO2 emissions according to subpart C of this part, you must calculate

CO2emissions under this subpart by following the Tier 4

Calculation Methodology specified in Sec. 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General

Stationary Fuel Combustion Sources). You must monitor fuel use in the

Claus burner, tail gas incinerator, or other combustion sources that discharge via the final exhaust stack from the sulfur recovery plant and calculate the combustion emissions from the fuel use according to subpart C of this part. Calculate the process emissions from the sulfur recovery plant as the difference in the CO2CEMS emissions and the calculated combustion emissions associated with the sulfur recovery plant final exhaust stack. Other sulfur recovery plants must either install a CEMS that complies with the Tier 4 Calculation

Methodology in subpart C, or follow the requirements of paragraphs

(f)(2) through (f)(5) of this section.

(2) Flow measurement. If you have a continuous flow monitor on the sour gas feed to the sulfur recovery plant, you must use the measured flow rates when the monitor is operational to calculate the sour gas flow rate. If you do not have a continuous flow monitor on the sour gas feed to the sulfur recovery plant, you must use engineering calculations, company records, or similar estimates of volumetric sour gas flow.

(3) Carbon content. If you have a continuous gas composition monitor capable of measuring carbon content on the sour gas feed to the sulfur recovery plant or if you monitor gas composition for carbon content on a routine basis, you must use the measured carbon content value. Alternatively, you may develop a site-specific carbon content factor using limited measurement data or engineering estimates or use the default factor of 0.20.

(4) Calculate the CO2emissions from each sulfur recovery plant using Equation Y-12 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.098

Where:

CO2= Annual CO2emissions (metric tons/year).

FSG= Volumetric flow rate of sour gas feed (including sour water stripper gas) to the sulfur recovery plant (scf/year). 44 = Molecular weight of CO2(kg/kg-mole).

MVC = Molar volume conversion factor (849.5 scf/kg-mole).

MFC= Mole fraction of carbon in the sour gas to the sulfur recovery plant (kg-mole C/kg-mole gas); default = 0.20. 0.001 = Conversion factor, kg to metric tons.

(5) If tail gas is recycled to the front of the sulfur recovery plant and the recycled flow rate and carbon content is included in the measured data under paragraphs (f)(2) and (f)(3) of this section, respectively, then the annual CO2emissions calculated in paragraph (f)(4) of this section must be corrected to avoid double counting these emissions. You may use engineering estimates to perform this correction or assume that the corrected CO2emissions are 95 percent of the uncorrected value calculated using Equation Y-12 of this section.

(g) For coke calcining units, calculate GHG emissions according to the applicable provisions in paragraphs (g)(1) through (g)(3) of this section.

(1) If you operate and maintain a CEMS that measures CO2 emissions according to subpart C of this part, you must calculate and report CO2emissions under this subpart by following the

Tier 4 Calculation Methodology specified in Sec. 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General

Stationary Fuel Combustion Sources). You must monitor fuel use in the coke calcining unit that discharges via the final exhaust stack from the coke calcining unit and calculate the combustion emissions from the fuel use according to subpart C of this part. Calculate the process emissions from the coke calcining unit as the difference in the

CO2CEMS emissions and the calculated combustion emissions associated with the coke calcining unit final exhaust stack. Other coke calcining units must either install a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part, or follow the requirements of paragraph (g)(2) of this section.

(2) Calculate the CO2emissions from the coke calcining unit using Equation Y-13 of this section.

Page 56456

GRAPHIC

TIFF OMITTED TR30OC09.099

Where:

CO2= Annual CO2emissions (metric tons/year).

Min= Annual mass of green coke fed to the coke calcining unit from facility records (metric tons/year).

CCGC= Average mass fraction carbon content of green coke from facility measurement data (metric ton carbon/metric ton green coke).

Mout= Annual mass of marketable petroleum coke produced by the coke calcining unit from facility records (metric tons petroleum coke/year).

Mdust= Annual mass of petroleum coke dust collected in the dust collection system of the coke calcining unit from facility records (metric ton petroleum coke dust/year).

CCMPC= Average mass fraction carbon content of marketable petroleum coke produced by the coke calcining unit from facility measurement data (metric ton carbon/metric ton petroleum coke). 44 = Molecular weight of CO2(kg/kg-mole). 12 = Atomic weight of C (kg/kg-mole).

(3) For all coke calcining units, use the CO2emissions from the coke calcining unit calculated in paragraphs (g)(1) or (g)(2), as applicable, and calculate CH4using the methods described in paragraph (c)(4) of this section and N2O emissions using the methods described in paragraph (c)(5) of this section.

(h) For asphalt blowing operations, calculate GHG emissions according to the requirements in paragraph (j) of this section or according to the applicable provisions in paragraphs (h)(1) and (h)(2) of this section.

(1) For uncontrolled asphalt blowing operations or asphalt blowing operations controlled by vapor scrubbing, calculate CO2and

CH4emissions using Equations Y-14 and Y-15 of this section, respectively.

GRAPHIC

TIFF OMITTED TR30OC09.100

Where:

CO2= Annual CO2emissions from uncontrolled asphalt blowing (metric tons CO2/year).

QAB= Quantity of asphalt blown (million barrels per year, MMbbl/year).

EFAB,CO2= Emission factor for CO2from uncontrolled asphalt blowing from facility-specific test data

(metric tons CO2/MMbbl asphalt blown); default = 1,100.

GRAPHIC

TIFF OMITTED TR30OC09.101

Where:

CH4= Annual methane emissions from uncontrolled asphalt blowing (metric tons CH4/year).

QAB= Quantity of asphalt blown (million barrels per year, MMbbl/year).

EFAB,CH4 = Emission factor for CH4from uncontrolled asphalt blowing from facility-specific test data

(metric tons CH4/MMbbl asphalt blown); default = 580.

(2) For asphalt blowing operations controlled by thermal oxidizer or flare, calculate CO2and CH4emissions using

Equations Y-16 and Y-17 of this section, respectively, provided these emissions are not already included in the flare emissions calculated in paragraph (b) of this section or in the stationary combustion unit emissions required under subpart C of this part (General Stationary

Fuel Combustion Sources).

GRAPHIC

TIFF OMITTED TR30OC09.102

Where:

CO2= Annual CO2emissions from controlled asphalt blowing (metric tons CO2/year). 0.98 = Assumed combustion efficiency of thermal oxidizer or flare.

QAB= Quantity of asphalt blown (MMbbl/year).

CEFAB= Carbon emission factor from asphalt blowing from facility-specific test data (metric tons C/MMbbl asphalt blown); default = 2,750. 44 = Molecular weight of CO2(kg/kg-mole). 12 = Atomic weight of C (kg/kg-mole).

GRAPHIC

TIFF OMITTED TR30OC09.103

Where:

CH4= Annual methane emissions from controlled asphalt blowing (metric tons CH4/year). 0.02 = Fraction of methane uncombusted in thermal oxidizer or flare based on assumed 98% combustion efficiency.

QAB= Quantity of asphalt blown (million barrels per year, MMbbl/year).

EFAB,CH4 = Emission factor for CH4from uncontrolled asphalt blowing from facility-specific test data

(metric tons CH4/MMbbl asphalt blown); default = 580.

(i) For delayed coking units, calculate the CH4 emissions from the depressurization of the coking unit vessel (i.e., the ``coke drum'') to atmosphere using either of the methods provided in paragraphs (i)(1) or (i)(2), provided no water or steam is added to the vessel once it is vented to the atmosphere. You must use the method in paragraph (i)(1) of this section if you add water or steam to the vessel after it is vented to the atmosphere.

(1) Use the process vent method in paragraph (j) of this section and also calculate the CH4emissions from the subsequent opening of the vessel for coke cutting operations using Equation Y-18 of this section. If you have coke drums or vessels of different dimensions, use Equation Y-18 for each set of coke drums or vessels of the same size and sum the resultant emissions across each set of coke drums or vessels to calculate the CH4emissions for all delayed coking units.

GRAPHIC

TIFF OMITTED TR30OC09.104

Page 56457

Where:

CH4 =Annual methane emissions from the delayed coking unit vessel opening (metric ton/year).

N = Cumulative number of vessel openings for all delayed coking unit vessels of the same dimensions during the year.

H = Height of coking unit vessel (feet).

PCV= Gauge pressure of the coking vessel when opened to the atmosphere prior to coke cutting or, if the alternative method provided in paragraph (i)(2) of this section is used, gauge pressure of the coking vessel when depressurization gases are first routed to the atmosphere (pounds per square inch gauge, psig). 14.7 = Assumed atmospheric pressure (pounds per square inch, psi). fvoid= Volumetric void fraction of coking vessel prior to steaming (cf gas/cf of vessel); default = 0.6.

D = Diameter of coking unit vessel (feet). 16 = Molecular weight of CH4(kg/kg-mole).

MVC = Molar volume conversion factor (849.5 scf/kg-mole).

MFCH4 = Mole fraction of methane in coking vessel gas

(kg-mole CH4/kg-mole gas, wet basis); default value is 0.01. 0.001 = Conversion factor (metric ton/kg).

(2) Calculate the CH4emissions from the depressurization vent and subsequent opening of the vessel for coke cutting operations using Equation Y-18 of this section and the pressure of the coking vessel when the depressurization gases are first routed to the atmosphere. If you have coke drums or vessels of different dimensions, use Equation Y-18 for each set of coke drums or vessels of the same size and sum the resultant emissions across each set of coke drums or vessels to calculate the CH4emissions for all delayed coking units.

(j) For each process vent not covered in paragraphs (a) through (i) of this section that can be reasonably expected to contain greater than 2 percent by volume CO2or greater than 0.5 percent by volume of CH4or greater than 0.01 percent by volume (100 parts per million) of N2O, calculate GHG emissions using the

Equation Y-19 of this section. You must use Equation Y-19 of this section for catalytic reforming unit depressurization and purge vents when methane is used as the purge gas or if you elected this method as an alternative to the methods in paragraphs (h)(1) or (h)(2) of this section.

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TIFF OMITTED TR30OC09.105

Where:

Ex= Annual emissions of each GHG from process vent

(metric ton/yr).

N = Number of venting events per year.

P = Index of venting events.

(VR)p= Average volumetric flow rate of process gas during the event (scf per hour).

(MFx)p= Mole fraction of GHG x in process vent during the event (kg-mol of GHG x/kg-mol vent gas).

MWx= Molecular weight of GHG x (kg/kg-mole); use 44 for

CO2or N2O and 16 for CH4.

MVC = Molar volume conversion factor (849.5 scf/kg-mole).

(VT)p= Venting time for the event, (hours). 0.001 = Conversion factor (metric ton/kg).

(k) For uncontrolled blowdown systems, you must either use the methods for process vents in paragraph (j) of this section or calculate

CH4emissions using Equation Y-20 of this section. Blowdown systems where the uncondensed gas stream is routed to a flare or similar control device is considered to be controlled and is not required to estimate emissions under this paragraph (k).

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TIFF OMITTED TR30OC09.106

Where:

CH4= Methane emission rate from blowdown systems (mt

CH4/year).

QRef= Quantity of crude oil plus the quantity of intermediate products received from off site that are processed at the facility (MMbbl/year).

EFBD= Methane emission factor for uncontrolled blown systems (scf CH4/MMbbl); default is 137,000. 16 = Molecular weight of CH4(kg/kg-mole).

MVC = Molar volume conversion factor (849.5 scf/kg-mole). 0.001 = Conversion factor (metric ton/kg).

(l) For equipment leaks, calculate CH4emissions using the method specified in either paragraph (l)(1) or (l)(2) of this section.

(1) Use process-specific methane composition data (from measurement data or process knowledge) and any of the emission estimation procedures provided in the Protocol for Equipment Leak Emissions

Estimates (EPA-453/R-95-017, NTIS PB96-175401).

(2) Use Equation Y-21 of this section.

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TIFF OMITTED TR30OC09.107

Where:

CH4= Annual methane emissions from equipment leaks

(metric tons/year).

NCD= Number of atmospheric crude oil distillation columns at the facility.

NPU1= Cumulative number of catalytic cracking units, coking units (delayed or fluid), hydrocracking, and full-range distillation columns (including depropanizer and debutanizer distillation columns) at the facility.

NPU2= Cumulative number of hydrotreating/hydrorefining units, catalytic reforming units, and visbreaking units at the facility.

NH2= Total number of hydrogen plants at the facility.

NFGS= Total number of fuel gas systems at the facility.

(m) For storage tanks, except as provided in paragraph (m)(3) of this section, calculate CH4emissions using the applicable methods in paragraphs (m)(1) and (m)(2) of this section.

(1) For storage tanks other than those processing unstabilized crude oil, you must either calculate CH4emissions from storage tanks that have a vapor-phase methane concentration of 0.5 volume percent or more using tank-specific methane composition data

(from measurement data or product knowledge) and the AP-42 emission

Page 56458

estimation methods provided in Section 7.1 of the AP-42: ``Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and Area

Sources'', including TANKS Model (Version 4.09D) or similar programs, or estimate CH4emissions from storage tanks using Equation

Y-22 of this section.

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TIFF OMITTED TR30OC09.108

Where:

CH4= Annual methane emissions from storage tanks (metric tons/year). 0.1 = Default emission factor for storage tanks (metric ton

CH4/MMbbl).

QRef= Quantity of crude oil plus the quantity of intermediate products received from off site that are processed at the facility (MMbbl/year).

(2) For storage tanks that process unstabilized crude oil, calculate CH4emissions from the storage of unstabilized crude oil using either tank-specific methane composition data (from measurement data or product knowledge) and direct measurement of the gas generation rate or by using Equation Y-23 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.109

Where:

CH4= Annual methane emissions from storage tanks (metric tons/year).

Qun= Quantity of unstabilized crude oil received at the facility (MMbbl/year).

Delta

P = Pressure differential from the previous storage pressure to atmospheric pressure (pounds per square inch, psi).

MFCH4= Mole fraction of CH4in vent gas from the unstabilized crude oil storage tank from facility measurements

(kg-mole CH4/kg-mole gas); use 0.27 as a default if measurement data are not available. 995,000 = Correlation Equation factor (scf gas per MMbbl per psi). 16 = Molecular weight of CH4(kg/kg-mole).

MVC = Molar volume conversion factor (849.5 scf/kg-mole). 0.001 = Conversion factor (metric ton/kg).

(3) You do not need to calculate CH4emissions from storage tanks that meet any of the following descriptions:

(i) Units permanently attached to conveyances such as trucks, trailers, rail cars, barges, or ships;

(ii) Pressure vessels designed to operate in excess of 204.9 kilopascals and without emissions to the atmosphere;

(iii) Bottoms receivers or sumps;

(iv) Vessels storing wastewater; or

(v) Reactor vessels associated with a manufacturing process unit.

(n) For crude oil, intermediate, or product loading operations for which the equilibrium vapor-phase concentration of methane is 0.5 volume percent or more, calculate CH4emissions from loading operations using product-specific, vapor-phase methane composition data

(from measurement data or process knowledge) and the emission estimation procedures provided in Section 5.2 of the AP-42:

``Compilation of Air Pollutant Emission Factors, Volume 1: Stationary

Point and Area Sources.'' For loading operations in which the equilibrium vapor-phase concentration of methane is less than 0.5 volume percent, you may assume zero methane emissions.

Sec. 98.254 Monitoring and QA/QC requirements.

(a) Fuel flow meters, gas composition monitors, and heating value monitors associated with stationary combustion sources must follow the monitoring and QA/QC requirements in Sec. 98.34.

(b) All flow meters, gas composition monitors, and heating value monitors that are used to provide data for the GHG emissions calculations in this subpart for sources other than stationary combustion sources shall be calibrated according to the procedures in the applicable methods specified in paragraphs (c) through (e) of this section, the procedures specified by the manufacturer, or Sec. Sec. 98.3(i). Recalibrate each flow meter either biennially (every two years) or at the minimum frequency specified by the manufacturer.

Recalibrate each gas composition monitor and heating value monitor either annually or at the minimum frequency specified by the manufacturer.

(c) For flare or sour gas flow meters, operate and maintain the flow meter using any of the following methods, a method published by a consensus-based standards organization (e.g., ASTM, API, etc.) or follow the procedures specified by the flow meter manufacturer. Flow meters must have a rated accuracy of 5 percent or lower.

(1) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using

Orifice, Nozzle, and Venturi (incorporated by reference, see Sec. 98.7).

(2) ASME MFC-4M-1986 (Reaffirmed 1997) Measurement of Gas Flow by

Turbine Meters (incorporated by reference, see Sec. 98.7).

(3) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using

Vortex Flowmeters (incorporated by reference, see Sec. 98.7).

(4) ASME MFC-7M-1987 (Reaffirmed 1992) Measurement of Gas Flow by

Means of Critical Flow Venturi Nozzles (incorporated by reference, see

Sec. 98.7).

(5) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of

Coriolis Mass Flowmeters (incorporated by reference, see Sec. 98.7).

(6) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore

Precision Orifice Meters (incorporated by reference, see Sec. 98.7).

(7) ASME MFC-18M-2001 Measurement of Fluid Flow Using Variable Area

Meters (incorporated by reference, see Sec. 98.7).

(8) AGA Report No. 11 Measurement of Natural Gas by Coriolis Meter

(2003) (incorporated by reference, see Sec. 98.7).

(d) Determine flare gas composition using any of the following methods.

(1) Method 18 at 40 CFR part 60, appendix A-6.

(2) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see Sec. 98.7).

(3) ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference, see

Sec. 98.7).

(4) GPA 2261-00 Analysis for Natural Gas and Similar Gaseous

Mixtures by Gas Chromatography (incorporated by reference, see Sec. 98.7).

(5) UOP539-97 Refinery Gas Analysis by Gas Chromatography

(incorporated by reference, see Sec. 98.7).

(e) Determine flare gas higher heating value using any of the following methods.

(1) ASTM D4809-06 Standard Test Method for Heat of Combustion of

Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method)

(incorporated by reference, see Sec. 98.7).

(2) ASTM D240-02 (Reapproved 2007) Standard Test Method for Heat of

Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter

(incorporated by reference, see Sec. 98.7).

(3) ASTM D1826-94 (Reapproved 2003) Standard Test Method for

Calorific (Heating) Value of Gases in Natural Gas Range by Continuous

Recording Calorimeter (incorporated by reference, see Sec. 98.7).

Continued on page 56459

From the Federal Register Online via GPO Access [wais.access.gpo.gov]

]

pp. 56459-56508

Mandatory Reporting of Greenhouse Gases

Continued from page 56458

Page 56459

(4) ASTM D3588-98 (Reapproved 2003) Standard Practice for

Calculating Heat Value, Compressibility Factor, and Relative Density of

Gaseous Fuels (incorporated by reference, see Sec. 98.7).

(5) ASTM D4891-89 (Reapproved 2006) Standard Test Method for

Heating Value of Gases in Natural Gas Range by Stoichiometric

Combustion (incorporated by reference, see Sec. 98.7).

(f) For exhaust gas flow meters used to comply with the requirements in Sec. 98.253(c)(2)(ii), install, operate, calibrate, and maintain exhaust gas flow meter according to the requirements in 40

CFR 63.1572(c) or according to the following requirements.

(1) Locate the flow meter(s) and other necessary equipment such as straightening vanes in a position that provides representative flow; reduce swirling flow or abnormal velocity distributions due to upstream and downstream disturbances.

(2) Use a flow rate meter with an accuracy within 5 percent.

(3) Use a continuous monitoring system capable of correcting for the temperature, pressure, and moisture content to output flow in dry standard cubic feet (standard conditions as defined in Sec. 98.6).

(4) Install, operate, and maintain each continuous monitoring system according to the manufacturer's specifications and requirements.

(g) For exhaust gas CO2/CO/O2composition monitors used to comply with the requirements in Sec. 98.253(c)(2), install, operate, calibrate, and maintain exhaust gas composition monitors according to the requirements in 40 CFR 60.105a(b)(2) or 40

CFR 63.1572(a) or according to the manufacturer's specifications and requirements.

(h) Determine the mass of petroleum coke as required by Equation Y- 13 of this subpart using mass measurement equipment meeting the requirements for commercial weighing equipment as described in

Specifications, Tolerances, and Other Technical Requirements For

Weighing and Measuring Devices, NIST Handbook 44 (2009) (incorporated by reference, see Sec. 98.7). Calibrate the measurement device according to the procedures specified by the method, the procedures specified by the manufacturer, or Sec. 98.3(i). Recalibrate either biennially or at the minimum frequency specified by the manufacturer.

(i) Determine the carbon content of petroleum coke as required by

Equation Y-13 of this subpart using any one of the following methods.

Calibrate the measurement device according to procedures specified by the method or procedures specified by the measurement device manufacturer.

(1) ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate

Analysis of Coal and Coke (incorporated by reference, see Sec. 98.7).

(2) ASTM D5291-02 (Reapproved 2007) Standard Test Methods for

Instrumental Determination of Carbon, Hydrogen, and Nitrogen in

Petroleum Products and Lubricants (incorporated by reference, see Sec. 98.7).

(3) ASTM D5373-08 Standard Test Methods for Instrumental

Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see Sec. 98.7).

(j) Determine the quantity of petroleum process streams using company records. These quantities include the quantity of asphalt blown, quantity of crude oil plus the quantity of intermediate products received from off site, and the quantity of unstabilized crude oil received at the facility.

(k) The owner or operator shall document the procedures used to ensure the accuracy of the estimates of fuel usage, gas composition, and heating value including but not limited to calibration of weighing equipment, fuel flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices shall also be recorded, and the technical basis for these estimates shall be provided.

(l) All CO2CEMS and flow rate monitors used for direct measurement of GHG emissions must comply with the QA procedures in

Sec. 98.34(c).

Sec. 98.255 Procedures for estimating missing data.

A complete record of all measured parameters used in the GHG emissions calculations is required (e.g., concentrations, flow rates, fuel heating values, carbon content values). Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a CEMS malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations.

(a) For stationary combustion sources, use the missing data procedures in subpart C of this part.

(b) For each missing value of the heat content, carbon content, or molecular weight of the fuel, substitute the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If the ``after'' value is not obtained by the end of the reporting year, you may use the

``before'' value for the missing data substitution. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period.

(c) For missing CO2, CO, O2, CH4, or N2O concentrations, gas flow rate, and percent moisture, the substitute data values shall be the best available estimate(s) of the parameter(s), based on all available process data (e.g., processing rates, operating hours, etc.). The owner or operator shall document and keep records of the procedures used for all such estimates.

(d) For hydrogen plants, use the missing data procedures in subpart

P of this part.

Sec. 98.256 Data reporting requirements.

In addition to the reporting requirements of Sec. 98.3(c), you must report the information specified in paragraphs (a) through (q) of this section.

(a) For combustion sources, follow the data reporting requirements under subpart C of this part (General Stationary Fuel Combustion

Sources).

(b) For hydrogen plants, follow the data reporting requirements under subpart P of this part (Hydrogen Production).

(d) [Reserved]

(e) For flares, owners and operators shall report:

(1) The flare ID number (if applicable).

(2) A description of the type of flare (steam assisted, air- assisted).

(3) A description of the flare service (general facility flare, unit flare, emergency only or back-up flare).

(4) The calculated CO2, CH4, and

N2O annual emissions for each flare, expressed in metric tons of each pollutant emitted.

(5) A description of the method used to calculate the

CO2emissions for each flare (e.g., reference section and equation number).

(6) If you use Equation Y-1 of this subpart, the annual volume of flare gas combusted (in scf/year) and the annual average molecular weight (in kg/kg-mole) and carbon content of the flare gas (in kg carbon per kg flare gas).

(7) If you use Equation Y-2 of this subpart, the annual volume of flare gas combusted (in million (MM) scf/year) and the annual average higher heating value of the flare gas (in MMBtu per MMscf).

(8) If you use Equation Y-3 of this subpart, the annual volume of flare gas combusted (in MMscf/year) during

Page 56460

normal operations, the annual average higher heating value of the flare gas (in MMBtu/MMscf), the number of SSM events exceeding 500,000 scf/ day, and the volume of gas flared (in scf/event) and the average molecular weight (in kg/kg-mole) and carbon content of the flare gas

(in kg carbon per kg flare) for each SSM event over 500,000 scf/day.

(9) The fraction of carbon in the flare gas contributed by methane used in Equation Y-4 of this subpart and the basis for its value.

(f) For catalytic cracking units, traditional fluid coking units, and catalytic reforming units, owners and operators shall report:

(1) The unit ID number (if applicable).

(2) A description of the type of unit (fluid catalytic cracking unit, thermal catalytic cracking unit, traditional fluid coking unit, or catalytic reforming unit).

(3) Maximum rated throughput of the unit, in bbl/stream day.

(4) The calculated CO2, CH4, and

N2O annual emissions for each unit, expressed in metric tons of each pollutant emitted.

(5) A description of the method used to calculate the

CO2emissions for each unit (e.g., reference section and equation number).

(6) If you use a CEMS, the relevant information required under

Sec. 98.36(e)(2)(vi) for the Tier 4 Calculation Methodology, the

CO2annual emissions as measured by the CEMS (unadjusted to remove CO2combustion emissions associated with a CO boiler, if present) and the process CO2emissions as calculated according to Sec. 98.253(c)(1)(ii). Report the CO2annual emissions associated with fuel combustion under subpart C of this part

(General Stationary Fuel Combustion Sources).

(7) If you use Equation Y-6 of this subpart, the annual average exhaust gas flow rate, %CO2, and %CO.

(8) If you use Equation Y-7 of this subpart, the annual average flow rate of inlet air and oxygen-enriched air, %O2,

%Ooxy, %CO2, and %CO.

(9) If you use Equation Y-8 of this subpart, the coke burn-off factor, annual throughput of unit, and the average carbon content of coke and the basis for the value.

(10) Indicate whether you use a measured value, a unit-specific emission factor, or a default emission factor for CH4 emissions. If you use a unit-specific emission factor for

CH4, report the units of measure for the unit-specific factor, the activity data for calculating emissions (e.g., if the emission factor is based on coke burn-off rate, the annual quantity of coke burned), and the basis for the factor.

(11) Indicate whether you use a measured value, a unit-specific emission factor, or a default emission factor for N2O emissions. If you use a unit-specific emission factor for

N2O, report the units of measure for the unit-specific factor, the activity data for calculating emissions (e.g., if the emission factor is based on coke burn-off rate, the annual quantity of coke burned), and the basis for the factor.

(12) If you use Equation Y-11 of this subpart, the number of regeneration cycles during the reporting year, the average coke burn- off quantity per cycle, and the average carbon content of the coke.

(g) For fluid coking unit of the flexicoking type, the owner or operator shall report:

(1) The unit ID number (if applicable).

(2) A description of the type of unit.

(3) Maximum rated throughput of the unit, in bbl/stream day.

(4) Indicate whether the GHG emissions from the low heat value gas are accounted for in subpart C of this part or Sec. 98.253(c).

(5) If the GHG emissions for the low heat value gas are calculated at the flexicoking unit, also report the calculated annual

CO2, CH4, and N2O emissions for each unit, expressed in metric tons of each pollutant emitted, and the applicable equation input parameters specified in paragraphs (f)(7) through (f)(11) of this section.

(h) For sulfur recovery plants and for emissions from sour gas sent off-site for sulfur recovery, the owner and operator shall report:

(1) The plant ID number (if applicable).

(2) Maximum rated throughput of each independent sulfur recovery plant, in metric tons sulfur produced/stream day.

(3) The calculated CO2annual emissions for each sulfur recovery plant, expressed in metric tons. The calculated annual

CO2emissions from sour gas sent off-site for sulfur recovery, expressed in metric tons.

(4) If you use Equation Y-12 of this subpart, the annual volumetric flow to the sulfur recovery plant (in scf/year) and the annual average mole fraction of carbon in the sour gas (in kg-mole C/kg-mole gas).

(5) If you recycle tail gas to the front of the sulfur recovery plant, indicate whether the recycled flow rate and carbon content are included in the measured data under Sec. 98.253(f)(2) and (3).

Indicate whether a correction for CO2emissions in the tail gas was used in Equation Y-12. If so, then report the value of the correction, the annual volume of recycled tail gas (in scf/year) and the annual average mole fraction of carbon in the tail gas (in kg-mole

C/kg-mole gas). Indicate whether you used the default (95%) or a unit specific correction, and if used, report the approach used.

(6) If you use a CEMS, the relevant information required under

Sec. 98.36(e)(2)(vi) for the Tier 4 Calculation Methodology, the

CO2annual emissions as measured by the CEMS and the annual process CO2emissions calculated according to Sec. 98.253(f)(1). Report the CO2annual emissions associated with fuel combustion subpart C of this part (General Stationary Fuel

Combustion Sources).

(i) For coke calcining units, the owner and operator shall report:

(1) The unit ID number (if applicable).

(2) Maximum rated throughput of the unit, in metric tons coke calcined/stream day.

(3) The calculated CO2, CH4, and

N2O annual emissions for each unit, expressed in metric tons of each pollutant emitted.

(4) A description of the method used to calculate the

CO2emissions for each unit (e.g., reference section and equation number).

(5) If you use Equation Y-13 of this subpart, annual mass and carbon content of green coke fed to the unit, the annual mass and carbon content of marketable coke produced, and the annual mass of coke dust collected in dust collection systems.

(6) If you use a CEMS, the relevant information required under

Sec. 98.36(e)(2)(vi) for the Tier 4 Calculation Methodology, the

CO2annual emissions as measured by the CEMS and the annual process CO2emissions calculated according to Sec. 98.253(g)(1). Report the CO2annual emissions associated with fuel combustion under subpart C of this part (General Stationary

Fuel Combustion Sources).

(7) Indicate whether you use a measured value, a unit-specific emission factor or a default for CH4emissions. If you use a unit-specific emission factor for CH4, the unit-specific emission factor for CH4, the units of measure for the unit- specific factor, the activity data for calculating emissions (e.g., if the emission factor is based on coke burn-off rate, the annual quantity of coke burned), and the basis for the factor.

(8) If you use a site-specific emission factor in Equation Y-10 of this subpart, the site-specific emission factor and the basis of the factor.

(j) For asphalt blowing operations, the owner or operator shall report:

Page 56461

(1) The unit ID number (if applicable).

(2) The quantity of asphalt blown (in Million bbl) at the facility in the reporting year.

(3) The type of control device used to reduce methane (and other organic) emissions from the unit.

(4) The calculated annual CO2and CH4 emissions for each unit, expressed in metric tons of each pollutant emitted.

(5) If you use Equation Y-14 of this subpart, the CO2 emission factor used and the basis for the value.

(6) If you use Equation Y-15 of this subpart, the CH4 emission factor used and the basis for the value.

(7) If you use Equation Y-16 of this subpart, the carbon emission factor used and the basis for the value.

(8) If you use Equation Y-17 of this subpart, the CH4 emission factor used and the basis for the value.

(k) For delayed coking units, the owner or operator shall report:

(1) The cumulative annual CH4emissions (in metric tons of each pollutant emitted) for all delayed coking units at the facility.

(2) A description of the method used to calculate the

CH4emissions for each unit (e.g., reference section and equation number).

(3) The total number of delayed coking units at the facility, the total number of delayed coking drums at the facility, and for each coke drum or vessel: the dimensions, the typical gauge pressure of the coking drum when first vented to the atmosphere, typical void fraction, the typical drum outage (i.e. the unfilled distance from the top of the drum, in feet), and annual number of coke-cutting cycles.

(4) For each set of coking drums that are the same dimensions: The number of coking drums in the set, the height and diameter of the coke drums (in feet), the cumulative number of vessel openings for all delayed coking drums in the set, the typical venting pressure (in psig), void fraction (in cf gas/cf of vessel), and the mole fraction of methane in coking gas (in kg-mole CF4/kg-mole gas, wet basis).

(5) The basis for the volumetric void fraction of the coke vessel prior to steaming and the basis for the mole fraction of methane in the coking gas.

(l) For process vents subject to Sec. 98.253(j), the owner or operator shall report:

(1) The vent ID number (if applicable).

(2) The unit or operation associated with the emissions.

(3) The type of control device used to reduce methane (and other organic) emissions from the unit, if applicable.

(4) The calculated annual CO2, CH4, and

N2O emissions for each vent, expressed in metric tons of each pollutant emitted.

(5) The annual volumetric flow discharged to the atmosphere (in scf), mole fraction of each GHG above the concentration threshold, and for intermittent vents, the number of venting events and the cumulative venting time.

(m) For uncontrolled blowdown systems, the owner or operator shall report:

(1) The cumulative annual CH4emissions (in metric tons of each pollutant emitted) for uncontrolled blowdown systems.

(2) The total quantity (in Million bbl) of crude oil plus the quantity of intermediate products received from off-site that are processed at the facility in the reporting year.

(3) The methane emission factor used for uncontrolled blowdown systems and the basis for the value.

(n) For equipment leaks, the owner or operator shall report:

(1) The cumulative CH4emissions (in metric tons of each pollutant emitted) for all equipment leak sources.

(2) The method used to calculate the reported equipment leak emissions.

(3) The number of each type of emission source listed in Equation

Y-21 of this subpart at the facility.

(o) For storage tanks, the owner or operator shall report:

(1) The cumulative annual CH4emissions (in metric tons of each pollutant emitted) for all storage tanks, except for those used to process unstabilized crude oil.

(2) The method used to calculate the reported storage tank emissions for storage tanks other than those processing unstabilized crude (AP-42, TANKS 4.09D, Equation Y-22 of this subpart, other).

(3) The total quantity (in MMbbl) of crude oil plus the quantity of intermediate products received from off-site that are processed at the facility in the reporting year.

(4) The cumulative CH4emissions (in metric tons of each pollutant emitted) for storage tanks used to process unstabilized crude oil.

(5) The method used to calculate the reported storage tank emissions for storage tanks processing unstabilized crude oil.

(6) The quantity of unstabilized crude oil received during the calendar year (in MMbbl), the average pressure differential (in psi), and the mole fraction of CH4in vent gas from the unstabilized crude oil storage tank, and the basis for the mole fraction.

(7) The tank-specific methane composition data and the gas generation rate data, if you did not use Equation Y-23.

(p) For loading operations, the owner or operator shall report:

(1) The cumulative annual CH4emissions (in metric tons of each pollutant emitted) for loading operations.

(2) The quantity and types of materials loaded by vessel type

(barge, tanker, marine vessel, etc.) that have an equilibrium vapor- phase concentration of methane of 0.5 volume percent or greater, and the type of vessels in which the material is loaded.

(3) The type of control system used to reduce emissions from the loading of material with an equilibrium vapor-phase concentration of methane of 0.5 volume percent or greater, if any (submerged loading, vapor balancing, etc.).

(q) Name of each method listed in Sec. 98.254 or a description of manufacturer's recommended method used to determine a measured parameter.

Sec. 98.257 Records that must be retained.

In addition to the records required by Sec. 98.3(g), you must retain the records of all parameters monitored under Sec. 98.255.

Sec. 98.258 Definitions.

All terms used in this subpart have the same meaning given in the

Clean Air Act and subpart A of this part.

Subpart Z--Phosphoric Acid Production

Sec. 98.260 Definition of the source category.

The phosphoric acid production source category consists of facilities with a wet-process phosphoric acid process line used to produce phosphoric acid. A wet-process phosphoric acid process line is the production unit or units identified by an individual identification number in an operating permit and/or any process unit or group of process units at a facility reacting phosphate rock from a common supply source with acid.

Sec. 98.261 Reporting threshold.

You must report GHG emissions under this subpart if your facility contains a phosphoric acid production process and the facility meets the requirements of either Sec. 98.2(a)(1) or (a)(2).

Sec. 98.262 GHGs to report.

(a) You must report CO2process emissions from each wet- process phosphoric acid process line.

(b) You must report under subpart C of this part (General

Stationary Fuel

Page 56462

Combustion Sources) the emissions of CO2, CH4, and N2O from each stationary combustion unit following the requirements of subpart C of this part.

Sec. 98.263 Calculating GHG emissions.

You must calculate and report the annual process CO2 emissions from each wet-process phosphoric acid process line using the procedures in either paragraph (a) or (b) of this section.

(a) Calculate and report under this subpart the process

CO2emissions by operating and maintaining a CEMS according to the Tier 4 Calculation Methodology specified in Sec. 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part

(General Stationary Fuel Combustion Sources).

(b) Calculate and report under this subpart the process

CO2emissions using the procedures in paragraphs (b)(1) and

(b)(2) of this section.

(1) Calculate and report the process CO2emissions from each wet-process phosphoric acid process line using Equation Z-1 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.110

Where:

Em= Annual CO2mass emissions from a wet- process phosphoric acid process line m (metric tons).

ICn,i= Inorganic carbon content of a grab sample batch of phosphate rock by origin i obtained during month n, from the carbon analysis results (percent by weight, expressed as a decimal fraction).

Pn,i= Mass of phosphate rock by origin i consumed in month n by wet-process phosphoric acid process line m (tons). z = Number of months during which the process line m operates. b = Number of different types of phosphate rock in month, by origin.

If the grab sample is a composite sample of rock from more than one origin, b=1. 2000/2205 = Conversion factor to convert tons to metric tons. 44/12 = Ratio of molecular weights, CO2to carbon.

(2) You must determine the total emissions from the facility using

Equation Z-2 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.111

Where:

CO2= Annual process CO2emissions from phosphoric acid production facility (metric tons/year).

Em= Annual process CO2emissions from wet- process phosphoric acid process line m (metric tons/year). p = Number of wet-process phosphoric acid process lines.

(c) If GHG emissions from a wet-process phosphoric acid process line are vented through the same stack as any combustion unit or process equipment that reports CO2emissions using a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Fuel Combustion Sources), then the calculation methodology in paragraph (b) of this section shall not be used to calculate process emissions. The owner or operator shall report under this subpart the combined stack emissions according to the Tier 4

Calculation Methodology in Sec. 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part.

Sec. 98.264 Monitoring and QA/QC requirements.

(a) You must obtain a monthly grab sample of phosphate rock directly from the rock being fed to the process line. Conduct the representative bulk sampling using the applicable standard method in the Phosphate Mining States Methods Used and Adopted by the Association of Fertilizer and Phosphate Chemists AFPC Manual 10th Edition 2009--

Version 1.9 (incorporated by reference, see Sec. 98.7). If phosphate rock is obtained from more than one origin in a month, you must obtain a sample from each origin of rock or obtain a composite representative sample.

(b) You must determine the inorganic carbon content of each monthly grab sample of phosphate rock (consumed in the production of phosphoric acid) using the applicable standard method in the Phosphate Mining

States Methods Used and Adopted by the Association of Fertilizer and

Phosphate Chemists AFPC Manual 10th Edition 2009--Version 1.9

(incorporated by reference, see Sec. 98.7).

(c) You must determine the mass of phosphate rock consumed each month (by origin) in each wet-process phosphoric acid process line. You can use existing plant procedures that are used for accounting purposes

(such as sales records) or you can use data from existing monitoring equipment that is used to measure total mass flow of phosphorous- bearing feed under 40 CFR part 60 or part 63.

Sec. 98.265 Procedures for estimating missing data.

A complete record of all measured parameters used in the GHG emissions calculations in Sec. 98.263(b) is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in paragraphs (a) and (b) of this section. You must document and keep records of the procedures used for all such estimates.

(a) For each missing value of the inorganic carbon content of phosphate rock (by origin), you must use the appropriate default factor provided in Table Z-1 of this subpart. Alternatively, the you must determine substitute data value by calculating the arithmetic average of the quality-assured values of inorganic carbon contents of phosphate rock of origin i (see Equation Z-1 of this subpart) from samples immediately preceding and immediately following the missing data incident. If no quality-assured data on inorganic carbon contents of phosphate rock of origin i are available prior to the missing data incident, the substitute data value shall be the first quality-assured value for inorganic carbon contents for phosphate rock of origin i obtained after the missing data period.

(b) For each missing value of monthly mass consumption of phosphate rock (by origin), you must use the best available estimate based on all available process data or data used for accounting purposes.

Sec. 98.266 Data reporting requirements.

In addition to the information required by Sec. 98.3(c), each annual report must contain the information specified in paragraphs (a) through (b) of this section.

(a) Annual phosphoric acid production by origin (as listed in Table

Z-1 to this subpart) of the phosphate rock (tons).

(b) Annual phosphoric acid permitted production capacity (tons).

(d) Annual phosphate rock consumption from monthly measurement records by origin, (as

Page 56463

listed in Table Z-1 to this subpart) (tons).

(e) If you use a CEMS to measure CO2emissions, then you must report the information in paragraphs (e)(1) and (e)(2) of this section.

(1) The identification number of each wet-process phosphoric acid process line.

(2) The annual CO2emissions from each wet-process phosphoric acid process line (metric tons) and the relevant information required under 40 CFR 98.36 (e)(2)(vi) for the Tier 4 Calculation

Methodology.

(f) If you do not use a CEMS to measure emissions, then you must report the information in paragraphs (f)(1) through (f)(8) of this section.

(1) Identification number of each wet-process phosphoric acid process line.

(2) Annual CO2emissions from each wet-process phosphoric acid process line (metric tons) as calculated by Equation Z- 1 of this subpart.

(3) Annual phosphoric acid permitted production capacity (tons) for each wet-process phosphoric acid process line (metric tons).

(4) Method used to estimate any missing values of inorganic carbon content of phosphate rock for each wet-process phosphoric acid process line.

(5) Monthly inorganic carbon content of phosphate rock for each wet-process phosphoric acid process line (percent by weight, expressed as a decimal fraction).

(6) Monthly mass of phosphate rock consumed by origin, (as listed in Table Z-1 of this subpart) in production for each wet-process phosphoric acid process line (tons).

(7) Number of wet-process phosphoric acid process lines.

(8) Number of times missing data procedures were used to estimate phosphate rock consumption (months) and inorganic carbon contents of the phosphate rock (months).

Sec. 98.267 Records that must be retained.

In addition to the records required by Sec. 98.3(g), you must retain the records specified in paragraphs (a) through (c) of this section for each wet-process phosphoric acid production facility.

(a) Monthly mass of phosphate rock consumed by origin (as listed in

Table Z-1 of this subpart) (tons).

(b) Records of all phosphate rock purchases and/or deliveries (if vertically integrated with a mine).

(c) Documentation of the procedures used to ensure the accuracy of monthly phosphate rock consumption by origin, (as listed in Table Z-1 of this subpart).

Sec. 98.268 Definitions.

All terms used in this subpart have the same meaning given in the

Clean Air Act and subpart A of this part.

Table Z-1 to Subpart Z of Part 98--Default Chemical Composition of

Phosphate Rock by Origin

Total carbon

Origin

(percent by weight)

Central Florida............................................

1.6

North Florida..............................................

1.76

North Carolina (Calcined)..................................

0.76

Idaho (Calcined)...........................................

0.60

Morocco....................................................

1.56

Subpart AA--Pulp and Paper Manufacturing

Sec. 98.270 Definition of source category.

(a) The pulp and paper manufacturing source category consists of facilities that produce market pulp (i.e., stand-alone pulp facilities), manufacture pulp and paper (i.e., integrated facilities), produce paper products from purchased pulp, produce secondary fiber from recycled paper, convert paper into paperboard products (e.g., containers), or operate coating and laminating processes.

(b) The emission units for which GHG emissions must be reported are listed in paragraphs (b)(1) through (b)(5) of this section:

(1) Chemical recovery furnaces at kraft and soda mills (including recovery furnaces that burn spent pulping liquor produced by both the kraft and semichemical process).

(2) Chemical recovery combustion units at sulfite facilities.

(3) Chemical recovery combustion units at stand-alone semichemical facilities.

(4) Pulp mill lime kilns at kraft and soda facilities.

(5) Systems for adding makeup chemicals (CaCO3,

Na2CO3) in the chemical recovery areas of chemical pulp mills.

Sec. 98.271 Reporting threshold.

You must report GHG emissions under this subpart if your facility contains a pulp and paper manufacturing process and the facility meets the requirements of either Sec. 98.2(a)(1) or (a)(2).

Sec. 98.272 GHGs to report.

You must report the emissions listed in paragraphs (a) through (f) of this section:

(a) CO2, biogenic CO2, CH4, and

N2O emissions from each kraft or soda chemical recovery furnace.

(b) CO2, biogenic CO2, CH4, and

N2O emissions from each sulfite chemical recovery combustion unit.

N2O emissions from each stand-alone semichemical chemical recovery combustion unit.

(d) CO2, biogenic CO2, CH4, and

N2O emissions from each kraft or soda pulp mill lime kiln.

(e) CO2emissions from addition of makeup chemicals

(CaCO3, Na2CO3) in the chemical recovery areas of chemical pulp mills.

(f) CO2, CH4,andN2O combustion emissions from each stationary combustion unit. You must calculate and report these emissions under subpart C of this part

(General Stationary Fuel Combustion Sources) by following the requirements of subpart C.

Sec. 98.273 Calculating GHG emissions.

(a) For each chemical recovery furnace located at a kraft or soda facility, you must determine CO2, biogenic CO2,

CH4, and N2O emissions using the procedures in paragraphs (a)(1) through (a)(3) of this section. CH4and

N2O emissions must be calculated as the sum of emissions from combustion of fossil fuels and combustion of biomass in spent liquor solids.

(1) Calculate fossil fuel-based CO2emissions from direct measurement of fossil fuels consumed and default emissions factors according to the Tier 1 methodology for stationary combustion sources in Sec. 98.33(a)(1).

(2) Calculate fossil fuel-based CH4and N2O emissions from direct measurement of fossil fuels consumed, default

HHV, and default emissions factors and convert to metric tons of

CO2equivalent according to the methodology for stationary combustion sources in Sec. 98.33(c).

(3) Calculate biogenic CO2emissions and emissions of

CH4and N2O from biomass using measured quantities of spent liquor solids fired, site-specific HHV, and default or site-specific emissions factors, according to Equation AA-1 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.112

Page 56464

Where:

CO2, CH4, or N2O, from Biomass =

Biogenic CO2emissions or emissions of CH4or

N2O from spent liquor solids combustion (metric tons per year).

Solids = Mass of spent liquor solids combusted (short tons per year) determined according to Sec. 98.274(b).

HHV = Annual high heat value of the spent liquor solids (mmBtu per kilogram) determined according to Sec. 98.274(b).

EF = Default emission factor for CO2, CH4, or

N2O, from Table AA-1 of this subpart (kg CO2,

CH4, or N2O per mmBtu). 0.90718 = Conversion factor from short tons to metric tons.

(b) For each chemical recovery combustion unit located at a sulfite or stand-alone semichemical facility, you must determine

CO2, CH4, and N2O emissions using the procedures in paragraphs (b)(1) through (b)(4) of this section:

(1) Calculate fossil CO2emissions from fossil fuels from direct measurement of fossil fuels consumed and default emissions factors according to the Tier 1 Calculation Methodology for stationary combustion sources in Sec. 98.33(a)(1).

(2) Calculate CH4and N2O emissions from fossil fuels from direct measurement of fossil fuels consumed, default

HHV, and default emissions factors and convert to metric tons of

CO2equivalent according to the methodology for stationary combustion sources in Sec. 98.33(c).

(3) Calculate biogenic CO2emissions using measured quantities of spent liquor solids fired and the carbon content of the spent liquor solids, according to Equation AA-2 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.113

Where:

Biogenic CO2= Annual CO2mass emissions for spent liquor solids combustion (metric tons per year).

Solids = Mass of the spent liquor solids combusted (short tons per year) determined according to Sec. 98.274(b).

CC = Annual carbon content of the spent liquor solids, determined according to Sec. 98.274(b) (percent by weight, expressed as a decimal fraction, e.g., 95% = 0.95). 44/12 = Ratio of molecular weights, CO2to carbon. 0.90718 = Conversion from short tons to metric tons.

(4) Calculate CH4and N2O emissions from biomass using Equation AA-1 of this section and the default

CH4and N2O emissions factors for kraft facilities in Table AA-1 of this subpart and convert the CH4 or N2O emissions to metric tons of CO2equivalent by multiplying each annual CH4and N2O emissions total by the appropriate global warming potential (GWP) factor from

Table A-1 of subpart A of this part.

N2O emissions using the procedures in paragraphs (c)(1) through (c)(3) of this section:

(1) Calculate CO2emissions from fossil fuel from direct measurement of fossil fuels consumed and default HHV and default emissions factors, according to the Tier 1 Calculation Methodology for stationary combustion sources in Sec. 98.33(a)(1); use the default HHV listed in Table C-1 of subpart C and the default CO2 emissions factors listed in Table AA-2 of this subpart.

(2) Calculate CH4and N2O emissions from fossil fuel from direct measurement of fossil fuels consumed, default

HHV, and default emissions factors and convert to metric tons of

CO2equivalent according to the methodology for stationary combustion sources in Sec. 98.33(c); use the default HHV listed in

Table C-1 of subpart C and the default CH4and

N2O emissions factors listed in Table AA-2 of this subpart.

(3) Biogenic CO2emissions from conversion of

CaCO3to CaO are included in the biogenic CO2 estimates calculated for the chemical recovery furnace in paragraph

(a)(3) of this section.

(d) For makeup chemical use, you must calculate CO2 emissions by using direct or indirect measurement of the quantity of chemicals added and ratios of the molecular weights of CO2 and the makeup chemicals, according to Equation AA-3 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.114

Where:

CO2= CO2mass emissions from makeup chemicals

(kilograms/yr).

M (CaCO3) = Make-up quantity of CaCO3used for the reporting year (metric tons per year).

M (NaCO3) = Make-up quantity of

Na2CO3used for the reporting year (metric tons per year). 44 = Molecular weight of CO2. 100 = Molecular weight of CaCO3. 105.99 = Molecular weight of Na2CO3.

Sec. 98.274 Monitoring and QA/QC requirements.

(a) Each facility subject to this subpart must quality assure the

GHG emissions data according to the applicable requirements in Sec. 98.34. All QA/QC data must be available for inspection upon request.

(b) Fuel properties needed to perform the calculations in Equations

AA-1 and AA-2 of this subpart must be determined according to paragraphs (b)(1) through (b)(3) of this section.

(1) High heat values of black liquor must be determined no less than annually using T684 om-06 Gross Heating Value of Black Liquor,

TAPPI (incorporated by reference, see Sec. 98.7). If measurements are performed more frequently than annually, then the high heat value used in Equation AA-1 of this subpart must be based on the average of the representative measurements made during the year.

(2) The annual mass of spent liquor solids must be determined using either of the methods specified in paragraph (b)(2)(i) or (b)(2)(ii) of this section.

(i) Measure the mass of spent liquor solids annually (or more frequently) using T-650 om-05 Solids Content of Black Liquor, TAPPI

(incorporated by reference in Sec. 98.7). If measurements are performed more frequently than annually, then the mass of spent liquor solids used in Equation AA-1 of this subpart must be based on the average of the representative measurements made during the year.

(ii) Determine the annual mass of spent liquor solids based on records of measurements made with an online measurement system that determines

Page 56465

the mass of spent liquor solids fired in a chemical recovery furnace or chemical recovery combustion unit.

(3) Carbon analyses for spent pulping liquor must be determined no less than annually using ASTM D5373-08 Standard Test Methods for

Instrumental Determination of Carbon, Hydrogen, and Nitrogen in

Laboratory Samples of Coal (incorporated by reference, see Sec. 98.7).

If measurements using ASTM D5373-08 are performed more frequently than annually, then the spent pulping liquor carbon content used in Equation

AA-2 of this subpart must be based on the average of the representative measurements made during the year.

(c) Each facility must keep records that include a detailed explanation of how company records of measurements are used to estimate

GHG emissions. The owner or operator must also document the procedures used to ensure the accuracy of the measurements of fuel, spent liquor solids, and makeup chemical usage, including, but not limited to calibration of weighing equipment, fuel flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices must be recorded and the technical basis for these estimates must be provided. The procedures used to convert spent pulping liquor flow rates to units of mass (i.e., spent liquor solids firing rates) also must be documented.

(d) Records must be made available upon request for verification of the calculations and measurements.

Sec. 98.275 Procedures for estimating missing data.

A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality- assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the requirements of paragraphs (a) through (c) of this section:

(a) There are no missing data procedures for measurements of heat content and carbon content of spent pulping liquor. A re-test must be performed if the data from any annual measurements are determined to be invalid.

(b) For missing measurements of the mass of spent liquor solids or spent pulping liquor flow rates, use the lesser value of either the maximum mass or fuel flow rate for the combustion unit, or the maximum mass or flow rate that the fuel meter can measure.

(c) For the use of makeup chemicals (carbonates), the substitute data value shall be the best available estimate of makeup chemical consumption, based on available data (e.g., past accounting records, production rates). The owner or operator shall document and keep records of the procedures used for all such estimates.

Sec. 98.276 Data reporting requirements.

In addition to the information required by Sec. 98.3(c), each annual report must contain the information in paragraphs (a) through

(k) of this section as applicable:

(a) Annual emissions of CO2, biogenic CO2,

CH4, biogenic CH4N2O, and biogenic

N2O (metric tons per year).

(b) Annual quantities fossil fuels by type used in chemical recovery furnaces and chemical recovery combustion units in short tons for solid fuels, gallons for liquid fuels and scf for gaseous fuels.

(c) Annual mass of the spent liquor solids combusted (short tons per year), and basis for determining the annual mass of the spent liquor solids combusted (whether based on T650 om-05 Solids Content of

Black Liquor, TAPPI (incorporated by reference, see Sec. 98.7) or an online measurement system).

(d) The high heat value (HHV) of the spent liquor solids used in

Equation AA-1 of this subpart (mmBtu per kilogram).

(e) The default emission factor for CO2, CH4, or N2O, used in Equation AA-1 of this subpart (kg

CO2, CH4, or N2O per mmBtu).

(f) The carbon content (CC) of the spent liquor solids, used in

Equation AA-2 of this subpart (percent by weight, expressed as a decimal fraction, e.g., 95% = 0.95).

(g) Annual quantities of fossil fuels by type used in pulp mill lime kilns in short tons for solid fuels, gallons for liquid fuels and scf for gaseous fuels.

(h) Make-up quantity of CaCO3used for the reporting year (metric tons per year) used in Equation AA-3 of this subpart.

(i) Make-up quantity of Na2CO3used for the reporting year (metric tons per year) used in Equation AA-3 of this subpart.

(j) Annual steam purchases (pounds of steam per year).

(k) Annual production of pulp and/or paper products produced

(metric tons).

Sec. 98.277 Records that must be retained.

In addition to the information required by Sec. 98.3(g), you must retain the records in paragraphs (a) through (f) of this section.

(a) GHG emission estimates (including separate estimates of biogenic CO2) for each emissions source listed under Sec. 98.270(b).

(b) Annual analyses of spent pulping liquor HHV for each chemical recovery furnace at kraft and soda facilities.

(c) Annual analyses of spent pulping liquor carbon content for each chemical recovery combustion unit at a sulfite or semichemical pulp facility.

(d) Annual quantity of spent liquor solids combusted in each chemical recovery furnace and chemical recovery combustion unit, and the basis for detemining the annual quantity of the spent liquor solids combusted (whether based on T650 om-05 Solids Content of Black Liquor,

TAPPI (incorporated by reference, see Sec. 98.7) or an online measurement system). If an online measurement system is used, you must retain records of the calculations used to determine the annual quantity of spent liquor solids combusted from the continuous measurements.

(e) Annual steam purchases.

(f) Annual quantities of makeup chemicals used.

Sec. 98.278 Definitions.

All terms used in this subpart have the same meaning given in the

Clean Air Act and subpart A of this part.

Table AA-1 to Subpart AA of Part 98--Kraft Pulping Liquor Emissions

Factors for Biomass-Based CO2, CH4, and N2O

Biomass-based emissions factors

(kg/mmBtu HHV)

Wood furnish

--------------------------------

CO2\a\

CH4

N2O

North American Softwood................

94.4

0.030

0.005

North American Hardwood................

93.7

Bagasse................................

95.5

Bamboo.................................

93.7

Page 56466

Straw..................................

95.1

\a\ Includes emissions from both the recovery furnace and pulp mill lime kiln.

Table AA-2 to Subpart AA of Part 98--Kraft Lime Kiln and Calciner Emissions Factors for Fossil Fuel-Based CO2,

CH4, and N2O

Fossil fuel-based emissions factors (kg/mmBtu HHV)

Fuel

Kraft lime kilns

Kraft calciners

CO2

CH4

N2O

CO2

CH4

N2O

Residual Oil......................

76.7

0.0027

76.7

0.0027

0.0003

Distillate Oil....................

73.5

0.0004

Natural Gas.......................

56.0

0.0001

Biogas............................

0.0001

Subpart BB--Silicon Carbide Production

Sec. 98.280 Definition of the source category.

Silicon carbide production includes any process that produces silicon carbide for abrasive purposes.

Sec. 98.281 Reporting threshold.

You must report GHG emissions under this subpart if your facility contains a silicon carbide production process and the facility meets the requirements of either Sec. 98.2(a)(1) or (a)(2).

Sec. 98.282 GHGs to report.

You must report:

(a) CO2and CH4process emissions from all silicon carbide process units or furnaces combined.

(b) CO2,CH4, and N2O emissions from each stationary combustion unit. You must report these emissions under subpart C of this part (General Stationary Fuel Combustion

Sources) by following the requirements of subpart C.

Sec. 98.283 Calculating GHG emissions.

You must calculate and report the annual process CO2 emissions from each silicon carbide process unit or production furnace using the procedures in either paragraph (a) or (b) of this section.

You must determine CH4process emissions in accordance with the procedures specified in paragraph (d) of this section.

(a) Calculate and report under this subpart the process

CO2emissions by operating and maintaining CEMS according to the Tier 4 Calculation Methodology specified in Sec. 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part

(General Stationary Fuel Combustion Sources).

(b) Calculate and report under this subpart the process

CO2emissions using the procedures in paragraphs (b)(1) and

(b)(2) of this section.

(1) Use Equation BB-1 of this section to calculate the facility- specific emissions factor for determining CO2emissions. The carbon content must be measured monthly and used to calculate a monthly

CO2emisssions factor:

GRAPHIC

TIFF OMITTED TR30OC09.115

Where:

EFCO2,n= CO2emissions factor in month n

(metric tons CO2/metric ton of petroleum coke consumed). 0.65 = Adjustment factor for the amount of carbon in silicon carbide product (assuming 35 percent of carbon input is in the carbide product).

CCFn= Carbon content factor for petroleum coke consumed in month n from the supplier or as measured by the applicable method incorporated by reference in Sec. 98.7 according to Sec. 98.284(c)

(percent by weight expressed as a decimal fraction). 44/12 = Ratio of molecular weights, CO2to carbon.

(2) Use Equation BB-2 of this section to calculate annual

CO2process emissions from all silicone carbide production:

GRAPHIC

TIFF OMITTED TR30OC09.116

Where:

CO2= Annual CO2emissions from silicon carbide production facility (metric tons CO2).

Tn= Petroleum coke consumption in month n (tons).

Page 56467

EFCO2,n= CO2emissions factor from month n

(calculated in Equation BB-1 of this section). 2000/2205 = Conversion factor to convert tons to metric tons. n = Number of month.

(c) If GHG emissions from a silicon carbide production furnace or process unit are vented through the same stack as any combustion unit or process equipment that reports CO2emissions using a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Fuel Combustion Sources), then the calculation methodology in paragraph (b) of this section shall not be used to calculate process emissions. The owner or operator shall report under this subpart the combined stack emissions according to the Tier 4

Calculation Methodology in Sec. 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part.

(d) You must calculate annual process CH4emissions from all silicon carbide production combined using Equation BB-3 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.117

Where:

CH4= Annual CH4emissions from silicon carbide production facility (metric tons CH4).

Tn= Petroleum coke consumption in month n (tons). 10.2 = CH4emissions factor (kg CH4/metric ton coke). 2000/2205 = Conversion factor to convert tons to metric tons. 0.001 = Conversion factor from kilograms to metric tons. n = Number of month.

Sec. 98.284 Monitoring and QA/QC requirements.

(a) You must measure your consumption of petroleum coke using plant instruments used for accounting purposes including direct measurement weighing the petroleum coke fed into your process (by belt scales or a similar device) or through the use of purchase records.

(b) You must document the procedures used to ensure the accuracy of monthly petroleum coke consumption measurements.

(c) For CO2process emissions, you must determine the monthly carbon content of the petroleum coke using reports from the supplier. Alternatively, facilities can measure monthly carbon contents of the petroleum coke using ASTM D3176-89 (Reapproved 2002) Standard

Practice for Ultimate Analysis of Coal and Coke (incorporated by reference, see Sec. 98.7) and ASTM D5373-08 Standard Test Methods for

Instrumental Determination of Carbon, Hydrogen, and Nitrogen in

Laboratory Samples of Coal (incorporated by reference, see Sec. 98.7).

(d) For quality assurance and quality control of the supplier data, you must conduct an annual measurement of the carbon content of the petroleum coke using ASTM D3176-89 and ASTM D5373-08 Standard Test

Methods for Instrumental Determination of Carbon, Hydrogen, and

Nitrogen in Laboratory Samples of Coal (incorporated by reference, see

Sec. 98.7).

Sec. 98.285 Procedures for estimating missing data.

For the petroleum coke input procedure in Sec. 98.283(b), a complete record of all measured parameters used in the GHG emissions calculations is required (e.g., carbon content values, etc.).

Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in the paragraphs (a) and (b) of this section. You must document and keep records of the procedures used for all such estimates.

(a) For each missing value of the monthly carbon content of petroleum coke, the substitute data value shall be the arithmetic average of the quality-assured values of carbon contents immediately preceding and immediately following the missing data incident. If no quality-assured data on carbon contents are available prior to the missing data incident, the substitute data value shall be the first quality-assured value for carbon contents obtained after the missing data period.

(b) For each missing value of the monthly petroleum coke consumption, the substitute data value shall be the best available estimate of the petroleum coke consumption based on all available process data or information used for accounting purposes (such as purchase records).

Sec. 98.286 Data reporting requirements.

In addition to the information required by Sec. 98.3(c), each annual report must contain the information specified in paragraphs (a) or (b) of this section, as applicable for each silicon carbide production facility.

(a) If a CEMS is used to measure process CO2emissions, you must report under this subpart the relevant information required for the Tier 4 Calculation Methodology in Sec. 98.36 and the information listed in this paragraph (a):

(1) Annual consumption of petroleum coke (tons).

(2) Annual production of silicon carbide (tons).

(3) Annual production capacity of silicon carbide (tons).

(b) If a CEMS is not used to measure process CO2 emissions, you must report the information listed in this paragraph (b) for all furnaces combined:

(1) Monthly consumption of petroleum coke (tons).

(2) Annual production of silicon carbide (tons).

(3) Annual production capacity of silicon carbide (tons).

(4) Carbon content factor of petroleum coke from the supplier or as measured by the applicable method in Sec. 98.284(c) for each month

(percent by weight expressed as a decimal fraction).

(5) Whether carbon content of the petroleum coke is based on reports from the supplier or through self measurement using applicable

ASTM standard method.

(6) CO2emissions factor calculated for each month

(metric tons CO2/metric ton of petroleum coke consumed).

(7) Sampling analysis results for carbon content of consumed petroleum coke as determined for QA/QC of supplier data under Sec. 98.284(d) (percent by weight expressed as a decimal fraction).

(8) Number of times in the reporting year that missing data procedures were followed to measure the carbon contents of petroleum coke (number of months) and petroleum coke consumption (number of months).

Sec. 98.287 Records that must be retained.

In addition to the records required by Sec. 98.3(g), you must retain the records specified in paragraphs (a) and (b) of this section for each silicon carbide production facility.

(a) If a CEMS is used to measure CO2emissions, you must retain under this subpart the records required for the Tier 4

Calculation Methodology in Sec. 98.37

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and the information listed in this paragraph (a):

(1) Records of all petroleum coke purchases.

(2) Annual operating hours.

(b) If a CEMS is not used to measure emissions, you must retain records for the information listed in this paragraph (b):

(1) Records of all analyses and calculations conducted for reported data listed in Sec. 98.286(b).

(2) Records of all petroleum coke purchases.

(3) Annual operating hours.

Sec. 98.288 Definitions.

All terms used in this subpart have the same meaning given in the

Clean Air Act and subpart A of this part.

Subpart CC--Soda Ash Manufacturing

Sec. 98.290 Definition of the source category.

(a) A soda ash manufacturing facility is any facility with a manufacturing line that produces soda ash by one of the methods in paragraphs (a)(1) through (3) of this section:

(1) Calcining trona.

(2) Calcining sodium sesquicarbonate.

(3) Using a liquid alkaline feedstock process that directly produces CO2.

(b) In the context of the soda ash manufacturing sector,

``calcining'' means the thermal/chemical conversion of the bicarbonate fraction of the feedstock to sodium carbonate.

Sec. 98.291 Reporting threshold.

You must report GHG emissions under this subpart if your facility contains a soda ash manufacturing process and the facility meets the requirements of either Sec. 98.2(a)(1) or (a)(2).

Sec. 98.292 GHGs to report.

You must report:

(a) CO2process emissions from each soda ash manufacturing line combined.

(b) CO2combustion emissions from each soda ash manufacturing line.

(c) CH4and N2O combustion emissions from each soda ash manufacturing line. You must calculate and report these emissions under subpart C of this part (General Stationary Fuel

Combustion Sources) by following the requirements of subpart C.

(d) CO2,CH4, and N2O emissions from each stationary combustion unit other than soda ash manufacturing lines. You must calculate and report these emissions under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.

Sec. 98.293 Calculating GHG emissions.

You must calculate and report the annual process CO2 emissions from each soda ash manufacturing line using the procedures specified in paragraph (a) or (b) of this section.

(a) For each soda ash manufacturing line that meets the conditions specified in Sec. 98.33(b)(4)(ii) or (b)(4)(iii), you must calculate and report under this subpart the combined process and combustion

CO2emissions by operating and maintaining a CEMS to measure

CO2emissions according to the Tier 4 Calculation

Methodology specified in Sec. 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General Stationary

Fuel Combustion Sources).

(b) For each soda ash manufacturing line that is not subject to the requirements in paragraph (a) of this section, calculate and report the process CO2emissions from the soda ash manufacturing line by using the procedure in either paragraphs (b)(1), (b)(2), or (b)(3) of this section; and the combustion CO2emissions using the procedure in paragraph (b)(4) of this section.

(1) Calculate and report under this subpart the combined process and combustion CO2emissions by operating and maintaining a

CEMS to measure CO2emissions according to the Tier 4

Calculation Methodology specified in Sec. 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part (General

Stationary Fuel Combustion Sources).

(2) Use either Equation CC-1 or Equation CC-2 of this section to calculate annual CO2process emissions from each manufacturing line that calcines trona to produce soda ash:

GRAPHIC

TIFF OMITTED TR30OC09.118

GRAPHIC

TIFF OMITTED TR30OC09.119

Where:

Ek= Annual CO2process emissions from each manufacturing line, k (metric tons).

(ICT)n= Inorganic carbon content (percent by weight, expressed as a decimal fraction) in trona input, from the carbon analysis results for month n. This represents the ratio of trona to trona ore.

(ICsa)n= Inorganic carbon content (percent by weight, expressed as a decimal fraction) in soda ash output, from the carbon analysis results for month n. This represents the purity of the soda ash produced.

(Tt)n= Mass of trona input in month n (tons).

(Tsa)n= Mass of soda ash output in month n

(tons). 2000/2205 = Conversion factor to convert tons to metric tons. 0.097/1 = Ratio of ton of CO2emitted for each ton of trona. 0.138/1 = Ratio of ton of CO2emitted for each ton of soda ash produced.

(3) Site-specific emission factor method. Use Equations CC-3, CC-4, and CC-5 of this section to determine annual CO2process emissions from manufacturing lines that use the liquid alkaline feedstock process to produce soda ash. You must conduct an annual performance test and measure CO2emissions and flow rates at all process vents from the mine water stripper/evaporator for each manufacturing line and calculate CO2emissions as described in paragraphs (b)(3)(i) through (b)(3)(iv) of this section.

(i) During the performance test, you must measure the process vent flow from each process vent during the test and calculate the average rate for the test period in metric tons per hour.

(ii) Using the test data, you must calculate the hourly

CO2emission rate using Equation CC-3 of this section:

Page 56469

GRAPHIC

TIFF OMITTED TR30OC09.120

Where:

ERCO2= CO2mass emission rate (metric tons/ hour).

CCO2= Hourly CO2concentration (percent

CO2) as determined by Sec. 98.294(c). 10000 = Parts per million per percent 2.59 x 10-\9\ = Conversion factor (pounds-mole/dscf/ppm). 44 = Pounds per pound-mole of carbon dioxide.

Q = Stack gas volumetric flow rate per minute (dscfm). 60 = Minutes per hour 4.53 x 10 -\4\ = Conversion factor (metric tons/pound)

(iii) Using the test data, you must calculate a CO2 emission factor for the process using Equation CC-4 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.121

Where:

EFCO2= CO2emission factor (metric tons

CO2/metric ton of process vent flow from mine water stripper/evaporator).

ERCO2= CO2mass emission rate (metric tons/ hour).

Vt= Process vent flow rate from mine water stripper/ evaporator during annual performance test (pounds/hour). 4.53 x 10-4= Conversion factor (metric tons/pound)

(iv) You must calculate annual CO2process emissions from each manufacturing line using Equation CC-5 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.122

Where:

Ek= Annual CO2process emissions for each manufacturing line, k (metric tons).

EFCO2= CO2emission factor (metric tons

CO2/metric ton of process vent flow from mine water stripper/evaporator).

Va= Annual process vent flow rate from mine water stripper/evaporator (thousand pounds/hour).

H = Annual operating hours for the each manufacturing line. 0.453 = Conversion factor (metric tons/thousand pounds).

(4) Calculate and report under subpart C of this part (General

Stationary Fuel Combustion Sources) the combustion CO2,

CH4, and N2O emissions in the soda ash manufacturing line according to the applicable requirements in subpart

Sec. 98.294 Monitoring and QA/QC requirements.

Section 98.293 provides three different procedures for emission calculations. The appropriate paragraphs (a) through (c) of this section should be used for the procedure chosen.

(a) If you determine your emissions using Sec. 98.293(b)(2)

(Equation CC-1 of this subpart) you must:

(1) Determine the monthly inorganic carbon content of the trona from a weekly composite analysis for each soda ash manufacturing line, using a modified version of ASTM E359-00 (Reapproved 2005)e1, Standard

Test Methods for Analysis of Soda Ash (Sodium Carbonate) (incorporated by reference, see Sec. 98.7). ASTM E359-00(Reapproved 2005) e1 is designed to measure the total alkalinity in soda ash not in trona. The modified method of ASTM E359-00 adjusts the regular ASTM method to expresse the results in terms of trona. Although ASTM E359-00

(Reapproved 2005) e1 uses manual titration, suitable autotitrators may also be used for this determination.

(2) Measure the mass of trona input produced by each soda ash manufacturing line on a monthly basis using belt scales or methods used for accounting purposes.

(3) Document the procedures used to ensure the accuracy of the monthly measurements of trona consumed.

(b) If you calculate CO2process emissions based on soda ash production (Sec. 98.293(b)(2) Equation CC-2 of this subpart), you must:

(1) Determine the inorganic carbon content of the soda ash (i.e., soda ash purity) using ASTM E359-00 (Reapproved 2005) e1 Standard Test

Methods for Analysis of Soda Ash (Sodium Carbonate) (incorporated by reference, see Sec. 98.7). Although ASTM E359-00 (Reapproved 2005) e1 uses manual titration, suitable autotitrators may also be used for this determination.

(2) Measure the mass of soda ash produced by each soda ash manufacturing line on a monthly basis using belt scales, by weighing the soda ash at the truck or rail loadout points of your facility, or methods used for accounting purposes.

(3) Document the procedures used to ensure the accuracy of the monthly measurements of soda ash produced.

(1) Conduct an annual performance test that is based on representative performance (i.e., performance based on normal operating conditions) of the affected process.

(2) Sample the stack gas and conduct three emissions test runs of 1 hour each.

(3) Conduct the stack test using EPA Method 3A at 40 CFR part 60, appendix A-2 to measure the CO2concentration, Method 2, 2A, 2C, 2D, or 2F at 40 CFR part 60, appendix A-1 or Method 26 at 40 CFR part 60, appendix A-2 to determine the stack gas volumetric flow rate.

All QA/QC procedures specified in the reference test methods and any associated performance specifications apply. For each test, the facility must prepare an emission factor determination report that must include the items in paragraphs (c)(3)(i) through (c)(3)(iii) of this section.

(i) Analysis of samples, determination of emissions, and raw data.

(ii) All information and data used to derive the emissions factor(s).

(iii) You must determine the average process vent flow rate from the mine water stripper/evaporater during each test and document how it was determined.

(4) You must also determine the annual vent flow rate from the mine water stripper/evaporater from monthly information using the same plant instruments or procedures used for accounting purposes (i.e., volumetric flow meter).

Sec. 98.295 Procedures for estimating missing data.

For the emission calculation methodologies in Sec. 98.293(b)(2) and (b)(3), a complete record of all measured parameters used in the

GHG emissions calculations is required (e.g., inorganic carbon content values, etc.). Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in the paragraphs (a) through (d) of this

Page 56470

section. You must document and keep records of the procedures used for all such missing value estimates.

(a) For each missing value of the weekly composite of inorganic carbon content of either soda ash or trona, the substitute data value shall be the arithmetic average of the quality-assured values of inorganic carbon contents from the week immediately preceding and the week immediately following the missing data incident. If no quality- assured data on inorganic carbon contents are available prior to the missing data incident, the substitute data value shall be the first quality-assured value for carbon contents obtained after the missing data period.

(b) For each missing value of either the monthly soda ash production or the trona consumption, the substitute data value shall be the best available estimate(s) of the parameter(s), based on all available process data or data used for accounting purposes.

(hourly CO2concentration, stack gas volumetric flow rate, or average process vent flow from mine water stripper/evaporator during performance test), you must repeat the annual performance test following the calculation and monitoring and QA/QC requirements under

Sec. Sec. 98.293(b)(3) and 98.294(c).

(d) For each missing value of the monthly process vent flow rate from mine water stripper/evaporator, the subsititute data value shall be the best available estimate(s) of the parameter(s), based on all available process data or the lesser of the maximum capacity of the system or the maximum rate the meter can measure.

Sec. 98.296 Data reporting requirements.

In addition to the information required by Sec. 98.3(c), each annual report must contain the information specified in paragraphs (a) or (b) of this section, as appropriate for each soda ash manufacturing facility.

(a) If a CEMS is used to measure CO2emissions, then you must report under this subpart the relevant information required under

Sec. 98.36 and the following information in this paragraph (a):

(1) Annual consumption of trona or liquid alkaline feedstock for each manufacturing line (metric tons).

(2) Annual production of soda ash for each manufacturing line

(tons).

(3) Annual production capacity of soda ash for each manufacturing line (tons).

(4) Identification number of each manufacturing line.

(b) If a CEMS is not used to measure CO2emissions, then you must report the information listed in this paragraph (b):

(1) Identification number of each manufacturing line.

(2) Annual process CO2emissions from each soda ash manufacturing line (metric tons).

(3) Annual production of soda ash (tons).

(4) Annual production capacity of soda ash for each manufacturing line (tons).

(5) Monthly consumption of trona or liquid alkaline feedstock for each manufacturing line (tons).

(6) Monthly production of soda ash for each manufacturing line

(metric tons).

(7) Inorganic carbon content factor of trona or soda ash (depending on use of Equations CC-1 or CC-2 of this subpart) as measured by the applicable method in Sec. 98.294(b) or (c) for each month (percent by weight expressed as a decimal fraction).

(8) Whether CO2emissions for each manufacturing line were calculated using a trona input method as described in Equation CC- 1 of this subpart, a soda ash output method as described in Equation

CC-2 of this subpart, or a site-specific emission factor method as described in Equations CC-3 through CC-5 of this subpart.

(9) Number of manufacturing lines located used to produce soda ash.

(10) If you produce soda ash using the liquid alkaline feedstock process and use the site-specific emission factor method (Sec. 98.293(b)(3)) to estimate emissions then you must report the following relevant information:

(i) Stack gas volumetric flow rate per minute (dscfm)

(ii) Hourly CO2concentration (percent CO2)

(iii) CO2emission factor (metric tons CO2/ metric tons of process vent flow from mine water stripper/evaporator).

(iv) CO2mass emission rate (metric tons/hour).

(v) Average process vent flow from mine water stripper/evaporater during performance test (pounds/hour).

(vi) Annual process vent flow rate from mine stripper/evaporator

(thousand pounds/hour).

(vii) Annual operating hours for each manufacturing line used to produce soda ash using liquid alkaline feedstock (hours).

(11) Number of times missing data procedures were used and for which parameter as specified in this paragraph (b)(11):

(i) Trona or soda ash (number of months).

(ii) Inorganic carbon contents of trona or soda ash (weeks).

(iii) Process vent flow rate from mine water stripper/evaporator

(number of months).

(iv) Stack gas volumetric flow rate during performance test (number of times).

(v) Hourly CO2concentration (number of times).

(vi) Average vent process vent flow rate from mine stripper/ evaporator during performance test (number of times).

Sec. 98.297 Records that must be retained.

In addition to the records required by Sec. 98.3(g), you must retain the records specified in paragraphs (a) and (b) of this section for each soda ash manufacturing line.

(a) If a CEMS is used to measure CO2emissions, then you must retain under this subpart the records required for the Tier 4

Calculation Methodology specified in subpart C of this part and the information listed in this paragraph (a):

(1) Monthly production of soda ash (tons)

(2) Monthly consumption of trona or liquid alkaline feedstock

(tons)

(3) Annual operating hours (hours).

(b) If a CEMS is not used to measure emissions, then you must retain records for the information listed in this paragraph (b):

(1) Records of all analyses and calculations conducted for determining all reported data as listed in Sec. 98.296(b).

(2) If using Equation CC-1 or CC-2 of this subpart, weekly inorganic carbon content factor of trona or soda ash, depending on method chosen, as measured by the applicable method in Sec. 98.294(b)

(percent by weight expressed as a decimal fraction).

(3) Annual operating hours for each manufacturing line used to produce soda ash (hours).

(4) You must document the procedures used to ensure the accuracy of the monthly trona consumption or soda ash production measurements including, but not limited to, calibration of weighing equipment and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided.

(5) If you produce soda ash using the liquid alkaline feedstock process and use the site-specific emission factor method to estimate emissions (Sec. 98.293(b)(3)) then you must also retain the following relevant information:

(i) Records of performance test results.

(ii) You must document the procedures used to ensure the accuracy

Page 56471

of the annual average vent flow measurements including, but not limited to, calibration of flow rate meters and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided.

Sec. 98.298 Definitions.

All terms used in this subpart have the same meaning given in the

Clean Air Act and subpart A of this part.

Subpart DD--[Reserved]

Subpart EE--Titanium Dioxide Production

Sec. 98.310 Definition of the source category.

The titanium dioxide production source category consists of facilities that use the chloride process to produce titanium dioxide.

Sec. 98.311 Reporting threshold.

You must report GHG emissions under this subpart if your facility contains a titanium dioxide production process and the facility meets the requirements of either Sec. 98.2(a)(1) or (a)(2).

Sec. 98.312 GHGs to report.

(a) You must report CO2process emissions from each chloride process line as required in this subpart.

(b) You must report CO2, CH4, and

N2O emissions from each stationary combustion unit under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.

Sec. 98.313 Calculating GHG emissions.

You must calculate and report the annual process CO2 emissions for each chloride process line using the procedures in either paragraph (a) or (b) of this section.

(a) Calculate and report under this subpart the process

CO2emissions by operating and maintaining a CEMS according to the Tier 4 Calculation Methodology specified in Sec. 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part

(General Stationary Fuel Combustion Sources).

(b) Calculate and report under this subpart the annual process

CO2emissions for each chloride process line by determining the mass of calcined petroleum coke consumed in each line as specified in paragraphs (b)(1) through (b)(3) of this section. Use Equation EE-1 of this section to calulate annual combined process CO2 emissions from all process lines and use Equation EE-2 of this section to calculate annual process CO2emissions for each process line. If your facility generates carbon-containing waste, use Equation

EE-3 of this section to estimate the annual quantity of carbon- containing waste generated and its carbon contents according to Sec. 98.314(e) and (f):

(1) You must calculate the annual CO2process emissions from all process lines at the facility using Equation EE-1 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.123

Where:

CO2= Annual CO2emissions from titanium dioxide production facility (metric tons/year).

Ep= Annual CO2emissions from chloride process line p (metric tons), determined using Equation EE-2 of this section. p = Process line. m = Number of separate chloride process lines located at the facility.

(2) You must calculate the annual CO2process emissions from each process lines at the facility using Equation EE-2 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.124

Where:

Ep= Annual CO2mass emissions from chloride process line p (metric tons).

Cp,n= Calcined petroleum coke consumption for process line p in month n (tons). 44/12 = Ratio of molecular weights, CO2to carbon. 2000/2205 = Conversion of tons to metric tons.

CCFn= Carbon content factor for petroleum coke consumed in month n from the supplier or as measured by the applicable method incorporated by reference in Sec. 98.7 according to Sec. 98.314(c)

(percent by weight expressed as a decimal fraction). n = Number of month.

(3) If facility generates carbon-containing waste, you must calculate the total annual quantity of carbon-containing waste produced from all process lines using Equation EE-3 of this section and its carbon contents according to Sec. 98.314(e) and (f):

GRAPHIC

TIFF OMITTED TR30OC09.125

Where:

TWC = Annual production of carbon-containing waste from titanium dioxide production facility (tons).

WCp,n= Production of carbon-containing waste in month n from chloride process line p (tons). p = Process line. m = Total number of process lines. n = Number of month.

(c) If GHG emissions from a chloride process line are vented through the same stack as any combustion unit or process equipment that reports CO2emissions using a CEMS that complies with the

Tier 4 Calculation Methodology in subpart C of this part (General

Stationary Fuel Combustion Sources), then the calculation methodology in paragraph (b) of this section shall not be used to calculate process

CO2emissions. The owner or operator shall report under this subpart the combined stack emissions according to the Tier 4

Calculation Methodology in Sec. 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part.

Sec. 98.314 Monitoring and QA/QC requirements.

(a) You must measure your consumption of calcined petroleum coke using plant instruments used for accounting purposes including direct measurement weighing the petroleum coke fed into your process (by belt scales or a similar device) or through the use of purchase records.

(b) You must document the procedures used to ensure the accuracy of monthly calcined petroleum coke consumption measurements.

(c) You must determine the carbon content of the calcined petroleum coke each month based on reports from the supplier. Alternatively, facilities can measure monthly carbon contents of the petroleum coke using ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate

Analysis of Coal and Coke (incorporated by reference, see Sec. 98.7) and ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal

(incorporated by reference, see Sec. 98.7).

Page 56472

(d) For quality assurance and quality control of the supplier data, you must conduct an annual measurement of the carbon content from a representative sample of the petroleum coke consumed using ASTM D3176- 89 and ASTM D5373-08.

(e) You must determine the quantity of carbon-containing waste generated from the each titanium production line dioxide using plant instruments used for accounting purposes including direct measurement weighing the carbon-containing waste not used during the process (by belt scales or a similar device) or through the use of sales records.

(f) You must determine the carbon contents of the carbon-containing waste from each titanium production line on an annual basis by collecting and analyzing a representative sample of the material using

ASTM D3176-89 and ASTM D5373-08.

Sec. 98.315 Procedures for estimating missing data.

For the petroleum coke input procedure in Sec. 98.313(b), a complete record of all measured parameters used in the GHG emissions calculations is required (e.g., carbon content values, etc.).

Therefore, whenever the monitoring and quality assurance procedures in

Sec. 98.315 cannot be followed, a substitute data value for the missing parameter shall be used in the calculations as specified in the paragraphs (a) through (c) of this section. You must document and keep records of the procedures used for all such estimates.

(a) For each missing value of the monthly carbon content of calcined petroleum coke the substitute data value shall be the arithmetic average of the quality-assured values of carbon contents for the month immediately preceding and the month immediately following the missing data incident. If no quality-assured data on carbon contents are available prior to the missing data incident, the substitute data value shall be the first quality-assured value for carbon contents obtained after the missing data period.

(b) For each missing value of the monthly calcined petroleum coke consumption and/or carbon-containing waste, the substitute data value shall be the best available estimate of the monthly petroleum coke consumption based on all available process data or information used for accounting purposes (such as purchase records).

(c) For each missing value of the carbon content of carbon- containing waste, you must conduct a new analysis following the procedures in Sec. 98.314(f).

Sec. 98.316 Data reporting requirements.

(a) If a CEMS is used to measure CO2emissions, then you must report the relevant information required under Sec. 98.36(e)(2)(vi) for the Tier 4 Calculation Methodology and the following information in this paragraph (a).

(1) Identification number of each process line.

(2) Annual consumption of calcined petroleum coke (tons).

(3) Annual production of titanium dioxide (tons).

(4) Annual production capacity of titanium dioxide (tons).

(5) Annual production of carbon-containing waste (tons), if applicable.

(b) If a CEMS is not used to measure CO2emissions, then you must report the information listed in this paragraph (b):

(1) Identification number of each process line.

(2) Annual CO2emissions from each chloride process line

(metric tons/year).

(3) Annual consumption of calcined petroleum coke for each process line (tons).

(4) Annual production of titanium dioxide for each process line

(tons).

(5) Annual production capacity of titanium dioxide for each process line (tons).

(6) Calcined petroleum coke consumption for each process line for each month (tons).

(7) Annual production of carbon-containing waste for each process line (tons), if applicable.

(8) Monthly production of titanium dioxide for each process line

(tons).

(9) Monthly carbon content factor of petroleum coke from the supplier (percent by weight expressed as a decimal fraction).

(10) Whether monthly carbon content of the petroleum coke is based on reports from the supplier or through self measurement using applicable ASTM standard methods.

(11) Carbon content for carbon-containing waste (percent by weight expressed as a decimal fraction).

(12) If carbon content of petroleum coke is based on self measurement, the ASTM standard methods used.

(13) Sampling analysis results of carbon content of petroleum coke as determined for QA/QC of supplier data under Sec. 98.314(d) (percent by weight expressed as a decimal fraction).

(14) Number of separate chloride process lines located at the facility.

(15) The number of times in the reporting year that missing data procedures were followed to measure the carbon contents of petroleum coke (number of months); petroleum coke consumption (number of months); carbon-containing waste generated (number of months); and carbon contents of the carbon-containing waste (number of times during year).

Sec. 98.317 Records that must be retained.

In addition to the records required by Sec. 98.3(g), you must retain the records specified in paragraphs (a) and (b) of this section for each titanium dioxide production facility.

(a) If a CEMS is used to measure CO2emissions, then you must retain under this subpart required for the Tier 4 Calculation

Methodology in Sec. 98.37 and the information listed in this paragraph

(a):

(1) Records of all calcined petroleum coke purchases.

(2) Annual operating hours for each titanium dioxide process line.

(b) If a CEMS is not used to measure CO2emissions, then you must retain records for the information listed in this paraghraph:

(1) Records of all calcined petroleum coke purchases (tons).

(2) Records of all analyses and calculations conducted for all reported data as listed in Sec. 98.316(b).

(3) Sampling analysis results for carbon content of consumed calcined petroleum coke (percent by weight expressed as a decimal fraction).

(4) Sampling analysis results for the carbon content of carbon containing waste (percent by weight expressed as a decimal fraction), if applicable.

(5) Monthly production of carbon-containing waste (tons).

(6) You must document the procedures used to ensure the accuracy of the monthly petroleum coke consumption and quantity of carbon- containing waste measurement including, but not limited to, calibration of weighing equipment and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided.

(7) Annual operating hours for each titanium dioxide process line

(hours).

Sec. 98.318 Definitions.

All terms used in this subpart have the same meaning given in the

Clean Air Act and subpart A of this part.

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Subpart FF--[Reserved]

Subpart GG--Zinc Production

Sec. 98.330 Definition of the source category.

The zinc production source category consists of zinc smelters and secondary zinc recycling facilities.

Sec. 98.331 Reporting threshold.

You must report GHG emissions under this subpart if your facility contains a zinc production process and the facility meets the requirements of either Sec. 98.2(a)(1) or (2).

Sec. 98.332 GHGs to report.

You must report:

(a) CO2process emissions from each Waelz kiln and electrothermic furnace used for zinc production.

(b) CO2, CH4, and N2O combustion emissions from each Waelz kiln. You must calculate and report these emissions under subpart C of this part (General Stationary Fuel

Combustion Sources) by following the requirements of subpart C.

(c) CO2, CH4, and N2O emissions from each stationary combustion unit other than Waelz kilns. You must report these emissions under subpart C of this part (General Stationary

Fuel Combustion Sources) by following the requirements of subpart C.

Sec. 98.333 Calculating GHG emissions.

You must calculate and report the annual process CO2 emissions using the procedures specified in either paragraph (a) or (b) of this section.

(a) Calculate and report under this subpart the process or combined process and combustion CO2emissions by operating and maintaining a CEMS according to the Tier 4 Calculation Methodology in

Sec. 98.33(a)(4) and all associated requirements for Tier 4 in subpart

C of this part (General Stationary Fuel Combustion Sources).

(b) Calculate and report under this subpart the process

CO2emissions by following paragraphs (b)(1) and (b)(2) of this section.

(1) For each Waelz kiln or electrothermic furnace at your facility used for zinc production, you must determine the mass of carbon in each carbon-containing material, other than fuel, that is fed, charged, or otherwise introduced into each Waelz kiln and electrothermic furnace at your facility for each year and calculate annual CO2process emissions from each affected unit at your facility using Equation GG-1 of this section. For electrothermic furnaces, carbon containing input materials include carbon eletrodes and carbonaceous reducing agents.

For Waelz kilns, carbon containing input materials include carbonaceous reducing agents. If you document that a specific material contributes less than 1 percent of the total carbon into the process, you do not have to include the material in your calculation using Equation R-1 of

Sec. 98.183.

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Where:

ECO2k= Annual CO2process emissions from individual Waelz kiln or electrothermic furnace ``k'' (metric tons). 44/12 = Ratio of molecular weights, CO2to carbon. 2000/2205 = Conversion factor to convert tons to metric tons.

(Zinc)k= Annual mass of zinc bearing material charged to kiln or furnace ''k'' (tons).

(CZinc)k= Carbon content of the zinc bearing material, from the annual carbon analysis for kiln or furnace ``k''

(percent by weight, expressed as a decimal fraction).

(Flux)k= Annual mass of flux materials (e.g., limestone, dolomite) charged to kiln or furnace ``k'' (tons).

(CFlux)k= Carbon content of the flux materials charged to kiln or furnace ``k'', from the annual carbon analysis (percent by weight, expressed as a decimal fraction).

(Electrode)k= Annual mass of carbon electrode consumed in kiln or furnace ``k'' (tons).

(CElectrode)k= Carbon content of the carbon electrode consumed in kiln or furnace ``k'', from the annual carbon analysis (percent by weight, expressed as a decimal fraction).

(Carbon)k= Annual mass of carbonaceous materials (e.g., coal, coke) charged to the kiln or furnace ``k''(tons).

(CCarbon)kCarbon content of the carbonaceous materials charged to kiln or furnace, ``k'', from the annual carbon analysis (percent by weight, expressed as a decimal fraction).

(2) You must determine the CO2emissions from all of the

Waelz kilns or electrothermic furnaces at your facility using Equation

GG-2 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.127

Where:

CO2= Annual combined CO2emissions from all

Waelz kilns or electrothermic furnaces (tons).

ECO2k = Annual CO2emissions from each Waelz kiln or electrothermic furnace k calculated using Equation GG-1 of this section (tons). n = Total number of Waelz kilns or electrothermic furnaces at facility used for the zinc production.

(c) If GHG emissions from a Waelz kiln or electrothermic furnace are vented through the same stack as any combustion unit or process equipment that reports CO2emissions using a CEMS that complies with the Tier 4 Calculation Methodology in subpart C of this part (General Stationary Fuel Combustion Sources), then the calculation methodology in paragraph (b) of this section shall not be used to calculate process emissions. The owner or operator shall report under this subpart the combined stack emissions according to the Tier 4

Calculation Methodology in Sec. 98.33(a)(4) and all associated requirements for Tier 4 in subpart C of this part.

Sec. 98.334 Monitoring and QA/QC requirements.

If you determine CO2emissions using the carbon input procedure in Sec. 98.333(b)(1) and (b)(2), you must meet the requirements specified in paragraphs (a) and (b) of this section.

(a) Determine the mass of each solid carbon-containing input material consumed using facility instruments, procedures, or records used for accounting purposes including direct measurement weighing or through the use of purchase records same plant instruments or procedures that are used for accounting purposes (such as weigh hoppers, belt weigh feeders, weighed purchased quantities in shipments or containers, combination of bulk density and volume measurements, etc.). Record the total mass for the materials consumed each calendar month and sum the monthly mass to determine the annual mass for each input material.

(b) For each input material identified in paragraph (a) of this section, you must determine the average carbon content of the material consumed or used in the calendar year using the methods specified in either paragraph (b)(1) or (b)(2) of this section.

(1) Information provided by your material supplier.

(2) Collecting and analyzing at least three representative samples of the material using the appropriate testing method. For each carbon- containing

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input material identified for which the carbon content is not provided by your material supplier, the carbon content of the material must be analyzed at least annually using the appropriate standard methods (and their QA/QC procedures), which are identified in paragraphs (b)(2)(i) through (b)(2)(iii) of this section, as applicable. If you document that a specific process input or output contributes less than one percent of the total mass of carbon into or out of the process, you do not have to determine the monthly mass or annual carbon content of that input or output.

(i) Using ASTM E1941-04 Standard Test Method for Determination of

Carbon in Refractory and Reactive Metals and Their Alloys (incorporated by reference, see Sec. 98.7), analyze zinc bearing materials.

(ii) Using ASTM D5373-08 Standard Test Methods for Instrumental

Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see Sec. 98.7), analyze carbonaceous reducing agents and carbon electrodes.

(iii) Using ASTM C25-06 Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime (incorporated by reference, see Sec. 98.7), analyze flux materials such as limestone or dolomite.

Sec. 98.335 Procedures for estimating missing data.

For the carbon input procedure in Sec. 98.333(b), a complete record of all measured parameters used in the GHG emissions calculations is required (e.g., raw materials carbon content values, etc.). Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in paragraphs

(a) and (b) of this section. You must document and keep records of the procedures used for all such estimates.

(a) For missing records of the carbon content of inputs for facilities that estimate emissions using the carbon input procedure in

Sec. 98.333(b); 100 percent data availability is required. You must repeat the test for average carbon contents of inputs according to the procedures in Sec. 98.335(b) if data are missing.

(b) For missing records of the annual mass of carbon-containing inputs using the carbon input procedure in Sec. 98.333(b), the substitute data value must be based on the best available estimate of the mass of the input material from all available process data or information used for accounting purposes, such as purchase records.

Sec. 98.336 Data reporting requirements.

In addition to the information required by Sec. 98.3(c), each annual report must contain the information specified in paragraphs (a) or (b) of this section, as applicable, for each Waelz kiln or electrothermic furnace.

(a) If a CEMS is used to measure CO2emissions, then you must report under this subpart the relevant information required for the Tier 4 Calculation Methodology in Sec. 98.37 and the information listed in this paragraph (a):

(1) Annual zinc product production capacity (tons).

(2) Annual production quantity for each zinc product (tons).

(3) Annual facility production quantity for each zinc product

(tons).

(4) Number of Waelz kilns at each facility used for zinc production.

(5) Number of electrothermic furnaces at each facility used for zinc production.

(b) If a CEMS is not used to measure CO2emissions, then you must report the information listed in this paragraph (b):

(1) Kiln identification number and annual process CO2 emissions from each individual Waelz kiln or electrothermic furnace

(metric tons).

(2) Annual zinc product production capacity (tons).

(3) Annual production quantity for each zinc product (tons).

(4) Number of Waelz kilns at each facility used for zinc production.

(5) Number of electrothermic furnaces at each facility used for zinc production.

(6) Annual mass of each carbon-containing input material charged to each kiln or furnace (including zinc bearing material, flux materials

(e.g., limestone, dolomite), carbon electrode, and other carbonaceous materials (e.g., coal, coke)) (tons).

(7) Carbon content of each carbon-containing input material charged to each kiln or furnace (including zinc bearing material, flux materials, and other carbonaceous materials) from the annual carbon analysis for each kiln or furnace (percent by weight, expressed as a decimal fraction).

(8) Whether carbon content of each carbon-containing input material charged to each kiln or furnace is based on reports from the supplier or through self measurement using applicable ASTM standard method.

(9) If carbon content of each carbon-containing input material charged to each kiln or furnace is based on self measurement, the ASTM

Standard Test Method used.

(10) Carbon content of the carbon electrode used in each furnace from the annual carbon analysis (percent by weight, expressed as a decimal fraction).

(11) Whether carbon content of the carbon electrode used in each furnace is based on reports from the supplier or through self measurement using applicable ASTM standard method.

(12) If carbon content of carbon electrode used in each furnace is based on self measurement, the ASTM standard method used.

(13) If you use the missing data procedures in Sec. 98.335(b), you must report how the monthly mass of carbon-containing materials with missing data was determined and the number of months the missing data procedures were used.

Sec. 98.337 Records that must be retained.

In addition to the records required by Sec. 98.3(g), you must retain the records specified in paragraphs (a) through (b) of this section for each zinc production facility.

(a) If a CEMS is used to measure emissions, then you must retain under this subpart the records required for the Tier 4 Calculation

Methodology in Sec. 98.37 and the information listed in this paragraph

(a):

(1) Monthly facility production quantity for each zinc product

(tons).

(2) Annual operating hours for all Waelz kilns and electrothermic furnaces used in zinc production.

(b) If a CEMS is not used to measure emissions, you must also retain the records specified in paragraphs (b)(1) through (b)(7) of this section.

(1) Records of all analyses and calculations conducted for data reported as listed in Sec. 98.336(b).

(2) Annual operating hours for Waelz kilns and electrothermic furnaces used in zinc production.

(3) Monthly production quantity for each zinc product (tons).

(4) Monthly mass of zinc bearing materials, flux materials (e.g., limestone, dolomite), and carbonaceous materials (e.g., coal, coke) charged to the kiln or furnace (tons).

(5) Sampling and analysis records for carbon content of zinc bearing materials, flux materials (e.g., limestone, dolomite), carbonaceous materials (e.g., coal, coke), charged to the kiln or furnace (percent by weight, expressed as a decimal fraction).

(6) Monthly mass of carbon electrode consumed in for each electrothermic furnace (tons).

(7) Sampling and analysis records for carbon content of electrode materials.

(8) You must keep records that include a detailed explanation of how company records of measurements are used to estimate the carbon input to each Waelz kiln or electrothermic furnace, as applicable to your facility, including documentation of any materials excluded from

Equation GG-

Page 56475

1 of this subpart that contribute less than 1 percent of the total carbon inputs to the process. You also must document the procedures used to ensure the accuracy of the measurements of materials fed, charged, or placed in an affected unit including, but not limited to, calibration of weighing equipment and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided.

Sec. 98.338 Definitions.

All terms used in this subpart have the same meaning given in the

Clean Air Act and subpart A of this part.

Subpart HH--Municipal Solid Waste Landfills

Sec. 98.340 Definition of the source category.

(a) This source category applies to municipal solid waste (MSW) landfills that accepted waste on or after January 1, 1980.

(b) This source category does not include hazardous waste landfills, construction and demolition landfills, or industrial landfills.

(c) This source category consists of the following sources at municipal solid waste (MSW) landfills: Landfills, landfill gas collection systems, and landfill gas destruction devices (including flares).

Sec. 98.341 Reporting threshold.

You must report GHG emissions under this subpart if your facility contains a MSW landfill and the facility meets the requirements of

Sec. 98.2(a)(1).

Sec. 98.342 GHGs to report.

(a) You must report CH4generation and CH4 emissions from landfills.

(b) You must report CH4destruction resulting from landfill gas collection and combustion systems.

Stationary Fuel Combustion Sources) the emissions of CO2,

CH4, and N2O from each stationary combustion unit following the requirements of subpart C.

Sec. 98.343 Calculating GHG emissions.

(a) For all landfills subject to the reporting requirements of this subpart, calculate annual modeled CH4generation according to the applicable requirements in paragraphs (a)(1) through (a)(3) of this section.

(1) Calculate annual modeled CH4generation using

Equation HH-1 of this section.

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Where:

GCH4= Modeled methane generation rate in reporting year

T (metric tons CH4).

X = Year in which waste was disposed.

S = Start year of calculation. Use the year 50 years prior to the year of the emissions estimate, or the opening year of the landfill, whichever is more recent.

T = Reporting year for which emissions are calculated.

Wx= Quantity of waste disposed in the landfill in year X from tipping fee receipts or other company records (metric tons, as received (wet weight)).

L0= CH4generation potential (metric tons

CH4/metric ton waste) = MCF x DOC x DOCFx F x 16/12.

MCF = Methane correction factor (fraction); default is 1.

DOC = Degradable organic carbon from Table HH-1 of this subpart or measurement data, if available [fraction (metric tons C/metric ton waste)].

DOCF= Fraction of DOC dissimilated (fraction); default is 0.5.

F = Fraction by volume of CH4in landfill gas from measurement data, if available (fraction); default is 0.5. k = Rate constant from Table HH-1 of this subpart or measurement data, if available (yr-1).

(2) For years when material-specific waste quantity data are available, apply Equation HH-1 of this section for each waste quantity type and sum the CH4generation rates for all waste types to calculate the total modeled CH4generation rate for the landfill. Use the appropriate parameter values for k, DOC, MCF,

DOCF, and F shown in Table HH-1 of this subpart. The annual quantity of each type of waste disposed must be calculated as the sum of the daily quantities of waste (of that type) disposed. You may use the bulk waste parameters for a portion of your waste materials when using the material-specific modeling approach for mixed waste streams that cannot be designated to a specific material type. For years when waste composition data are not available, use the bulk waste parameter values for k and L0in Table HH-1 of this subpart for the total quantity of waste disposed in those years.

(3) For years prior to reporting for which waste disposal quantities are not readily available, Wxshall be estimated using one of the applicable methods in paragraphs (a)(3)(i) through

(a)(3)(iii) of this section. You must determine which method is most applicable to the conditions and disposal history of your facility and use that method to estimate waste disposal quantities.

(i) Assume all prior year waste disposal quantities are the same as the waste quantity in the first reporting year.

(ii) Use the estimated population served by the landfill in each year, the values for national average per capita waste generation, and fraction of generated waste disposed of in solid waste disposal sites found in Table HH-2 of this subpart, and calculate the waste quantity landfilled using Equation HH-2 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.129

Where:

Wx= Quantity of waste placed in the landfill in year x

(metric tons, wet basis).

POPx= Population of served by the landfill in year x from city population, census data, or other estimates (capita).

WGR = Average per capita waste generation rate for year x from Table

HH-2 of this subpart (metric tons per capita per year, wet basis; tons/cap/yr).

%SWDS = Percent of waste generated subsequently managed in solid waste disposal sites (i.e., landfills) for year x from Table HH-2 of this subpart.

(iii) Use a constant average waste disposal quantity calculated using Equation HH-3 of this section for each year the landfill was in operation (i.e.,

Page 56476

from first accepting waste until the last year for which waste disposal data is unavailable, inclusive).

GRAPHIC

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Where:

WAR = Annual average waste acceptance rate (metric tons per year).

LFC = Landfill capacity or, for operating landfills, capacity of the landfill currently used from design drawings or engineering estimates (metric tons).

YrData = Year in which the landfill last received waste or, for operating landfills, the year prior to the first reporting year when waste disposal data is first available from company records, or best available data.

YrOpen = Year in which the landfill first received waste from company records or best available data. If no data are available for estimating YrOpen for a closed landfill, use 30 years as the default operating life of the landfill.

(b) For landfills with gas collection systems, calculate the quantity of CH4destroyed according to the requirements in paragraphs (b)(1) and (b)(2) of this section.

(1) If you continuously monitor the flow rate, CH4 concentration, temperature, pressure, and moisture content of the landfill gas that is collected and routed to a destruction device

(before any treatment equipment) using a monitoring meter specifically for CH4gas, as specified in Sec. 98.344, you must use this monitoring system and calculate the quantity of CH4 recovered for destruction using Equation HH-4 of this section. A fully integrated system that directly reports CH4content requires no other calculation than summing the results of all monitoring periods for a given year.

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Where:

R = Annual quantity of recovered CH4(metric tons

CH4).

N = Total number of measurement periods in a year. Use daily averaging periods for continuous monitoring system (N = 365). For weekly sampling, use N = 52. n = Index for measurement period.

(V)n= Daily average volumetric flow rate for day n

(acfm). If the flow rate meter automatically corrects for temperature and pressure, replace ``520 [deg]R/(T)nx

(P)n/1 atm'' with ``1''. If the CH4 concentration is determined on a dry basis and the flow rate meter automatically corrects for moisture/content, replace the term [1 -

(fH20)n] with 1.

(fH2O)n= Daily average moisture content of landfill gas, volumetric basis (cubic feet water per cubic feet landfill gas).

(C)n= Daily average CH4concentration of landfill gas for day n (volume %, dry basis). If the CH4 concentration is determined on a wet basis, replace the term [1 -

(fH20)n] with 1. 0.0423 = Density of CH4lb/cf at 520 [deg]R or 60 [deg]F and 1 atm.

(T)n= Temperature at which flow is measured for day n

([deg]R).

(P)n= Pressure at which flow is measured for day n

(atm). 1,440 = Conversion factor (min/day). 0.454/1,000 = Conversion factor (metric ton/lb).

(2) If you do not continuously monitor according to paragraph

(b)(1) of this section, you must determine the flow rate,

CH4concentration, temperature, pressure, and moisture content of the landfill gas that is collected and routed to a destruction device (before any treatment equipment) at least weekly according to the requirements in paragraphs (b)(2)(i) through

(b)(2)(iii) of this section and calculate the quantity of

CH4recovered for destruction using Equation HH-4 of this section.

(i) Continuously monitor gas flow rate and determine the cumulative volume of landfill gas each week and the cumulative volume of landfill gas each year that is collected and routed to a destruction device

(before any treatment equipment). Under this option, the gas flow meter is not required to automatically correct for temperature, pressure, or, if necessary, moisture content. If the gas flow meter is not equipped with automatic correction for temperature, pressure, or, if necessary, moisture content, you must determine these parameters as specified in paragraph (b)(2)(iii) of this section.

(ii) Determine the CH4concentration in the landfill gas that is collected and routed to a destruction device (before any treatment equipment) in a location near or representative of the location of the gas flow meter no less than weekly.

(iii) If the gas flow meter is not equipped with automatic correction for temperature, pressure, or, if necessary, moisture content:

(A) Determine the temperature, pressure in the landfill gas that is collected and routed to a destruction device (before any treatment equipment) in a location near or representative of the location of the gas flow meter no less than weekly.

(B) If the CH4concentration is determined on a dry basis, determine the moisture content in the landfill gas that is collected and routed to a destruction device (before any treatment equipment) in a location near or representative of the location of the gas flow meter no less than weekly

(c) Calculate CH4generation (adjusted for oxidation in cover materials) and actual CH4emissions (taking into account any CH4recovery, and oxidation in cover materials) according to the applicable methods in paragraphs (c)(1) through (c)(3) of this section.

(1) Calculate CH4generation, adjusted for oxidation, from the modeled CH4(GCH4 from Equation HH-1 of this section) using Equation HH-5 of this section.

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Where:

MG = Methane generation, adjusted for oxidation, from the landfill in the reporting year (metric tons CH4).

GCH4= Modeled methane generation rate in reporting year from Equation HH-1 of this section (metric tons CH4).

OX = Oxidation fraction. Use the default value of 0.1 (10%).

(2) For landfills that do not have landfill gas collection systems, the CH4emissions are equal to the CH4generation

(MG) calculated in Equation HH-5 of this section.

(3) For landfills with landfill gas collection systems, calculate

CH4emissions using the methodologies specified in paragraphs (c)(3)(i) and (c)(3)(ii) of this section.

Page 56477

(i) Calculate CH4emissions from the modeled

CH4generation and measured CH4recovery using

Equation HH-6 of this section.

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Where:

Emissions = Methane emissions from the landfill in the reporting year (metric tons CH4).

GCH4 = Modeled methane generation rate in reporting year from Equation HH-1 of this section or the quantity of recovered

CH4from Equation HH-4 of this section, whichever is greater (metric tons CH4).

R = Quantity of recovered CH4from Equation HH-4 of this section (metric tons).

OX = Oxidation fraction. Use the oxidation fraction default value of 0.1 (10%).

DE = Destruction efficiency (lesser of manufacturer's specified destruction efficiency and 0.99). If the gas is transported off-site for destruction, use DE = 1. fDest= Fraction of hours the destruction device was operating (annual operating hours/8760 hours per year). If the gas is destroyed in a back-up flare (or simlar device) or if the gas is transported off-site for destruction, use fDest= 1.

(ii) Calculate CH4generation and CH4 emissions using measured CH4recovery and estimated gas collection efficiency and Equations HH-7 and HH-8 of this section.

GRAPHIC

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GRAPHIC

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Where:

MG = Methane generation, adjusted for oxidation, from the landfill in the reporting year (metric tons CH4).

Emissions = Methane emissions from the landfill in the reporting year (metric tons CH4).

R = Quantity of recovered CH4from Equation HH-4 of this section (metric tons CH4).

CE = Collection efficiency estimated at landfill, taking into account system coverage, operation, and cover system materials from

Table HH-3 of this subpart. If area by soil cover type information is not available, use default value of 0.75 (CE4 in table HH-3 of this subpart) for all areas under active influence of the collection system. fRec= Fraction of hours the recovery system was operating (annual operating hours/8760 hours per year).

OX = Oxidation fraction. Use the oxidation fractions default value of 0.1 (10%).

DE = Destruction efficiency, (lesser of manufacturer's specified destruction efficiency and 0.99). If the gas is transported off-site for destruction, use DE = 1. fDest= Fraction of hours the destruction device was operating (device operating hours/8760 hours per year). If the gas is destroyed in a back-up flare (or similar device) or if the gas is transported off-site for destruction, use fDest= 1.

Sec. 98.344 Monitoring and QA/QC requirements.

(a) The quantity of waste landfilled must be determined using mass measurement equipment meeting the requirements for commercial weighing equipment as described in ``Specifications, Tolerances, and Other

Technical Requirements For Weighing and Measuring Devices'' NIST

Handbook 44 (2009)(incorporated by reference, see Sec. 98.7).

(b) For landfills with gas collection systems, install, operate, maintain, and calibrate a gas composition monitor capable of measuring the concentration of CH4 in the recovered landfill gas using one of the methods specified in paragraphs (b)(1) through (b)(6) of this section or as specified by the manufacturer. Gas composition monitors shall be calibrated prior to the first reporting year and recalibrated either annually or at the minimum frequency specified by the manufacturer, whichever is more frequent, or whenever the error in the midrange calibration check exceeds 10 percent.

(1) Method 18 at 40 CFR part 60, appendix A-6.

(2) ASTM D1945-03, Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see Sec. 98.7).

(3) ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference, see

Sec. 98.7).

(4) GPA Standard 2261-00, Analysis for Natural Gas and Similar

Gaseous Mixtures by Gas Chromatography.

(5) UOP539-97 Refinery Gas Analysis by Gas Chromatography

(incorporated by reference, see Sec. 98.7).

(6) As an alternative to the gas chromatography methods provided in paragraphs (b)(1) through (b)(5) of this section, you may use total gaseous organic concentration analyzers and calculate the methane concentration following the requirements in paragraphs (b)(6)(i) through (b)(6)(iii) of this section.

(i) Use Method 25A or 25B at 40 CFR part 60, appendix A-7 to determine total gaseous organic concentration. You must calibrate the instrument with methane and determine the total gaseous organic concentration as carbon (or as methane; K=1 in Equation 25A-1 of Method 25A at 40 CFR part 60, appendix A-7).

(ii) Determine a non-methane organic carbon correction factor no less frequently than once a reporting year following the requirements in paragraphs (b)(6)(ii)(A) through (b)(6)(ii)(C) of this section.

(A) Take a minimum of three grab samples of the landfill gas that is collected and routed to a destruction device (before any treatment equipment) with a minimum of 20 minutes between samples and determine the methane composition of the landfill gas using one of the methods specificed in paragraphs (b)(1) through (b)(5) of this section.

(B) As soon as practical after each grab sample is collected and prior to the collection of a subsequent grab sample, determine the total gaseous organic concentration of the landfilll gas that is

Page 56478

collected and routed to a destruction device (before any treatment equipment) using either Method 25A or 25B at 40 CFR part 60, appendix

A-7 as specified in paragaph (b)(6)(i) of this section.

(C) Determine the arithmetic average methane concentration and the arithmetic average total gaseous organic concentration of the samples analyzed according to paragraphs (b)(6)(ii)(A) and (b)(6)(ii)(B) of this section, respectively, and calculate the non-methane organic carbon correction factor as the ratio of the average methane concentration to the average total gaseous organic concentration. If the ratio exceeds 1, use 1 for the non-methane organic carbon correction factor.

(iii) Calculate the methane concentration as specified in Equation

HH-9 of this section.

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Where:

CCH4= Methane concentration in the landfill gas (volume %). fNMOC= Non-methane organic carbon correction factor from the most recent determination of the non-methane organic carbon correction factor as specified in paragraph (b)(6)(ii) of this section (unitless).

CTGOC= Total gaseous organic carbon concentration measured using Method 25A or 25B at 40 CFR part 60, appendix A-7 during routine monitoring of the landfill gas (volume %).

(c) For landfills with gas collection systems, install, operate, maintain, and calibrate a gas flow meter capable of measuring the volumetric flow rate of the recovered landfill gas using one of the methods specified in paragraphs (c)(1) through (c)(8) of this section or as specified by the manufacturer. Each gas flow meter shall be calibrated prior to the first year of reporting and recalibrated either biennially (every 2 years) or at the minimum frequency specified by the manufacturer. Except as provided in Sec. 98.343(b)(2)(i), each gas flow meter must be capable of correcting for the temperature and pressure and, if the gas composition monitor determines CH4 concentration on a dry basis, moisture content.

(1) ASME MFC-3M-2004, Measurement of Fluid Flow in Pipes Using

Orifice, Nozzle, and Venturi (incorporated by reference, see Sec. 98.7).

(2) ASME MFC-4M-1986 (Reaffirmed 1997), Measurement of Gas Flow by

Turbine Meters (incorporated by reference, see Sec. 98.7).

(3) ASME MFC-6M-1998, Measurement of Fluid Flow in Pipes Using

Vortex Flowmeters (incorporated by reference, see Sec. 98.7).

(4) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow by

Means of Critical Flow Venturi Nozzles (incorporated by reference, see

Sec. 98.7).

(5) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of

Coriolis Mass Flowmeters (incorporated by reference, see Sec. 98.7).

The mass flow must be corrected to volumetric flow based on the measured temperature, pressure, and gas composition.

(6) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore

Precision Orifice Meters (incorporated by reference, see Sec. 98.7).

(7) ASME MFC-18M-2001 Measurement of Fluid Flow using Variable Area

Meters (incorporated by reference, see Sec. 98.7).

(8) Method 2A or 2D at 40 CFR part 60, appendix A-1.

(d) All temperature and pressure monitors must be calibrated using the procedures and frequencies specified by the manufacturer.

(e) The owner or operator shall document the procedures used to ensure the accuracy of the estimates of disposal quantities and, if applicable, gas flow rate, gas composition, temperature, and pressure measurements. These procedures include, but are not limited to, calibration of weighing equipment, fuel flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices shall also be recorded, and the technical basis for these estimates shall be provided.

Sec. 98.345 Procedures for estimating missing data.

A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality- assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the requirements in paragraphs (a) through (c) of this section.

(a) For each missing value of the CH4content, the substitute data value shall be the arithmetic average of the quality- assured values of that parameter immediately preceding and immediately following the missing data incident. If the ``after'' value is not obtained by the end of the reporting year, you may use the ``before'' value for the missing data substitution. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality- assured value obtained after the missing data period.

(b) For missing gas flow rates, the substitute data value shall be the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If the ``after'' value is not obtained by the end of the reporting year, you may use the ``before'' value for the missing data substitution. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period.

(c) For missing daily waste disposal quantity data for disposal in reporting years, the substitute value shall be the average daily waste disposal quantity for that day of the week as measured on the week before and week after the missing daily data.

Sec. 98.346 Data reporting requirements.

In addition to the information required by Sec. 98.3(c), each annual report must contain the following information for each landfill.

(a) A classification of the landfill as ``open'' (actively received waste in the reporting year) or ``closed'' (no longer receiving waste), the year in which the landfill first started accepting waste for disposal, the last year the landfill accepted waste (for open landfills, enter the estimated year of landfill closure), the capacity

(in metric tons) of the landfill, an indication of whether leachate recirculation is used, and the waste disposal quantity for each year of landfilling.

(b) Method for estimating waste disposal quantity, and reason for its selection.

(1) Municipal.

(2) Biosolids or biological sludges.

(3) Other, or more refined categories, such as those for which k rates are available in Table HH-1 of this subpart, and the method or basis for estimating waste composition.

(d) For each waste type used to calculate CH4generation using Equation HH-1 of this subpart, you must report:

(1) Degradable organic carbon (DOC) value used in the calculations.

(2) Decay rate (k) value used in the calculations.

(e) Fraction of CH4in landfill gas (F) and an indication of whether the fraction of CH4was determined based on measured values or the default value.

(f) The surface area of the landfill containing waste (in square meters), the cover types applicable to the landfill, the surface area and oxidation fraction

Page 56479

for each cover type used to calculate the average oxidation fraction, and the average oxidation fraction used in the calculations.

(g) The modeled annual methane generation rate for the reporting year (metric tons CH4) calculated using Equation HH-1 of this subpart.

(h) For landfills without gas collection systems, the annual methane emissions (i.e., the methane generation, adjusted for oxidation, calculated using Equation HH-5 of this subpart), reported in metric tons CH4.

(i) For landfills with gas collection systems, you must report:

(1) Total volumetric flow of landfill gas collected for destruction

(cubic feet at 520 [deg]R or 60 [deg]F and 1 atm).

(2) CH4concentration of landfill gas collected for destruction (percent by volume).

(3) Monthly average temperature for each month at which flow is measured for landfill gas collected for destruction, or statement that temperature is incorporated into internal calculations run by the monitoring equipment.

(4) Monthly average pressure for each month at which flow is measured for landfill gas collected for destruction, or statement that temperature is incorporated into internal calculations run by the monitoring equipment.

(5) An indication of whether destruction occurs at the landfill facility or off-site. If destruction occurs at the landfill facility, also report an indication of whether a back-up destruction device is present at the landfill, the annual operating hours for the primary destruction device, the annual operating hours for the back-up destruction device (if present), and the destruction efficiency used

(percent).

(6) Annual quantity of recovered CH4(metric tons

CH4) calculated using Equation HH-4 of this subpart.

(7) A description of the gas collection system (manufacture, capacity, number of wells, etc.), the surface area (square meters) and estimated waste depth (meters) for each area specified in Table HH-3 of this subpart, the estimated gas collection system efficiency for landfills with this gas collection system, and the annual operating hours of the gas collection system.

(8) Methane generation corrected for oxidation calculated using

Equation HH-5 of this subpart, reported in metric tons CH4.

(9) Methane generation (GCH4) value used as an input to

Equation HH-6 of this subpart. Specify whether the value is modeled

(GCH4from HH-1 of this subpart) or measured (R from

Equation HH-4 of this subpart).

(10) Methane generation corrected for oxidation calculated using

Equation HH-7 of this subpart, reported in metric tons CH4.

(11) Methane emissions calculated using Equation HH-6 of this subpart, reported in metric tons CH4.

(12) Methane emissions calculated using Equation HH-8 of this subpart, reported in metric tons CH4.

Sec. 98.347 Records that must be retained.

In addition to the information required by Sec. 98.3(g), you must retain the calibration records for all monitoring equipment, including the method or manufacturer's specification used for calibration.

Sec. 98.348 Definitions.

All terms used in this subpart have the same meaning given in the

Clean Air Act and subpart A of this part.

Table HH-1 to Subpart HH of Part 98--Emissions Factors, Oxidation

Factors and Methods

Factor

Default value

Units

Waste model--bulk waste option

k (precipitation 40 inches/year 0.057............. yr-\1\ or for landfill areas with leachate recirculation).

L0 (Equivalent to DOC = 0.2028 0.067............. metric tons CH4/ when MCF = 1, DOCF = 0.5, and F

metric ton waste

= 0.5).

Waste model--All MSW landfills

MCF............................. 1................. ..................

DOCF............................ 0.5............... ..................

F............................... 0.5............... ..................

Waste model--MSW using waste composition option

DOC (food waste)................ 0.15.............. Weight fraction, wet basis

DOC (garden).................... 0.2............... Weight fraction, wet basis

DOC (paper)..................... 0.4............... Weight fraction, wet basis

DOC (wood and straw)............ 0.43.............. Weight fraction, wet basis

DOC (textiles).................. 0.24.............. Weight fraction, wet basis

DOC (diapers)................... 0.24.............. Weight fraction, wet basis

DOC (sewage sludge)............. 0.05.............. Weight fraction, wet basis

DOC (bulk waste)................ 0.20.............. Weight fraction, wet basis k (food waste).................. 0.06 to 0.185\a\.. yr-\1\ k (garden)...................... 0.05 to 0.10 \a\.. yr-\1\ k (paper)....................... 0.04 to 0.06 \a\.. yr-\1\ k (wood and straw).............. 0.02 to 0.03 \a\.. yr-\1\ k (textiles).................... 0.04 to 0.06 \a\.. yr-\1\ k (diapers)..................... 0.05 to 0.10 \a\.. yr-\1\ k (sewage sludge)............... 0.06 to 0.185 \a\. yr-\1\

Calculating methane generation and emissions

OX.............................. 0.1............... ..................

Page 56480

DE.............................. 0.99.............. ..................

\a\ Use the lesser value when the potential evapotranspiration rate exceeds the mean annual precipitation rate and leachate recirculation is not used. Use the greater value when the potential evapotranspiration rate does not exceed the mean annual precipitation rate or when leachate recirculation is used.

Table HH-2 to Subpart HH of Part 98--U.S. Per Capita Waste Disposal

Rates

Waste per

Year

capita ton/

% to SWDS cap/yr

1950....................................

0.63

100 1951....................................

0.63

100 1952....................................

0.63

100 1953....................................

0.63

100 1954....................................

0.63

100 1955....................................

0.63

100 1956....................................

0.63

100 1957....................................

0.63

100 1958....................................

0.63

100 1959....................................

0.63

100 1960....................................

0.63

100 1961....................................

0.64

100 1962....................................

0.64

100 1963....................................

0.65

100 1964....................................

0.65

100 1965....................................

0.66

100 1966....................................

0.66

100 1967....................................

0.67

100 1968....................................

0.68

100 1969....................................

0.68

100 1970....................................

0.69

100 1971....................................

0.69

100 1972....................................

0.70

100 1973....................................

0.71

100 1974....................................

0.71

100 1975....................................

0.72

100 1976....................................

0.73

100 1977....................................

0.73

100 1978....................................

0.74

100 1979....................................

0.75

100 1980....................................

0.75

100 1981....................................

0.76

100 1982....................................

0.77

100 1983....................................

0.77

100 1984....................................

0.78

100 1985....................................

0.79

100 1986....................................

0.79

100 1987....................................

0.80

100 1988....................................

0.80

100 1989....................................

0.85

84 1990....................................

0.84

77 1991....................................

0.78

76 1992....................................

0.76

72 1993....................................

0.78

71 1994....................................

0.77

67 1995....................................

0.72

63 1996....................................

0.71

62 1997....................................

0.72

61 1998....................................

0.78

61 1999....................................

0.78

60 2000....................................

0.84

61 2001....................................

0.95

63 2002....................................

1.06

66 2003....................................

1.06

65 2004....................................

1.06

64 2005....................................

1.06

64 2006....................................

1.06

Page 56481

Table HH-3 to Subpart HH of Part 98--Landfill Gas Collection

Efficiencies

Landfill Gas Collection

Description

Efficiency

A1: Area with no waste in-place........ Not applicable; do not use this area in the calculation.

A2: Area without active gas collection, CE2: 0%. regardless of cover type.

H2: Average depth of waste in area A2..

A3: Area with daily soil cover and

CE3: 60%. active gas collection.

H3: Average depth of waste in area A3..

A4: Area with an intermediate soil

CE4: 75%. cover and active gas collection.

H4: Average depth of waste in area A4..

A5: Area with a final soil and

CE5: 95%. geomembrane cover system and active gas collection.

H5: Average depth of waste in area A5..

Area weighted average collection

CEave1 = (A2*CE2 + A3*CE3 + efficiency for landfills.

A4*CE4 + A5*CE5)/

(A2+A3+A4+A5).

Subpart II--[Reserved]

Subpart JJ--Manure Management

Sec. 98.360 Definition of the source category.

(a) This source category consists of livestock facilities with manure management systems that emit 25,000 metric tons CO2e or more per year.

(1) Table JJ-1 presents the minimum average annual animal population by animal group that is estimated to emit 25,000 metric tons

CO2e or more per year. Facilities with an average annual animal population, as described in Sec. 98.363(a)(1) and (2), below those listed in Table JJ-1 do not need to report under this rule. A facility with an annual animal population that exceeds those listed in

Table JJ-1 should conduct a more thorough analysis to determine applicability.

(2) (i) If a facility has more than one animal group present (e.g., swine and poultry), the facility must determine if they are required to report by calculating the combined animal group factor (CAGF) using equation JJ-1:

GRAPHIC

TIFF OMITTED TR30OC09.137

Where:

CAGF = Combined Animal Group Factor

AAAPAG,Facility= Average annual animal population at the facility, by animal group

APTL AG= Animal population threshold level, as specified in Table JJ-1 of this section

(ii) If the calculated CAGF for a facility is less than 1, the facility is not required to report under this rule. If the CAGF is equal to or greater than 1, the facility must use more detailed applicability tables and tools to determine if they are required to report under this rule.

(b) A manure management system (MMS) is a system that stabilizes and/or stores livestock manure, litter, or manure wastewater in one or more of the following system components: Uncovered anaerobic lagoons, liquid/slurry systems with and without crust covers (including but not limited to ponds and tanks), storage pits, digesters, solid manure storage, dry lots (including feedlots), high-rise houses for poultry production (poultry without litter), poultry production with litter, deep bedding systems for cattle and swine, manure composting, and aerobic treatment.

(c) This source category does not include system components at a livestock facility that are unrelated to the stabilization and/or storage of manure such as daily spread or pasture/range/paddock systems or land application activities or any method of manure utilization that is not listed in Sec. 98.360(b).

(d) This source category does not include manure management activities located off site from a livestock facility or off-site manure composting operations.

Sec. 98.361 Reporting threshold.

Livestock facilities must report GHG emissions under this subpart if the facility meets the reporting threshold as defined in 98.360(a) above, contains a manure management system as defined in 98.360(b) above, and meets the requirements of Sec. 98.2(a)(1).

Sec. 98.362 GHGs to report.

(a) Livestock facilities must report annual aggregate

CH4and N2O emissions for the following MMS components at the facility:

(1) Uncovered anaerobic lagoons.

(2) Liquid/slurry systems (with and without crust covers, and including but not limited to ponds and tanks).

(3) Storage pits.

(4) Digesters, including covered anaerobic lagoons.

(5) Solid manure storage.

(6) Dry lots, including feedlots.

(7) High-rise houses for poultry production (poultry without litter)

(8) Poultry production with litter.

(9) Deep bedding systems for cattle and swine.

(10) Manure composting.

(11) Aerobic treatment.

(b) A livestock facility that is subject to this rule only because of emissions from manure management system components is not required to report emissions from subparts C through PP (other than subpart JJ) of this part.

(c) A livestock facility that is subject to this part because of emissions from source categories described in subparts C through PP of this part is not required to report emissions under subpart JJ of this part unless emissions from manure management systems are 25,000 metric tons CO2e per year or more.

Sec. 98.363 Calculating GHG emissions.

(a) For all manure management system components listed in 98.360(b) except digesters, estimate the annual CH4emissions and sum for all the components to obtain total emissions from the manure management system for all animal types using Equation JJ-1.

Page 56482

GRAPHIC

TIFF OMITTED TR30OC09.138

Where:

MMSC = Manure management systems component.

TVSAT= Total volatile solids excreted by animal type, calculated using Equation JJ-3 of this section (kg/day).

VSMMSC= Fraction of the total manure for each animal type that is managed in MMS component MMSC, assumed to be equivalent to the fraction of VS in each MMS component.

VSss= Volatile solids removal through solid separation; if solid separation occurs prior to the MMS component, use a default value from Table JJ-4 of this section; if no solid separation occurs, this value is set to 0.

(B0)AT= Maximum CH4-producing capacity for each animal type, as specified in Table JJ-2 of this section (m\3\ CH4/kg VS).

MCFMMSC= CH4conversion factor for the MMS component, as specified in Table JJ-5 of this section (decimal).

GRAPHIC

TIFF OMITTED TR30OC09.139

Where:

TVSAT= Daily total volatile solids excreted per animal type (kg/day).

PopulationAT= Average annual animal population contributing manure to the manure management system by animal type

(head) (see description in Sec. 98.363(a)(i) and (ii) below).

TAMAT= Typical animal mass for each animal type, using either default values in Table JJ-2 of this section or farm-specific data (kg/head).

VSAT= Volatile solids excretion rate for each animal type, using default values in Table JJ-2 or JJ-3 of this section (kg

VS/day/1000 kg animal mass).

(1) Average annual animal populations for static populations (e.g., dairy cows, breeding swine, layers) must be estimated by performing an animal inventory or review of facility records once each reporting year.

(2) Average annual animal populations for growing populations (meat animals such as beef and veal cattle, market swine, broilers, and turkeys) must be estimated each year using the average number of days each animal is kept at the facility and the number of animals produced annually, and an equation similar or equal to Equation JJ-4 below, adapted from Equation 10.1 in 2006 IPCC Guidelines for National

Greenhouse Gas Inventories, Volume 4, Chapter 10.

GRAPHIC

TIFF OMITTED TR30OC09.140

Where:

PopulationAT= Average annual animal population (by animal type).

Days onsiteAT= Average number of days the animal is kept at the facility, by animal type.

NAPAAT= Number of animals produced annually, by animal type.

(b) For each digester, calculate the total amount of CH4 emissions, and then sum the emissions from all digesters, as shown in

Equation JJ-5 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.141

Where:

CH4EmissionsAD= CH4emissions from anaerobic digestion (metric tons/yr).

AD = Number of anaerobic digesters at the manure management facility.

CH4C = CH4flow to digester combustion device, calculated using Equation JJ-6 of this section (metric tons

CH4/yr).

CH4D = CH4destruction at digesters, calculated using Equation JJ-11 of this section (metric tons

CH4/yr) .

CH4L = Leakage at digesters calculated using Equation JJ- 12 of this section (metric tons CH4/yr).

(1) For each digester, calculate the annual CH4flow to the combustion device (CH4C) using Equation JJ-6 of this section. A fully integrated system that directly reports the quantity of CH4flow to the digester combustion device requires only summing the results of all monitoring periods for a given year to obtain CH4C.

GRAPHIC

TIFF OMITTED TR30OC09.142

Where:

CH4C = CH4flow to digester combustion device

(metric tons CH4/yr).

V = Average annual volumetric flow rate, calculated in Equation JJ-7 of this subsection (cubic feet CH4/yr).

C = Average annual CH4concentration of digester gas, calculated in Equation JJ-8 of this section (%, wet basis). 0.0423 = Density of CH4lb/scf (at 520 [deg]R or 60

deg

F and 1 atm).

Page 56483

T = Average annual temperature at which flow is measured, calculated in Equation JJ-9 of this section ([deg]R).

P = Average annual pressure at which flow is measured, calculated in

Equation JJ-10 of this section (atm).

(2) For each digester, calculate the average annual volumetric flow rate, CH4concentration of digester gas, temperature, and pressure at which flow are measured using Equations JJ-7 through JJ-10 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.143

Where:

V = Average annual volumetric flow rate (cubic feet CH4/ yr).

OD = Operating days, number of days per year that that the digester was operating (days/yr).

Vn= Daily average volumetric flow rate for day n, as determined from daily monitoring as specified in Sec. 98.364

(acfm).

GRAPHIC

TIFF OMITTED TR30OC09.144

Where:

C = Average annual CH4concentration of digester gas (%, wet basis).

OD = Operating days, number of days per year that the digester was operating (days/yr).

Cn= Average daily CH4concentration of digester gas for day n, as determined from daily monitoring as specified in Sec. 98.364 (%, wet basis).

GRAPHIC

TIFF OMITTED TR30OC09.145

Where:

T = Average annual temperature at which flow is measured ([deg]R).

OD = Operating days, number of days per year that the digester was operating (days/yr).

Tn= Temperature at which flow is measured for day n([deg]R).

GRAPHIC

TIFF OMITTED TR30OC09.146

Where:

P = Average annual pressure at which flow is measured (atm).

OD = Operating days, number of days per year that the digester was operating (days/yr).

Pn= Pressure at which flow is measured for day n (atm).

(3) For each digester, calculate the CH4destruction at the digester combustion device using Equation JJ-11 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.147

Where:

CH4D = CH4destruction at digester combustion device (metric tons/yr).

CH4C = Annual quantity of CH4flow to digester combustion device, as calculated in Equation JJ-6 of this section

(metric tons CH4).

DE = CH4destruction efficiency from flaring or burning in engine (lesser of manufacturer's specified destruction efficiency and 0.99). If the gas is transported off-site for destruction, use

DE = 1.

OH = Number of hours combustion device is functioning in reporting year.

Hours = Hours in reporting year.

(4) For each digester, calculate the CH4leakage using

Equation JJ-12 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.148

Where:

CH4L = Leakage at digesters (metric tons/yr).

CH4C = Annual quantity of CH4flow to digester combustion device, as calculated in Equation JJ-6 of this section

(metric tons CH4).

CE = CH4collection efficiency of anaerobic digester, as specified in Table JJ-6 of this section (decimal).

(c) For each MMS component, estimate the annual N2O emissions and sum for all MMS components to obtain total emissions from the manure management system for all animal types using Equation JJ-13 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.149

Where:

Nex AT= Daily total nitrogen excreted per animal type, calculated using Equation JJ-14 of this section (kg N/day).

Nex,MMSC= Fraction of the total manure for each animal type that is managed in MMS component MMSC, assumed to be equivalent to the fraction of Nexin each MMS component.

Nss= Nitrogen removal through solid separation; if solid separation occurs prior to the MMS component, use a default value from Table JJ-4 of this

Page 56484

section; if no solid separation occurs, this value is set to 0.

EFMMSC= Emission factor for MMS component, as specified in Table JJ-7 of this section (kg N2O-N/kg N).

GRAPHIC

TIFF OMITTED TR30OC09.150

Where:

Nex AT= Total nitrogen excreted per animal type (kg/ day).

PopulationAT= Average annual animal population contributing manure to the manure management system by animal type

(head) (see description in Sec. 98.363(a)(i) and (ii)).

TAMAT= Typical animal mass by animal type, using either default values in Table JJ-2 of this section or farm-specific data

(kg/head).

NAT= Nitrogen excretion rate by animal type, using default values in Tables JJ-2 or JJ-3 of this section (kg N/day/1000 kg animal mass).

(d) Estimate the annual total facility emissions using Equation JJ- 15 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.151

Where:

CH4emissionsMMS= From Equation JJ-2 of this section.

CH4emissionsAD= From Equation JJ-5 of this section. 21 = Global Warming Potential of CH4.

Direct N2O emissions = From Equation JJ-13 of this section. 310 = Global Warming Potential of N2O.

Sec. 98.364 Monitoring and QA/QC requirements.

(a) Perform an annual animal inventory or review of facility records (for static populations) or population calculation (for growing populations) to determine the average annual animal population for each animal type (see description in Sec. 98.363(a)(1) and (2)).

(b) Perform an analysis on your operation to determine the fraction of total manure by weight for each animal type that is managed in each on-site manure management system component. If your system changes from previous reporting periods, you must reevaluate the fraction of total manure managed in each system component.

(c) The CH4concentration of gas from digesters must be determined using ASTM D1946-90 (Reapproved 2006) Standard Practice for

Analysis of Reformed Gas by Gas Chromatography (incorporated by reference see Sec. 98.7). All gas composition monitors shall be calibrated prior to the first reporting year for biogas methane and carbon dioxide content using ASTM D1946-90 (Reapproved 2006) Standard

Practice for Analysis of Reformed Gas by Gas Chromatography

(incorporated by reference see Sec. 98.7)and recalibrated either annually or at the minimum frequency specified by the manufacturer, whichever is more frequent, or whenever the error in the midrange calibration check exceeds 10 percent. All monitors shall be maintained as specified by the manufacturer.

(d) All temperature and pressure monitors must be calibrated using the procedures and frequencies specified by the manufacturer. All equipment (temperature and pressure monitors) shall be maintained as specified by the manufacturer.

(e) For digesters with gas collection systems, install, operate, maintain, and calibrate a gas flow meter capable of measuring the volumetric flow rate to provide data for the GHG emissions calculations, using the applicable methods specified in paragraphs

(e)(1) through (e)(6) of this section or as specified by the manufacturer.

(1) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using

Orifice, Nozzle, and Venturi (incorporated by reference, see Sec. 98.7).

(2) ASME MFC-4M-1986 (Reaffirmed 1997) Measurement of Gas Flow by

Turbine Meters (incorporated by reference, see Sec. 98.7).

(3) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using

Vortex Flowmeters (incorporated by reference, see Sec. 98.7).

(4) ASME MFC-7M-1987 (Reaffirmed 1992) Measurement of Gas Flow by

Means of Critical Flow Venturi Nozzles (incorporated by reference, see

Sec. 98.7).

(5) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore

Precision Orifice Meters (incorporated by reference, see Sec. 98.7).

(6) ASME MFC-18M-2001 Measurement of Fluid Flow using Variable Area

Meters (incorporated by reference, see Sec. 98.7).

(f) If applicable, the owner or operator shall document the procedures used to ensure the accuracy of gas flow rate, gas composition, temperature, and pressure measurements. These procedures include, but are not limited to, calibration of fuel flow meters and other measurement devices. The estimated accuracy of measurements made with these devices shall also be recorded, and the technical basis for these estimates shall be provided.

(g) Each gas flow meter shall be calibrated prior to the first reporting year and recalibrated either annually or at the minimum frequency specified by the manufacturer, whichever is more frequent.

Each gas flow meter must have a rated accuracy of 5 percent or lower and be capable of correcting for the temperature and pressure and, if the gas composition monitor determines CH4 concentration on a dry basis, moisture content.

Sec. 98.365 Procedures for estimating missing data.

(a) A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality- assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the requirements in paragraph (b) of this section.

(b) For missing gas flow rates or CH4content data, the substitute data value shall be the arithmetic average of the quality- assured values of that parameter immediately preceding and immediately following the missing data incident. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period.

Sec. 98.366 Data reporting requirements.

(a) In addition to the information required by Sec. 98.3(c), each annual report must contain the following information:

Page 56485

(1) List of manure management system components at the facility.

(2) Fraction of manure from each animal type that is handled in each manure management system component.

(3) Average annual animal population (for each animal type) for static populations or the results of Equation JJ-4 for growing populations.

(4) Average number of days that growing animals are kept at the facility (for each animal type).

(5) The number of animals produced annually for growing populations

(for each animal type).

(6) Typical animal mass (for each animal type).

(7) Total facility emissions (results of Equation JJ-15).

(8) CH4emissions from manure management system components listed in Sec. 98.360(b), except digesters (results of

Equation JJ-2).

(9) VS value used (for each animal type).

(10) B0value used (for each animal type).

(11) Methane conversion factor used for each MMS component.

(12) Average ambient temperature used to select each methane conversion factor.

(13) N2O emissions (results of Equation JJ-13).

(14) N value used for each animal type.

(15) N2O emission factor selected for each MMS component.

(b) Facilities with anaerobic digesters must also report:

(1) CH4emissions from anaerobic digesters (results of

Equation JJ-5).

(2) CH4flow to the digester combustion device for each digester (results of Equation JJ-6, or value from fully integrated monitoring system as described in 98.363(b)).

(3) CH4destruction for each digester (results of

Equation JJ-11).

(4) CH4leakage for each digester (results of Equation

JJ-12).

(5) Total annual volumetric biogas flow for each digester (results of Equation JJ-7).

(6) Average annual CH4concentration for each digester

(results of Equation JJ-8).

(7) Average annual temperature at which gas flow is measured for each digester (results of Equation JJ-9).

(8) Average annual gas flow pressure at which gas flow is measured for each digester (results of Equation JJ-10).

(9) Destruction efficiency used for each digester.

(10) Number of days per year that each digester was operating.

(11) Collection efficiency used for each digester.

Sec. 98.367 Records that must be retained.

Sec. 98.368 Definitions.

All terms used in this subpart have the same meaning given in the

Clean Air Act and subpart A of this part.

Table JJ-1 to Subpart JJ of Part 98--Animal Population Threshold Level

Below Which Facilities Are Not Required To Report Emissions Under

Subpart JJ 1,2

Average annual animal

Animal group

population

(Head) \3\

Beef....................................................

29,300

Dairy...................................................

3,200

Swine...................................................

34,100

Poultry:

Layers..............................................

723,600

Broilers............................................

38,160,000

Turkeys.............................................

7,710,000

\1\ The threshold head populations in this table were calculated using the most conservative assumptions (high VS and N values, maximum ambient temperatures, and the application of an uncertainty factor) to ensure that facilities at or near the 25,000 metric ton CO2e threshold level were not excluded from reporting.

\2\ For facilities with more than one animal group present refer to Sec. 98.360 (2) to estimate the combined animal group factor (CAGF), which is used to determine if a facility may be required to report.

\3\ For all animal groups except dairy, the average annual animal population represents the total number of animals present at the facility. For dairy facilities, the average annual animal population represents the number of mature dairy cows present at the facility

(note that heifers and calves were included in the emission estimates for dairy facilities using the assumption that the average annual animal population of heifers and calves at dairy facilities are equal to 30 percent of the mature dairy cow average annual animal population, therefore the average annual population for dairy facilities should not include heifers and calves, only dairy cows).

Table JJ-2 to Subpart JJ of Part 98--Waste Characteristics Data

Maximum

Volatile solids

methane

Typical animal excretion rate (kg

Nitrogen excretion

generation

Animal type

mass (kg)

VS/day/1000 kg animal rate (kg N/day/1000 potential, Bo mass)

kg animal mass)

(m\3\ CH4/kg

VS added)

Dairy Cows........................

604 See Table JJ-3....... See Table JJ-3.......

0.24

Dairy Heifers.....................

476 See Table JJ-3....... See Table JJ-3.......

0.17

Dairy Calves......................

118 6.41................. 0.30.................

0.17

Feedlot Steers....................

420 See Table JJ-3....... See Table JJ-3.......

0.33

Feedlot heifers...................

420 See Table JJ-3....... See Table JJ-3.......

0.33

Market Swine 180 lbs.............

91 5.40................. 0.42.................

0.48

Breeding Swine....................

198 2.60................. 0.24.................

0.48

Page 56486

Feedlot Sheep.....................

25 9.20................. 0.42.................

0.36

Goats.............................

64 9.50................. 0.45.................

0.17

Horses............................

450 10.00................ 0.30.................

0.33

Hens >/= 1 yr.....................

1.8 10.09................ 0.83.................

0.39

Pullets...........................

1.8 10.09................ 0.62.................

0.39

Other Chickens....................

1.8 10.80................ 0.83.................

0.39

Broilers..........................

0.9 15.00................ 1.10.................

0.36

Turkeys...........................

6.8 9.70................. 0.74.................

0.36

Table JJ-3 to Subpart JJ of Part 98--State-Specific Volatile Solids (VS) and Nitrogen (N) Excretion Rates for Cattle

Volatile solids excretion rate (kg VS/day/ Nitrogen excretion rate (kg VS/day/1000 kg 1000 kg animal mass)

animal mass)

State

---------------------------------------------------------------------------------------

Dairy

Feedlot

Dairy

Feedlot

Feedlot cows

heifers

steer

heifers

cows

heifers

steer

heifers

Alabama.........................................................

8.40

8.35

4.27

4.74

0.50

0.46

0.36

0.38

Alaska..........................................................

7.30

8.35

4.15

4.58

0.45

0.46

0.35

0.37

Arizona.........................................................

10.37

8.35

3.91

4.27

0.58

0.46

0.33

0.34

Arkansas........................................................

7.59

8.35

3.98

4.35

0.46

0.33

0.35

California......................................................

10.02

8.35

3.96

4.33

0.56

0.46

0.33

0.34

Colorado........................................................

10.25

8.35

3.97

4.34

0.58

0.46

0.33

0.35

Connecticut.....................................................

9.22

8.35

4.41

4.93

0.53

0.46

0.37

0.40

Delaware........................................................

8.63

8.35

4.19

4.64

0.51

0.46

0.35

0.37

Florida.........................................................

8.90

8.35

4.15

4.58

0.52

0.46

0.35

0.37

Georgia.........................................................

9.07

8.35

4.18

4.63

0.53

0.46

0.35

0.37

Hawaii..........................................................

7.00

8.35

4.15

4.58

0.44

0.46

0.35

0.37

Idaho...........................................................

10.11

8.35

4.03

4.42

0.57

0.46

0.34

0.35

Illinois........................................................

9.07

8.35

4.15

4.59

0.52

0.46

0.35

0.37

Indiana.........................................................

9.38

8.35

3.98

4.35

0.54

0.46

0.33

0.35

Iowa............................................................

9.46

8.35

3.93

4.28

0.54

0.46

0.33

0.34

Kansas..........................................................

9.63

8.35

3.97

4.35

0.55

0.46

0.33

0.35

Kentucky........................................................

7.89

8.35

4.20

4.65

0.48

0.46

0.35

0.37

Louisiana.......................................................

7.39

8.35

4.07

4.48

0.45

0.46

0.34

0.36

Maine...........................................................

8.99

8.35

4.07

4.47

0.52

0.46

0.34

0.36

Maryland........................................................

9.02

8.35

4.05

4.45

0.52

0.46

0.34

0.35

Massachusetts...................................................

8.63

8.35

4.15

4.58

0.51

0.46

0.35

0.37

Michigan........................................................

10.05

8.35

4.00

4.38

0.57

0.46

0.34

0.35

Minnesota.......................................................

9.17

8.35

3.89

4.24

0.53

0.46

0.33

0.34

Mississippi.....................................................

8.19

8.35

4.14

4.57

0.49

0.46

0.35

0.37

Missouri........................................................

8.02

8.35

4.08

4.49

0.48

0.46

0.34

0.36

Montana.........................................................

9.03

8.35

4.23

4.69

0.52

0.46

0.36

0.38

Nebraska........................................................

9.09

8.35

3.98

4.35

0.53

0.46

0.33

0.35

Nevada..........................................................

9.65

8.35

4.07

4.48

0.55

0.46

0.34

0.36

New Hampshire...................................................

9.44

8.35

3.94

4.30

0.54

0.46

0.33

0.34

New Jersey......................................................

8.51

8.35

3.98

4.36

0.50

0.46

0.33

0.35

New Mexico......................................................

10.34

8.35

3.88

4.22

0.58

0.46

0.32

0.33

New York........................................................

9.42

8.35

3.75

4.05

0.54

0.46

0.31

0.32

North Carolina..................................................

9.38

8.35

4.20

4.65

0.55

0.46

0.35

0.37

North Dakota....................................................

8.40

8.35

3.88

4.22

0.50

0.46

0.32

0.34

Ohio............................................................

9.01

8.35

3.96

4.33

0.52

0.46

0.33

0.34

Oklahoma........................................................

8.58

8.35

3.98

4.35

0.50

0.46

0.33

0.35

Oregon..........................................................

9.40

8.35

4.06

4.46

0.54

0.46

0.34

0.36

Pennsylvania....................................................

9.26

8.35

3.98

4.35

0.53

0.46

0.33

0.35

Rhode Island....................................................

8.94

8.35

4.36

4.87

0.52

0.46

0.37

0.39

South Carolina..................................................

9.05

8.35

4.15

4.58

0.53

0.46

0.35

0.37

South Dakota....................................................

9.45

8.35

4.01

4.39

0.54

0.46

0.34

0.35

Tennessee.......................................................

8.60

8.35

4.48

5.02

0.51

0.46

0.38

0.40

Texas...........................................................

9.51

8.35

3.95

4.32

0.54

0.46

0.33

0.34

Utah............................................................

9.70

8.35

3.88

4.22

0.55

0.46

0.32

0.34

Vermont.........................................................

9.03

8.35

4.10

4.52

0.52

0.46

0.34

0.36

Virginia........................................................

9.02

8.35

3.98

4.35

0.53

0.46

0.33

0.35

Washington......................................................

10.36

8.35

4.07

4.47

0.58

0.46

0.34

0.36

West Virginia...................................................

8.13

8.35

4.65

5.25

0.48

0.46

0.40

0.42

Wisconsin.......................................................

9.34

8.35

3.95

4.31

0.54

0.46

0.33

0.34

Page 56487

Wyoming.........................................................

9.29

8.35

4.17

4.61

0.53

0.46

0.35

0.37

Table JJ-4 to Subpart JJ of Part 98--Volatile Solids and Nitrogen

Removal through Solids Separation

Volatile solids

Nitrogen removal

Type of solids separation

removal (decimal)

(decimal)

Gravity.........................

0.60

Mechanical:

Stationary Screen...........

0.20

0.10

Vibrating Screen............

0.15

Screw Press.................

0.25

0.15

Centrifuge..................

0.50

0.25

Roller drum.................

0.25

0.15

Belt press/screen...........

0.50

0.30

BILLING CODE 6560-50-P

Page 56488

GRAPHIC

TIFF OMITTED TR30OC09.192

BILLING CODE 6560-50-C

Page 56489

Table JJ-6 to Subpart JJ of Part 98--Collection Efficiencies of

Anaerobic Digesters

Methane

Anaerobic digester type

Cover type

collection efficiency

Covered anaerobic lagoon (biogas

Bank to bank,

0.975 capture).

impermeable.

Modular, impermeable

0.70

Complete mix, fixed film, or plug Enclosed Vessel.....

0.99 flow digester.

Table JJ-7 to Subpart JJ of Part 98--Nitrous Oxide Emission Factors (kg

N2O-N/kg Kjdl N)

N2O

Manure management system component

emission factor

Uncovered anaerobic lagoon.................................

Liquid/Slurry (with crust cover)...........................

0.005

Liquid/Slurry (without crust cover)........................

Storage pits...............................................

0.002

Digesters..................................................

Solid manure storage.......................................

0.005

Dry lots (including feedlots)..............................

0.02

High-rise house for poultry (poultry without litter).......

0.001

Poultry production with litter.............................

0.001

Deep bedding for cattle and swine (active mix).............

0.07

Deep bedding for cattle and swine (no mix).................

0.01

Manure Composting (in vessel)..............................

0.006

Manure Composting (intensive)..............................

0.1

Manure Composting (passive)................................

0.01

Manure Composting (static).................................

0.006

Aerobic Treatment (forced aeration)........................

0.005

Aerobic Treatment (natural aeration).......................

0.01

Subpart KK--[Reserved]

Subpart LL--Suppliers of Coal-based Liquid Fuels

Sec. 98.380 Definition of the source category.

This source category consists of producers, importers, and exporters of products listed in Table MM-1 of subpart MM that are coal- based (coal-to-liquid products).

(a) A producer is the owner or operator of a coal-to-liquids facility. A coal-to-liquids facility is any facility engaged in converting coal into liquid products using a process involving conversion of coal into gas and then into liquids (e.g., Fischer-

Tropsch) or conversion of coal directly into liquids (i.e., direct liquefaction).

(b) An importer or exporter shall have the same meaning given in

Sec. 98.6.

Sec. 98.381 Reporting threshold.

Any supplier of coal-to-liquid products who meets the requirements of Sec. 98.2(a)(4) must report GHG emissions.

Sec. 98.382 GHGs to report.

You must report the CO2emissions that would result from the complete combustion or oxidation of fossil-fuel products (besides coal or crude oil) that you produce, use as feedstock, import, or export during the calendar year. Additionally, producers must report

CO2emissions that would result from the complete combustion or oxidation of any biomass co-processed with fossil fuel-based feedstocks.

Sec. 98.383 Calculating GHG emissions.

You must follow the calculation methodologies of Sec. 98.393 as if they applied to the appropriate coal-to-liquid product supplier (i.e., calculation methodologies for refiners apply to producers of coal-to- liquid products and calculation methodologies for importers and exporters of petroleum products apply to importers and exporters of coal-to-liquid products).

(a) In calculation methodologies in Sec. 98.393 for petroleum products or petroleum-based products, suppliers of coal-to-liquid products shall also include coal-to-liquid products.

(b) In calculation methodologies in Sec. 98.393 for non-crude feedstocks or non-crude petroleum feedstocks, producers of coal-to- liquid products shall also include coal-to-liquid products that enter the facility to be further processed or otherwise used on site.

(c) In calculation methodologies in Sec. 98.393 for petroleum feedstocks, suppliers of coal-to-liquid products shall also include coal and coal-to-liquid products that enter the facility to be further processed or otherwise used on site.

Sec. 98.384 Monitoring and QA/QC requirements.

You must follow the monitoring and QA/QC requirements in Sec. 98.394 as if they applied to the appropriate coal-to-liquid product supplier. Any monitoring and QA/QC requirement for petroleum products in Sec. 98.394 also applies to coal-to-liquid products.

Sec. 98.385 Procedures for estimating missing data.

You must follow the procedures for estimating missing data in Sec. 98.395 as if they applied to the appropriate coal-to-liquid product supplier. Any procedure for estimating missing data for petroleum products in Sec. 98.395 also applies to coal-to-liquid products.

Sec. 98.386 Data reporting requirements.

In addition to the information required by Sec. 98.3(c), the following requirements apply:

(a) Producers shall report the following information for each coal- to-liquid facility:

(1) For each product listed in Table MM-1 of subpart MM of this part that enters the coal-to-liquid facility to be further processed or otherwise used on site, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product.

(2) For each product listed in Table MM-1 of subpart MM of this part that enters the coal-to-liquid facility to be further processed or otherwise used on site, report the total annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product.

(3) For each feedstock reported in paragraph (a)(2) that was produced by blending a fossil fuel-based product with a biomass-based product, report the percent of the volume reported in paragraph (a)(2) of this section that is fossil fuel-based.

(4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(1) of this section.

(5) For each product (leaving the coal-to-liquid facility) listed in Table MM-1 of subpart MM of this part, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product.

(6) For each product (leaving the coal-to-liquid facility) listed in Table MM-1 of subpart MM of this part, report the total annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product.

(7) For each product reported in paragraph (a)(6) of this section that was produced by blending a fossil fuel-based

Page 56490

product with a biomass-based product, report the percent of the volume reported in paragraph (a)(6) of this section that is fossil fuel-based.

(8) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(5) of this section.

(9) For every feedstock reported in paragraph (a)(2) of this section for which Calculation Methodology 2 of subpart MM of this part was used to determine an emissions factor, report:

(i) The number of samples collected according to Sec. 98.394(c).

(ii) The sampling standard method used.

(iii) The carbon share test results in percent mass.

(iv) The standard method used to test carbon share.

(v) The calculated CO2emissions factor.

(10) For every non-solid feedstock reported in paragraph (a)(2) of this section for which Calculation Methodology 2 of subpart MM of this part was used to determine an emissions factor, report:

(i) The density test results in metric tons per barrel.

(ii) The standard method used to test density.

(11) For every product reported in paragraph (a)(6) of this section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report:

(i) The number of samples collected according to Sec. 98.394(c).

(ii) The sampling standard method used.

(iii) The carbon share test results in percent mass.

(iv) The standard method used to test carbon share.

(v) The calculated CO2emissions factor.

(12) For every non-solid product reported in paragraph (a)(6) of this section for which Calculation Methodology 2 of subpart MM of this part was used to determine an emissions factor, report:

(i) The density test results in metric tons per barrel.

(ii) The standard method used to test density.

(13) For each specific type of biomass that enters the coal-to- liquid facility to be co-processed with fossil fuel-based feedstock to produce a product reported in paragraph (a)(6) of this section, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used.

(14) For each specific type of biomass that enters the coal-to- liquid facility to be co-processed with fossil fuel-based feedstock to produce a product reported in paragraph (a)(6) of this section, report the total annual quantity in metric tons or barrels.

(15) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(3) of this section.

(16) The CO2emissions in metric tons that would result from the complete combustion or oxidation of each feedstock reported in paragraph (a)(2) of this section, calculated according to Sec. 98.393(b) or (h).

(17) The CO2emissions in metric tons that would result from the complete combustion or oxidation of each product (leaving the coal-to-liquid facility) reported in paragraph (a)(6) of this section, calculated according to Sec. 98.393(a) or (h).

(18) Annual CO2emissions in metric tons that would result from the complete combustion or oxidation of each type of biomass feedstock co-processed with fossil fuel-based feedstocks reported in paragraph (a)(3) of this section, calculated according to

Sec. 98.393(c).

(19) Annual CO2emissions that would result from the complete combustion or oxidation of all products, calculated according to Sec. 98.393(d).

(20) Annual quantity of bulk NGLs in metric tons or barrels received for processing during the reporting year.

(b) In addition to the information required by Sec. 98.3(c), each importer shall report all of the following information at the corporate level:

(1) For each product listed in Table MM-1 of subpart MM of this part, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product.

(2) For each product listed in Table MM-1 of subpart MM of this part, report the total annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product as listed in Table MM-1 of subpart MM of this part.

(3) For each product reported in paragraph (b)(2) of this section that was produced by blending a fossil fuel-based product with a biomass-based product, report the percent of the volume reported in paragraph (b)(2) of this section that is fossil fuel-based.

(4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (b)(1) of this section.

(5) For each product reported in paragraph (b)(2) of this section for which Calculation Methodology 2 of this subpart used was used to determine an emissions factor, report:

(i) The number of samples collected according to Sec. 98.394(c)

(ii) The sampling standard method used.

(iii) The carbon share test results in percent mass.

(iv) The standard method used to test carbon share.

(v) The calculated CO2emissions factor in metric tons.

(6) For each non-solid product reported in paragraph (b)(2) of this section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report:

(i) The density test results in metric tons ber barrel.

(ii) The standard method used to test density.

(7) The CO2emissions in metric tons that would result from the complete combustion or oxidation of each imported product reported in paragraph (b)(2) of this section, calculated according to

Sec. 98.393(a).

(8) The total sum of CO2emissions that would result from the complete combustion or oxidation of all imported products, calculated according to Sec. 98.393(e).

(c) In addition to the information required by Sec. 98.3(c), each exporter shall report all of the following information at the corporate level:

(2) For each product listed in table MM-1 of subpart MM of this part, report the total annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product.

(3) For each product reported in paragraph (c)(2) of this section that was produced by blending a fossil fuel-based product with a biomass-based product, report the percent of the volume reported in paragraph (c)(2) of this section that is fossil fuel-based.

(4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (c)(1) of this section.

(5) For each product reported in paragraph (c)(2) of this section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report:

(i) The number of samples collected according to Sec. 98.394(c).

Page 56491

(ii) The sampling standard method used.

(iii) The carbon share test results in percent mass.

(iv) The standard method used to test carbon share.

(v) The calculated CO2emissions factor in metric tons.

(6) For each non-solid product reported in paragraph (c)(2) of this section for which Calculation Methodology 2 of this subpart used was used to determine an emissions factor, report:

(i) The density test results in metric tons per barrel.

(ii) The standard method used to test density.

(7) The CO2emissions in metric tons that would result from the complete combustion or oxidation of each exported product reported in paragraph (c)(2) of this section, calculated according to

Sec. 98.393(a).

(8) Total sum of CO2emissions that would result from the complete combustion or oxidation of all exported products, calculated according to Sec. 98.393(e).

Sec. 98.387 Records that must be retained.

You must retain records according to the requirements in Sec. 98.397 as if they applied to the appropriate coal-to-liquid product supplier (e.g., retaining copies of all reports submitted to EPA under

Sec. 98.386 and records to support information contained in those reports). Any records for petroleum products that are required to be retained in Sec. 98.397 are also required for coal-to-liquid products.

Sec. 98.388 Definitions.

All terms used in this subpart have the same meaning given in the

Clean Air Act and subpart A of this part.

Subpart MM--Suppliers of Petroleum Products

Sec. 98.390 Definition of the source category.

This source category consists of petroleum refineries and importers and exporters of petroleum products and natural gas liquids as listed in Table MM-1 of this subpart.

(a) A petroleum refinery for the purpose of this subpart is any facility engaged in producing petroleum products through the distillation of crude oil.

(b) A refiner is the owner or operator of a petroleum refinery.

(c) Importer has the same meaning given in Sec. 98.6 and includes any entity that imports petroleum products or natural gas liquids as listed in Table MM-1 of this subpart. Any blender or refiner of refined or semi-refined petroleum products shall be considered an importer if it otherwise satisfies the aforementioned definition.

(d) Exporter has the same meaning given in Sec. 98.6 and includes any entity that exports petroleum products or natural gas liquids as listed in Table MM-1 of this subpart. Any blender or refiner of refined or semi-refined petroleum products shall be considered an exporter if it otherwise satisfies the aforementioned definition.

Sec. 98.391 Reporting threshold.

Any supplier of petroleum products who meets the requirements of

Sec. 98.2(a)(4) must report GHG emissions.

Sec. 98.392 GHGs To report.

Suppliers of petroleum products must report the CO2 emissions that would result from the complete combustion or oxidation of each petroleum product and natural gas liquid produced, used as feedstock, imported, or exported during the calendar year.

Additionally, refiners must report CO2emissions that would result from the complete combustion or oxidation of any biomass co- processed with petroleum feedstocks.

Sec. 98.393 Calculating GHG emissions.

(a) Calculation for individual products produced, imported, or exported.

(1) Except as provided in paragraph (h) of this section, any refiner, importer, or exporter shall calculate CO2emissions from each individual petroleum product and natural gas liquid using

Equation MM-1 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.152

Where:

CO2i= Annual CO2emissions that would result from the complete combustion or oxidation of each petroleum product or natural gas liquid ``i'' (metric tons).

Producti= Annual volume of product ``i'' produced, imported, or exported by the reporting party (barrels). For refiners, this volume only includes products ex refinery gate. For natural gas liquids, volumes shall reflect the individual components of the product as listed in Table MM-1 of this subpart.

EFi= Product-specific CO2emission factor

(metric tons CO2per barrel).

(2) In the event that an individual petroleum product is produced as a solid rather than liquid any refiner, importer, or exporter shall calculate CO2emissions using Equation MM- 1 of this section.

Where:

CO2i= Annual CO2emissions that would result from the complete combustion or oxidation of each petroleum product

``i'' (metric tons).

Producti= Annual mass of product ``i'' produced, imported, or exported by the reporting party (metric tons). For refiners, this mass only includes products ex refinery gate.

EFi= Product-specific CO2emission factor

(metric tons CO2per metric ton of product).

(b) Calculation for individual products that enter a refinery as a non-crude feedstock.

(1) Except as provided in paragraph (h) of this section, any refiner shall calculate CO2emissions from each non-crude feedstock using Equation MM-2 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.153

Where:

CO2j= Annual CO2emissions that would result from the complete combustion or oxidation of each non-crude feedstock ``j'' (metric tons).

Feedstockj= Annual volume of a petroleum product or natural gas liquid ``j'' that enters the refinery to be further refined or otherwise used on site (barrels). For natural gas liquids, volumes shall reflect the individual components of the product as listed in table MM-1 of this subpart.

EFj= Feedstock-specific CO2emission factor

(metric tons CO2per barrel).

(2) In the event that a non-crude feedstock enters a refinery as a solid rather than liquid, the refiner shall calculate CO2 emissions using Equation MM-2 of this section.

Where:

CO2j= Annual CO2emissions that would result from the complete combustion or oxidation of each non-crude feedstock ``j'' (metric tons).

Feedstockj= Annual mass of a petroleum product ``j'' that enters the refinery to be further refined or otherwise used on site (metric tons).

EFj= Feedstock-specific CO2emission factor

(metric tons CO2per metric ton of feedstock).

(1) Refiners shall calculate CO2emissions from each type of biomass that enters a refinery and is co-processed with petroleum feedstocks using Equation MM-3 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.154

Where:

CO2m= Annual CO2emissions that would result from the complete combustion or oxidation of each type of biomass

``m'' (metric tons).

Biomassm= Annual volume of a specific type of biomass that enters the refinery and is co-processed with petroleum feedstocks to produce a petroleum product reported under paragraph

(a) of this section (barrels).

Page 56492

EFm= Biomass-specific CO2emission factor

(metric tons CO2per barrel).

(2) In the event that biomass enters a refinery as a solid rather than liquid and is co-processed with petroleum feedstocks, the refiner shall calculate CO2emissions from each type of biomass using Equation MM-3 of this section.

Where:

CO2m= Annual CO2emissions that would result from the complete combustion or oxidation of each type of biomass

``m'' (metric tons).

Biomassm= Total annual mass of a specific type of biomass that enters the refinery to be co-processed with petroleum feedstocks to produce a petroleum product reported under paragraph

(a) of this section (metric tons).

EFm= Biomass-specific CO2emission factor

(metric tons CO2per metric ton of biomass).

(d) Summary calculation for refinery products. Refiners shall calculate annual CO2emissions from all products using

Equation MM-4 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.155

Where:

CO2r= Annual CO2emissions that would result from the complete combustion or oxidation of all petroleum products and natural gas liquids (ex refinery gate) minus non-crude feedstocks and any biomass to be co-processed with petroleum feedstocks.

CO2i= Annual CO2emissions that would result from the complete combustion or oxidation of each petroleum product or natural gas liquid ``i'' (metric tons).

CO2j= Annual CO2emissions that would result from the complete combustion or oxidation of each non-crude feedstock ``j'' (metric tons).

CO2m= Annual CO2emissions that would result from the complete combustion or oxidation of each type of biomass

``m'' (metric tons).

(e) Summary calculation for importer and exporter products.

Importers and exporters shall calculate annual CO2emissions from all petroleum products and natural gas liquids imported or exported, respectively, using Equations MM-1 and MM-5 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.156

Where:

CO2i= Annual CO2emissions that would result from the complete combustion or oxidation of each petroleum product or natural gas liquid ``i'' (metric tons).

CO2x= Annual CO2emissions that would result from the complete combustion or oxidation of all petroleum products and natural gas liquids.

(f) Emission factors for petroleum products and natural gas liquids. The emission factor (EFi,j) for each petroleum product and natural gas liquid shall be determined using either of the calculation methods described in paragraphs (f)(1) or (f)(2) of this section. The same calculation method must be used for the entire quantity of the product for the reporting year. For refiners, the quantity of a product that enters a refinery (i.e., a non-crude feedstock) is considered separate from the quantity of a product ex refinery gate.

(1) Calculation Method 1. For solid products, use the default carbon share factor (i.e., percent carbon by mass) in column B of Table

MM-1 of this subpart for the appropriate product. For all other products, use the default CO2emission factor listed in column C of Table MM-1 of this subpart for the appropriate product.

(2) Calculation Method 2.

(i) For solid products, develop emission factors according to

Equation MM-6 of this section using a value of 1 for density and direct measurements of carbon share according to methods set forth in Sec. 98.394(c). For all other products, develop emission factors according to Equation MM-6 of this section using direct measurements of density and carbon share according to methods set forth in Sec. 98.394(c).

GRAPHIC

TIFF OMITTED TR30OC09.157

Where:

EFi,j= Emission factor of the petroleum product or natural gas liquid (metric tons CO2per barrel or per metric ton of product).

Density = Density of the petroleum product or natural gas liquid

(metric tons per barrel for non-solid products, 1 for solid products).

Carbon share = Percent of total mass that carbon represents in the petroleum product or natural gas liquid, expressed as a fraction

(e.g., 75% would be expressed as 0.75 in the above equation). 44/12 = Conversion factor for carbon to carbon dioxide.

(ii) If you use a standard method that involves gas chromatography to determine the percent mass of each component in a product, calculate the product's carbon share using Equation MM-7 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.158

Where:

Carbon Share = Percent of total mass that carbon represents in the petroleum product or natural gas liquid.

%Composition i* * *n = Percent of total mass that each molecular component in the petroleum product or natural gas liquid represents as determined by the procedures in the selected standard method.

%Massi* * *n= Percent of total mass that carbon represents in each molecular component of the petroleum product or natural gas liquid.

(g) Emission factors for biomass co-processed with petroleum feedstocks. Refiners shall use the most appropriate default

CO2emission factor (EFm) for biomass in Table

MM-2 of this subpart to calculate CO2emissions in paragraph

(h) Special procedures for blended biomass-based fuels. In the event that some portion of a petroleum product is biomass-based and was not derived by co-processing biomass and petroleum feedstocks together

(i.e., the petroleum product was produced by blending a

Page 56493

petroleum-based product with a biomass-based fuel), the reporting party shall calculate emissions for the petroleum product according to one of the methods in paragraphs (h)(1) through (h)(4) of this section, as appropriate.

(1) A reporter using Calculation Methodology 1 to determine the emission factor of a petroleum product shall calculate the

CO2emissions associated with that product using Equation

MM-8 of this section in place of Equation MM-1 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.159

Where:

CO2i= Annual CO2emissions that would result from the complete combustion or oxidation of each petroleum product

``i'' (metric tons).

Producti= Annual volume of each petroleum product ``i'' produced, imported, or exported by the reporting party (barrels).

For refiners, this volume only includes products ex refinery gate.

EFi= Petroleum product-specific CO2emission factor (metric tons CO2per barrel) from Table MM-1 of this subpart.

%Voli= Percent volume of product ``i'' that is petroleum-based, including 2.5% of the volume of any ethanol product blended into a petroleum-based product to represent the denaturant in that ethanol product, expressed as a fraction (e.g., 75% would be expressed as 0.75 in the above equation).

(2) A refinery using Calculation Methodology 1 of this subpart to determine the emission factor of a non-crude petroleum feedstock shall calculate the CO2emissions associated with that feedstock using Equation MM-9 of this section in place of Equation MM-2 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.160

Where:

CO2j= Annual CO2emissions that would result from the complete combustion or oxidation of each non-crude feedstock ``j'' (metric tons).

Feedstockj= Annual volume of each petroleum product

``j'' that enters the refinery as a feedstock to be further refined or otherwise used on site (barrels).

EFj= Non-crude petroleum feedstock-specific

CO2emission factor (metric tons CO2per barrel).

%Volj= Percent volume of feedstock ``j'' that is petroleum-based, including 2.5% of the volume of any ethanol product blended with the petroleum-based product to represent the denaturant in that ethanol product, expressed as a fraction (e.g., 75% would be expressed as 0.75 in the above equation).

(3) A reporter using Calculation Methodology 2 of this subpart to determine the emission factor of a petroleum product must calculate the

CO2emissions associated with that product using Equation

MM-10 of this section in place of Equation MM-1 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.161

Where:

CO2i= Annual CO2emissions that would result from the complete combustion or oxidation of each product ``i''

(metric tons).

Producti= Annual volume of each petroleum product ``i'' produced, imported, or exported by the reporting party (barrels).

For refiners, this volume only includes products ex refinery gate.

EFi= Product-specific CO2emission factor

(metric tons CO2per barrel).

EFm= Default CO2emission factor from Table

MM-2 of this subpart that most closely represents the component of product ``i'' that is biomass-based.

%Volm= Percent volume of petroleum product ``i'' that is biomass-based, not including 2.5% of the volume of any ethanol product blended with the petroleum-based product, which represents the denaturant in that ethanol product, expressed as a fraction

(e.g., 75% would be expressed as 0.75 in the above equation).

(4) A refiner using Calculation Methodology 2 of this subpart to determine the emission factor of a non-crude petroleum feedstock must calculate the CO2emissions associated with that feedstock using Equation MM-11 of this section in place of Equation MM-2 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.162

Where:

CO2j= Annual CO2emissions that would result from the complete combustion or oxidation of each non-crude feedstock ``j'' (metric tons).

Feedstockj= Annual volume of each petroleum product

``j'' that enters the refinery to be further refined or otherwise used on site (barrels).

EFj= Feedstock-specific CO2emission factor

(metric tons CO2per barrel).

EFm= Default CO2emission factor from Table

MM-2 of this subpart that most closely represents the component of petroleum product ``j'' that is biomass-based.

%Volm= Percent volume of non-crude feedstock ``j'' that is biomass-based, not including 2.5% of the volume of any ethanol product blended with the petroleum-based product, which represents the denaturant in that ethanol product, expressed as a fraction

(e.g., 75% would be expressed as 0.75 in the above equation).

Sec. 98.394 Monitoring and QA/QC requirements.

(a) Determination of quantity.

(1) The quantity of petroleum products, natural gas liquids, biomass, and crude oil shall be determined as follows:

(i) Where an appropriate standard method published by a consensus- based standards organization exists, such a method shall be used.

Consensus-based

Page 56494

standards organizations include, but are not limited to, the following:

ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the American Society of Mechanical

Engineers (ASME), the American Petroleum Institute (API), and the North

American Energy Standards Board (NAESB).

(ii) Where no appropriate standard method developed by a consensus- based standards organization exists, industry standard practices shall be followed.

(iii) For products that are liquid at 60 degrees Fahrenheit and one standard atmosphere, all measurements of quantity shall be temperature- adjusted and pressure-adjusted to these conditions. For all other products, reporters shall use appropriate standard conditions specified in the standard method; if temperature and pressure conditions are not specified in the standard method or if a reporter uses an industry standard practice to determine quantity, the reporter shall use appropriate standard conditions according to established industry practices.

(2) All measurement equipment (including, but not limited to, flow meters and tank gauges) used for compliance with this subpart shall be appropriate for the standard method or industry standard practice followed under paragraph (a)(1)(i) or (a)(1)(ii) of this section.

(b) Equipment Calibration.

(1) All measurement equipment shall be calibrated prior to its first use for reporting under this subpart, using an appropriate standard method published by a consensus based standards organization or according to the equipment manufacturer's directions.

(2) Measurement equipment shall be recalibrated at the minimum frequency specified by the standard method used or by the equipment manufacturer's directions.

(1) Reporting parties shall collect one sample of each petroleum product or natural gas liquid on any day of each calendar month of the reporting year in which the quantity of that product was measured in accordance with the requirements of this subpart. For example, if a given product was measured as entering the refinery continuously throughout the reporting year, twelve samples of that product shall be collected over the reporting year, one on any day of each calendar month of that year. If a given product was only measured from April 15 through June 10 of the reporting year, a refiner would collect three samples during that year, one during each of the calendar months of

April, May and June on a day when the product was measured as either entering or exiting the refinery. Each sample shall be collected using an appropriate standard method published by a consensus-based standards organization.

(2) Mixing and handling of samples shall be performed using an appropriate standard method published by a consensus-based standards organization.

(3) Density measurement.

(i) For all products that are not solid, reporters shall test for density using an appropriate standard method published by a consensus- based standards organization.

(ii) The density value for a given petroleum product shall be generated by either making a physical composite of all of the samples collected for the reporting year and testing that single sample or by measuring the individual samples throughout the year and defining the representative density value for the sample set by numerical means, i.e., a mathematical composite. If a physical composite is chosen as the option to obtain the density value, the reporter shall submit each of the individual samples collected during the reporting year to the laboratory responsible for generating the composite sample.

(iii) For physical composites, the reporter shall handle the individual samples and the laboratory shall mix them in accordance with an appropriate standard method published by a consensus-based standards organization.

(iv) All measurements of density shall be temperature-adjusted and pressure-adjusted to the conditions assumed for determining the quantities of the product reported under this subpart.

(4) Carbon share measurement.

(i) Reporters shall test for carbon share using an appropriate standard method published by a consensus-based standards organization.

(ii) If a standard method that involves gas chromatography is used to determine the percent mass of each component in a product, the molecular formula for each component shall be obtained from the information provided in the standard method and the atomic mass of each element in a given molecular component shall be obtained from the periodic table of the elements.

(iii) The carbon share value for a given petroleum product shall be generated by either making a physical composite of all of the samples collected for the reporting year and testing that single sample or by measuring the individual samples throughout the year and defining the representative carbon share value for the sample set by numerical means, i.e., a mathematical composite. If a physical composite is chosen as the option to obtain the carbon share value, the reporter shall submit each of the individual samples collected during the reporting year to the laboratory responsible for generating the composite sample.

(iv) For physical composites, the reporter shall handle the individual samples and the laboratory shall mix them in accordance with an appropriate standard method published by a consensus-based standards organization.

(d) Measurement of API gravity and sulfur content of crude oil.

(1) Samples of each batch of crude oil shall be taken according to an appropriate standard method published by a consensus-based standards organization.

(2) Samples shall be handled according to an appropriate standard method published by a consensus-based standards organization.

(3) API gravity shall be measured using an appropriate standard method published by a consensus-based standards organization.

(4) Sulfur content shall be measured using an appropriate standard method published by a consensus-based standards organization.

(5) All measurements shall be temperature-adjusted and pressure- adjusted to the conditions assumed for determining the quantities of crude oil reported under this subpart.

Sec. 98.395 Procedures for estimating missing data.

(a) Determination of quantity. Whenever the quality assurance procedures in Sec. 98.394(a) cannot be followed to measure the quantity of one or more petroleum products, natural gas liquids, types of biomass, feedstocks, or crude oil batches during any period (e.g., if a meter malfunctions), the following missing data procedures shall be used:

(1) For quantities of a product that are purchased or sold, a period of missing data shall be substituted using a reporter's established procedures for billing purposes in that period as agreed to by the party selling or purchasing the product.

(2) For quantities of a product that are not purchased or sold but of which the custody is transferred, a period of missing data shall be substituted using a reporter's established procedures for tracking purposes in that period as agreed to by the party involved in custody transfer of the product.

Page 56495

(b) Determination of emission factor. Whenever any of the procedures in Sec. 98.394(c) cannot be followed to develop an emission factor for any reason, Calculation Methodology 1 of this subpart must be used in place of Calculation Methodology 2 of this subpart for the entire reporting year.

For missing data on sulfur content or API gravity, the substitute data value shall be the arithmetic average of the quality-assured values of

API gravity or sulfur content in the batch preceding and the batch immediately following the missing data incident. If no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured values for API gravity and sulfur content obtained from the batch after the missing data period.

Sec. 98.396 Data reporting requirements.

In addition to the information required by Sec. 98.3(c), the following requirements apply:

(a) Refiners shall report the following information for each facility:

(1) For each petroleum product or natural gas liquid listed in table MM-1 of this subpart that enters the refinery to be further refined or otherwise used on site, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product.

(2) For each petroleum product or natural gas liquid listed in

Table MM-1 of this subpart that enters the refinery to be further refined or otherwise used on site, report the annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product.

(3) For each feedstock reported in paragraph (a)(2) of this section that was produced by blending a petroleum-based product with a biomass- based product, report the percent of the volume reported in paragraph

(a)(2) of this section that is petroleum-based.

(4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(1) of this section.

(5) For each petroleum product and natural gas liquid (ex refinery gate) listed in Table MM-1 of this subpart, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product.

(6) For each petroleum product and natural gas liquid (ex refinery gate) listed in Table MM-1 of this subpart, report the annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product.

(7) For each product reported in paragraph (a)(6) of this section that was produced by blending a petroleum-based product with a biomass- based product, report the percent of the volume reported in paragraph

(a)(6) of this section that is petroleum-based.

(8) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(5) of this section.

(9) For every feedstock reported in paragraph (a)(2) of this section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report:

(i) The number of samples collected according to Sec. 98.394(c)

(ii) The sampling standard method used.

(iii) The carbon share test results in percentmass.

(iv) The standard method used to test carbon share.

(v) The calculated CO2emissions factor in metric tons.

(10) For every non-solid feedstock reported in paragraph (a)(2) of this section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report:

(i) The density test results in metric tons per barrel.

(ii) The standard method used to test density.

(11) For every petroleum product and natural gas liquid reported in paragraph (a)(6) of this section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report:

(i) The number of samples collected according to Sec. 98.394(c).

(ii) The sampling standard method used.

(iii) The carbon share test results in percentmass.

(iv) The standard method used to test carbon share.

(v) The calculated CO2emissions factor in metric tons

CO2per barrel or per metric ton of product.

(12) For every non-solid petroleum product and natural gas liquid reported in paragraph (a)(6) for which Calculation Method 2 was used to determine an emissions factor, report:

(i) The density test results in metric tons per barrel.

(ii) The standard method used to test density.

(13) For each specific type of biomass that enters the refinery to be co-processed with petroleum feedstocks to produce a petroleum product reported in paragraph (a)(6) of this section, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used.

(14) For each specific type of biomass that enters the refinery to be co-processed with petroleum feedstocks to produce a petroleum product reported in paragraph (a)(6) of this section, report the annual quantity in metric tons or barrels.

(15) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (a)(13) of this section.

(16) The CO2emissions in metric tons that would result from the complete combustion or oxidation of each petroleum product and natural gas liquid (ex refinery gate) reported in paragraph (a)(6) of this section, calculated according to Sec. 98.393(a) or (h).

(17) The CO2emissions in metric tons that would result from the complete combustion or oxidation of each feedstock reported in paragraph (a)(2) of this section, calculated according to Sec. 98.393(b) or (h).

(18) The CO2emissions in metric tons that would result from the complete combustion or oxidation of each type of biomass feedstock co-processed with petroleum feedstocks reported in paragraph

(a)(13) of this section, calculated according to Sec. 98.393(c).

(19) The sum of CO2emissions that would result from the complete combustion or oxidation of all products, calculated according to Sec. 98.393(d).

(20) All of the following information for all crude oil feedstocks used at the refinery:

(i) Batch volume in barrels.

(ii) API gravity of the batch at the point of entry at the refinery.

(iii) Sulfur content of the batch at the point of entry at the refinery.

(iv) Country of origin of the batch, if known.

(21) The quantity of bulk NGLs in metric tons or barrels received for processing during the reporting year.

(b) In addition to the information required by Sec. 98.3(c), each importer shall report all of the following information at the corporate level:

(1) For each petroleum product and natural gas liquid listed in

Table MM-1 of this subpart, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids,

Page 56496

quantity shall reflect the individual components of the product.

(2) For each petroleum product and natural gas liquid listed in

Table MM-1 of this subpart, report the annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product as listed in Table MM-1 of this subpart.

(3) For each product reported in paragraph (b)(2) of this section that was produced by blending a petroleum-based product with a biomass- based product, report the percent of the volume reported in paragraph

(b)(2) of this section that is petroleum-based.

(4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (b)(1) of this section.

(5) For each product reported in paragraph (b)(2) of this section for which Calculation Methodology 2 of this subpart used was used to determine an emissions factor, report:

(i) The number of samples collected according to Sec. 98.394(c).

(ii) The sampling standard method used.

(iii) The carbon share test results in percent mass.

(iv) The standard method used to test carbon share.

(v) The calculated CO2emissions factor in metric tons

CO2per barrel or per metric ton of product.

(6) For each non-solid product reported in paragraph (b)(2) of this section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report:

(i) The density test results in metric tons per barrel.

(ii) The standard method used to test density.

(7) The CO2emissions in metric tons that would result from the complete combustion or oxidation of each imported petroleum product and natural gas liquid reported in paragraph (b)(2) of this section, calculated according to Sec. 98.393(a).

(8) The sum of CO2emissions that would result from the complete combustion oxidation of all imported products, calculated according to Sec. 98.393(e).

(c) In addition to the information required by Sec. 98.3(c), each exporter shall report all of the following information at the corporate level:

(1) For each petroleum product and natural gas liquid listed in

Table MM-1 of this subpart, report the annual quantity in metric tons or barrels by each quantity measurement standard method or other industry standard practice used. For natural gas liquids, quantity shall reflect the individual components of the product.

(2) For each petroleum product and natural gas liquid listed in

Table MM-1 of this subpart, report the annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product.

(3) For each product reported in paragraph (c)(2) of this section that was produced by blending a petroleum-based product with a biomass- based product, report the percent of the volume reported in paragraph

(c)(2) of this section that is petroleum based.

(4) Each standard method or other industry standard practice used to measure each quantity reported in paragraph (c)(1) of this section.

(5) For each product reported in paragraph (c)(2) of this section for which Calculation Methodology 2 of this subpart was used to determine an emissions factor, report:

(i) The number of samples collected according to Sec. 98.394(c).

(ii) The sampling standard method used.

(iii) The carbon share test results in percentmass.

(iv) The standard method used to test carbon share.

(v) The calculated CO2emissions factor in metric tons

CO2per barrel or per metric ton of product.

(6) For each non-solid product reported in paragraph (c)(2) of this section for which Calculation Methodology 2 of this subpart used was used to determine an emissions factor, report:

(i) The density test results in metric tons per barrel.

(ii) The standard method used to test density.

(7) The CO2emissions in metric tons that would result from the complete combustion or oxidation of for each exported petroleum product and natural gas liquid reported in paragraph (c)(2) of this section, calculated according to Sec. 98.393(a).

(8) The sum of CO2emissions that would result from the complete combustion or oxidation of all exported products, calculated according to Sec. 98.393(e).

Sec. 98.397 Records that must be retained.

(a) All reporters shall retain copies of all reports submitted to

EPA under Sec. 98.396. In addition, all reporters shall maintain sufficient records to support information contained in those reports, including but not limited to information on the characteristics of their feedstocks and products.

(b) Reporters shall maintain records to support quantities that are reported under this subpart, including records documenting any estimations of missing data and the number of calendar days in the reporting year for which substitute data procedures were followed. For all quantities of petroleum products, natural gas liquids, biomass, and feedstocks, reporters shall maintain metering, guaging, and other records normally maintained in the course of business to document product and feedstock flows including the date of initial calibration and the frequency of recalibration for the measurement equipment used

(c) Reporters shall retain laboratory reports, calculations and worksheets used to estimate the CO2emissions of the quantities of petroleum products, natural gas liquids, biomass, and feedstocks reported under this subpart.

(d) Reporters shall maintain laboratory reports, calculations and worksheets used in the measurement of density and carbon share for any petroleum product or natural gas liquid for which CO2 emissions were calculated using Calculation Methodology 2.

(e) Reporters shall maintain laboratory reports, calculations and worksheets used in the measurement of API gravity and sulfur content for every crude oil batch reported under this subpart.

(f) Estimates of missing data shall be documented and records maintained showing the calculations.

(g) Reporters described in this subpart shall also retain all records described in Sec. 98.3(g).

Sec. 98.398 Definitions.

All terms used in this subpart have the same meaning given in the

Clean Air Act and subpart A of this part.

Page 56497

Table MM-1 to Subpart MM of Part 98--Default Factors for Petroleum

Products and Natural Gas Liquids 1 2

Column C:

Column A:

Column B:

emission density

carbon

factor

Products

(metric share (% of

(metric tons/bbl)

mass)

tons CO2/ bbl)

Finished Motor Gasoline

Conventional--Summer

Regular......................

0.1181

86.66

0.3753

Midgrade.....................

0.1183

86.63

0.3758

Premium......................

0.1185

86.61

0.3763

Conventional--Winter

Regular......................

0.1155

86.50

0.3663

Midgrade.....................

0.1161

86.55

0.3684

Premium......................

0.1167

86.59

0.3705

Reformulated--Summer

Regular......................

0.1167

86.13

0.3686

Midgrade.....................

0.1165

86.07

0.3677

Premium......................

0.1164

86.00

0.3670

Reformulated--Winter

Regular......................

0.1165

86.05

0.3676

Midgrade.....................

0.1165

86.06

0.3676

Premium......................

0.1166

86.06

0.3679

Gasoline--Other..................

0.1185

86.61

0.3763

Blendstocks

CBOB--Summer

Regular......................

0.1181

86.66

0.3753

Midgrade.....................

0.1183

86.63

0.3758

Premium......................

0.1185

86.61

0.3763

CBOB--Winter

Regular......................

0.1155

86.50

0.3663

Midgrade.....................

0.1161

86.55

0.3684

Premium......................

0.1167

86.59

0.3705

RBOB--Summer

Regular......................

0.1167

86.13

0.3686

Midgrade.....................

0.1165

86.07

0.3677

Premium......................

0.1164

86.00

0.3670

RBOB--Winter

Regular......................

0.1165

86.05

0.3676

Midgrade.....................

0.1165

86.06

0.3676

Premium......................

0.1166

86.06

0.3679

Blendstocks--Other...............

0.1185

86.61

0.3763

Oxygenates

Methanol.........................

0.1268

37.48

0.1743

GTBA.............................

0.1257

64.82

0.2988

MTBE.............................

0.1181

68.13

0.2950

ETBE.............................

0.1182

70.53

0.3057

TAME.............................

0.1229

70.53

0.3178

DIPE.............................

0.1156

70.53

0.2990

Distillate Fuel Oil

Distillate No. 1

Ultra Low Sulfur.............

0.1346

86.40

0.4264

Low Sulfur...................

0.1346

86.40

0.4264

High Sulfur..................

0.1346

86.40

0.4264

Distillate No. 2

Ultra Low Sulfur.............

0.1342

87.30

0.4296

Low Sulfur...................

0.1342

87.30

0.4296

High Sulfur..................

0.1342

87.30

0.4296

Distillate Fuel Oil No. 4........

0.1452

86.47

0.4604

Residual Fuel Oil No. 5 (Navy

0.1365

85.67

0.4288

Special)........................

Residual Fuel Oil No. 6 (a.k.a.

0.1528

84.67

0.4744

Bunker C).......................

Kerosene-Type Jet Fuel...........

0.1294

86.30

0.4095

Kerosene.........................

0.1346

86.40

0.4264

Diesel--Other....................

0.1452

86.47

0.4604

Petrochemical Feedstocks

Page 56498

Naphthas (401 [deg]F)....

0.1390

87.30

0.4450

Unfinished Oils

Heavy Gas Oils...................

0.1476

85.80

0.4643

Residuum.........................

0.1622

85.70

0.5097

Other Petroleum Products and Natural Gas Liquids

Aviation Gasoline................

0.1120

85.00

0.3490

Special Naphthas.................

0.1222

84.76

0.3798

Lubricants.......................

0.1428

85.80

0.4492

Waxes............................

0.1285

85.30

0.4019

Petroleum Coke...................

0.1818

92.28

0.6151

Asphalt and Road Oil.............

0.1634

83.47

0.5001

Still Gas........................

0.1405

77.70

0.4003

Ethane...........................

0.0866

79.89

0.2537

Ethylene.........................

0.0903

85.63

0.2835

Propane..........................

0.0784

81.71

0.2349

Propylene........................

0.0803

85.63

0.2521

Butane...........................

0.0911

82.66

0.2761

Butylene.........................

0.0935

85.63

0.2936

Isobutane........................

0.0876

82.66

0.2655

Isobutylene......................

0.0936

85.63

0.2939

Pentanes Plus....................

0.1055

83.63

0.3235

Miscellaneous Products...........

0.1380

85.49

0.4326

\1\ In the case of products blended with some portion of biomass-based fuel, the carbon share in Table MM-1 of this subpart represents only the petroleum-based components.

\2\ Products that are derived entirely from biomass should not be reported, but products that were derived from both biomass and a petroleum product (i.e., co-processed) should be reported as the petroleum product that it most closely represents.

Table MM-2 to Subpart MM of Part 98--Default Factors for Biomass-Based

Fuels and Biomass

Column C:

Column A:

Column B:

Emission

Density

Carbon

factor

Biomass-based fuel and biomass

(metric share (% of

(metric tons/bbl)

mass)

tons CO2/ bbl)

Ethanol (100%)...................

0.1267

52.14

0.2422

Biodiesel (100%, methyl ester)...

0.1396

77.30

0.3957

Rendered Animal Fat..............

0.1333

76.19

0.3724

Vegetable Oil....................

0.1460

76.77

0.4110

Subpart NN--Suppliers of Natural Gas and Natural Gas Liquids

Sec. 98.400 Definition of the source category.

This supplier category consists of natural gas liquids fractionators and local natural gas distribution companies.

(a) Natural gas liquids fractionators are installations that fractionate natural gas liquids (NGLs) into their consitutent liquid products (ethane, propane, normal butane, isobutane or pentanes plus) for supply to downstream facilities.

(b) Local Distribution Companies (LDCs) are companies that own or operate distribution pipelines, not interstate pipelines or intrastate pipelines, that physically deliver natural gas to end users and that are regulated as separate operating companies by State public utility commissions or that operate as independent municipally-owned distribution systems.

(1) Field gathering and boosting stations.

(2) Natural gas processing plants that separate NGLs from natural gas and produce bulk or y-grade NGLs but do not fractionate these NGLs into their constituent products.

(3) Facilities that meet the definition of refineries and report under subpart MM of this part.

(4) Facilities that meet the definition of petrochemical plants and report under subpart X of this part.

Sec. 98.401 Reporting threshold.

Any supplier of natural gas and natural gas liquids that meets the requirements of Sec. 98.2(a)(4) must report GHG emissions.

Sec. 98.402 GHGs to report.

(a) NGL fractionators must report the CO2emissions that would result from the complete combustion or oxidation of the annual quantity of ethane, propane, normal butane, isobutane, and pentanes

Page 56499

plus that is produced and sold or delivered to others.

(b) LDCs must report the CO2emissions that would result from the complete combustion or oxidation of the annual volumes of natural gas provided to end-users on their distribution systems.

Sec. 98.403 Calculating GHG emissions.

(a) LDCs and fractionators shall, for each individual product reported under this part, calculate the estimated CO2 emissions that would result from the complete combustion or oxidation of the products supplied using either of Calculation Methodology 1 or 2 of this subpart:

(1) Calculation Methodology 1. NGL fractionators shall estimate

CO2emissions that would result from the complete combustion or oxidation of the product(s) supplied using Equation NN-1 of this section. LDCs shall estimate CO2emissions that would result from the complete combustion or oxidation of the product received at the city gate using Equation NN-1. For each product, use the default value for higher heating value and CO2emission factor in

Table NN-1 of this subpart. Alternatively, for each product, a reporter-specific higher heating value and CO2emission factor may be used, in place of one or both defaults provided they are developed using methods outlined in Sec. 98.404. For each product, you must use the same volume unit throughout the equation.

GRAPHIC

TIFF OMITTED TR30OC09.163

Where:

CO2i= Annual CO2mass emissions that would result from the combustion or oxidation of each product ``h'' for redelivery to all recipients (metric tons).

Fuel = Total annual volume of product ``h'' supplied (volume per year, in Mscf for natural gas and bbl for NGLs).

HHV = Higher heating value of product ``h'' supplied (MMBtu/Mscf or

MMBtu/bbl).

EFh= CO2emission factor of product ``h'' (kg

CO2/MMBtu). 1 x 10-3= Conversion factor from kilograms to metric tons (MT/kg).

(2) Calculation Methodology 2. NGL fractionators shall estimate

CO2emissions that would result from the complete combustion or oxidation of the product(s) supplied using Equation NN-2 of this section. LDCs shall estimate CO2emissions that would result from the complete combustion or oxidation of the product received at the city gate using Equation NN-2. For each product, use the default

CO2emission factor found in Table NN-2 of this subpart.

Alternatively, for each product, a reporter-specific CO2 emission factor may be used in place of the default factor, provided it is developed using methods outlined in Sec. 98.404. For each product, you must use the same volume unit throughout the equation.

GRAPHIC

TIFF OMITTED TR30OC09.164

Where:

CO2i= Annual CO2mass emissions that would result from the combustion or oxidation of each product ``h''

(metric tons)

Fuel = Total annual volume of product ``h'' supplied (bbl or Mscf per year)

EFh= CO2emission factor of product ``h'' (MT

CO2/bbl, or MT CO2/Mscf)

(b) Each LDC shall follow the procedures below.

(1) For natural gas that is received for redelivery to downstream gas transmission pipelines and other local distribution companies, use eEquation NN-3 of this section and the default values for the

CO2emission factors found in Table NN-2 of this subpart.

Alternatively, reporter-specific CO2emission factors may be used, provided they are developed using methods outlined in Sec. 98.404.

GRAPHIC

TIFF OMITTED TR30OC09.165

Where:

CO2j= Annual CO2mass emissions that would result from the combustion or oxidation of natural gas for redelivery to transmission pipelines or other LDCs (metric tons).

Fuel = Total annual volume of natural gas supplied (Mscf per year).

EF = Fuel-specific CO2emission factor (MT

CO2/Mscf).

(2)(i) For natural gas delivered to each meter registering a supply equal to or greater than 460,000 Mscf per year, use Equation NN-4 of this section and the default values for the CO2emission factors found in Table NN-2 of this subpart.

(ii) Alternatively, reporter-specific CO2emission factors may be used, provided they are developed using methods outlined in Sec. 98.404.

GRAPHIC

TIFF OMITTED TR30OC09.166

Where:

CO2k= Annual CO2mass emissions that would result from the combustion or oxidation of natural gas received by end-users that receive a supply equal to or greater than 460,000

Mscf per year (metric tons).

Fuel = Total annual volume of natural gas supplied (Mscf per year).

EF = Fuel-specific CO2emission factor (MT

CO2/Mscf).

(3) For natural gas received by the LDC at the city gate that is injected into on-system storage, and/or liquefied and stored, use

Equation NN-5 of this section and the default value for the

CO2emission factors found in Table NN-2 of this subpart.

Alternatively, a reporter-specific CO2emission factor may be used, provided it is developed using methods outlined in Sec. 98.404.

GRAPHIC

TIFF OMITTED TR30OC09.167

Where:

CO2l= Annual CO2mass emissions that would result from the combustion or oxidation of the net natural gas that is liquefied and/or stored and not used for deliveries by the LDC within the reported year (metric tons).

Fuel1= Total annual volume of natural gas received by the LDC at the city gate and stored on-system or liquefied and stored in the reportng year (Mscf per year).

Fuel2= Total annual volume of natural gas that is used for deliveries in the reporting year that was not otherwise accounted for in Equation NN-1 or NN-2 of this section (Mscf per year). This primarily includes natural gas previously stored on- system or liquefied and stored that is removed from storage and used for deliveries to customers or other LDCs by the LDC within the reporting year. This also includes natural gas that bypassed the city gate and was delivered directly to LDC systems from producers or natural gas processing plants from local production.

EF = Fuel-specific CO2emission factor (MT

CO2/Mscf).

Page 56500

(4) Calculate the total CO2emissions that would result from the complete combustion or oxidation of the annual supply of natural gas to end-users using Equation NN-6 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.168

Where:

CO2= Annual CO2mass emissions that would result from the combustion or oxidation of natural gas delivered to

LDC customers not covered in paragraph (b)(2) of this section

(metric tons).

CO2i= Annual CO2mass emissions that would result from the combustion or oxidation of natural gas received at the city gate as calculated in paragraph (a)(1) or (a)(2) of this section (metric tons).

CO2j= Annual CO2mass emissions that would result from the combustion or oxidation of natural gas delivered to transmission pipelines or other LDCs as calculated in paragraph

(b)(1) of this section (metric tons).

CO2k= Annual CO2mass emissions that would result from the combustion or oxidation of natural gas received by end-users that receive a supply equal to or greater than 460,000

Mscf per year as calculated in paragraph (b)(2) of this section

(metric tons).

CO2l= Annual CO2mass emissions that would result from the combustion or oxidation of natural gas received by the LDC and liquefied and/or stored but not used for deliveries within the reported year as calculated in paragraph (b)(3) of this section (metric tons).

(1)(i) For fractionated NGLs received by the reporter from other

NGL fractionators, you shall use Equation NN-7 of this section and the default values for the CO2emission factors found in Table

NN-2 of this subpart.

(ii) Alternatively, reporter-specific CO2emission factors may be used, provided they are developed using methods outlined in Sec. 98.404.

GRAPHIC

TIFF OMITTED TR30OC09.169

Where:

CO2m= Annual CO2mass emissions that would result from the combustion or oxidation of each fractionated NGL product ``g'' received from other fractionators (metric tons).

Fuelg= Total annual volume of each NGL product ``g'' received (bbls).

EF = Fuel-specific CO2emission factor (MT

CO2/bbl).

(2) Calculate the total CO2equivalent emissions that would result from the combustion or oxidation of fractionated NGLs supplied less the quantity received by other fractionators using

Equation NN-8 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.170

Where:

CO2= Annual CO2mass emissions that would result from the combustion or oxidation of fractionated NGLs delivered to customers or on behalf of customers (metric tons).

CO2i= Annual CO2mass emissions that would result from the combustion or oxidation of fractionated NGLs delivered to all customers as calculated in paragraph (a)(1) or

(a)(2) of this section (metric tons).

CO2m= Annual CO2mass emissions that would result from the combustion or oxidation of fractionated NGLs received from other fractionators and calculated in paragraph (c)(1) of this section (metric tons).

Sec. 98.404 Monitoring and QA/QC requirements.

(a) Determination of quantity.

(1) NGL fractionators and LDCs shall determine the quantity of NGLs and natural gas using methods in common use in the industry for billing purposes as audited under existing Sarbanes Oxley regulationn.

(i) Where an appropriate standard method published by a consensus- based standards organization exists, such a method shall be used.

Consensus-based standards organizations include, but are not limited to, the following: ASTM International, the American National Standards

Institute (ANSI), the American Gas Association (AGA), the American

Society of Mechanical Engineers (ASME), the American Petroleum

Institute (API), and the North American Energy Standards Board (NAESB).

(ii) Where no appropriate standard method developed by a consensus- based standards organization exists, industry standard practices shall be followed.

(2) NGL fractionators and LDCs shall base the minimum frequency of the product quantity measurements, to be summed to the annual quantity reported, on the reporter's standard practices for commercial operations.

(i) For NGL fractionators the minimum frequency of measurements shall be the measurements taken at custody transfers summed to the annual reportable volume.

(ii) For natural gas the minimum frequency of measurement shall be based on the LDC's standard measurement schedules used for billing purposes and summed to the annual reportable volume.

(3) NGL fractionators shall use measurement for NGLs at custody tranfer meters or at such meters that are used to determine the NGL product slate delivered from the fractionation facility.

(4) If a NGL fractionator supplies a product not listed in Table

NN-1 of this subpart that is a mixture or blend of two or more products listed in Tables NN-1 and NN-2 of this subpart, the NGL fractionator shall report the quantities of the constituents of the mixtures or blends separately.

(5) For an LDC using Equation NN-1 or NN-2 of this subpart, the point(s) of measurement for the natural gas volume supplied shall be the LDC city gate meter(s).

(i) If the LDC makes its own quantity measurements according to established business practices, its own measurements shall be used.

(ii) If the LDC does not make its own quantity measurements according to established business practices, it shall use its delivering pipeline invoiced measurements for natural gas deliveries to the LDC city gate, used in determining daily system sendout.

(6) An LDC using Equation NN-3 of this subpart shall measure natural gas at the custody transfer meters.

(7) An LDC using Equation NN-4 of this subpart shall measure natural gas at the customer meters. The reporter shall consider the volume delivered through a single particluar meter at a single particular location as the volume delivered to an individual end-user.

(8) An LDC using Equation NN-5 of this subpart shall measure natural gas as follows:

Page 56501

(i) Fuel1shall be measured at the on-system storage injection meters and/or at the meters measuring natural gas to be liquefied.

(ii) Fuel2shall be measured at the meters used for measuring on-system storage withdrawals and/or LNG vaporization injection. If Fuel2is from a source other than storage, the appropriate meter shall be used to measure the quantity.

(9) An LDC shall measure all natural gas under the following standard industry temperature and pressure conditions: Cubic foot of gas at a temperature of 60 degrees Fahrenheit and at an absolute pressure of fourteen and seventy-three hundredths (14.73) pounds per square inch.

(b) Determination of higher heating values (HHV).

(1) When a reporter uses the default HHV provided in this section to calculate Equation NN-1 of this subpart, the appropriate value shall be taken from Table NN-1 of this subpart.

(2) When a reporter uses a reporter-specific HHV to calculate

Equation NN-1 of this subpart, an appropriate standard test published by a consensus-based standards organization shall be used. Consensus- based standards organizations include, but are not limited to, the following: AGA and GPA.

(i) If an LDC makes its own HHV measurements according to established business practices, then its own measurements shall be used.

(ii) If an LDC does not make its own measurements according to established business practices, it shall use its delivering pipeline measurements.

(1) When a reporter used the default EF provided in this section to calculate Equation NN-1 of this subpart, the appropriate value shall be taken from Table NN-1 of this subpart.

(2) When a reporter used the default EF provided in this section to calculate Equation NN-2, NN-3, NN-4, NN-5, or NN-7 of this subpart, the appropriate value shall be taken from Table NN-2 of this subpart.

(3) When a reporter uses a reporter-specific EF, the reporter shall use an appropriate standard method published by a consensus-based standards organization to conduct compositional analysis necessary to determine reporter-specific CO2emission factors. Consensus- based standards organizations include, but are not limited to, the following: AGA and GPA.

(d) Equipment Calibration.

(1) Equipment used to measure quantities in Equations NN-1, NN-2, and NN-5 of this subpart shall be calibrated prior to its first use for reporting under this subpart, using a suitable standard method published by a consensus based standards organization or according to the equipment manufacturer's directions.

(2) Equipment used to measure quantities in Equations NN-1, NN-2, and NN-5 of this subpart shall be recalibrated at the frequency specified by the standard method used or by the manufacturer's directions.

Sec. 98.405 Procedures for estimating missing data.

(a) Whenever a quality-assured value of the quantity of natural gas liquids or natural gas supplied during any period is unavailable (e.g., if a flow meter malfunctions), a substitute data value for the missing quantity measurement must be used in the calculations according to paragraphs (b) and (c) of this section.

(b) Determination of quantity.

(1) NGL fractionators shall substitute meter records provided by pipeline(s) for all pipeline receipts of NGLs; by manifests for deliveries made to trucks or rail cars; or metered quantities accepted by the entities purchasing the output from the fractionator whether by pipeline or by truck or rail car. In cases where the metered data from the receiving pipeline(s) or purchasing entities are not available, fractionators may substitute estimates based on contract quantities required to be delivered under purchase or delivery contracts with other parties.

(2) LDCs shall either substitute their delivering pipeline metered deliveries at the city gate or substitute nominations and scheduled delivery quantities for the period when metered values of actual deliveries are not available.

(1) Whenever an LDC that makes its own HHV measurements according to established business practices cannot follow the quality assurance procedures for developing a reporter-specific HHV, as specified in

Sec. 98.404, during any period for any reason, the reporter shall use either its delivering pipeline measurements or the default HHV provided in Table NN-1 of this part for that period.

(2) Whenever an LDC that does not make its own HHV measurements according to established business practices or an NGL fractionator cannot follow the quality assurance procedures for developing a reporter-specific HHV, as specified in Sec. 98.404, during any period for any reason, the reporter shall use the default HHV provided in

Table NN-1 of this part for that period.

(3) Whenever a NGL fractionator cannot follow the quality assurance procedures for developing a reporter-specific HHV, as specified in

Sec. 98.404, during any period for any reason, the NGL fractionator shall use the default HHV provided in Table NN-1 of this part for that period.

(4) Whenever a reporter cannot follow the quality assurance procedures for developing a reporter-specific EF, as specified in Sec. 98.404, during any period for any reason, the reporter shall use the default EF provided in Sec. 98.408 for that period.

Sec. 98.406 Data reporting requirements.

(a) In addition to the information required by Sec. 98.3(c), the annual report for each NGL fractionator covered by this rule shall contain the following information.

(1) Annual quantity (in barrels) of each NGL product supplied to downstream facilities in the following product categories: ethane, propane, normal butane, isobutane, and pentanes plus.

(2) Annual quantity (in barrels) of each NGL product received from other NGL fractionators in the following product categories: ethane, propane, normal butane, isobutane, and pentanes plus.

(3) Annual volumes in Mscf of natural gas received for processing.

(4) Annual quantity (in barrels) of y-grade, bulk NGLs received from others for fractionation.

(5) Annual quantity (in barrels) of propane that the NGL fractionator odorizes at the facility and delivers to others.

(6) Annual CO2emissions (metric tons) that would result from the complete combustion or oxidation of the quantities in paragraphs (b)(1) and (b)(2) of this section, calculated in accordance with Sec. 98.403(a) and (c)(1).

(7) Annual CO2mass emissions (metric tons) that would result from the combustion or oxidation of fractionated NGLs supplied less the quantity received by other fractionators, calculated in accordance with Sec. 98.403(c)(2).

(8) The specific industry standard used to measure each quantity reported in paragraph (a)(1) of this section.

(9) If the LNG fractionator developed reporter-specific EFs or

HHVs, report the following:

(i) The specific industry standard(s) used to develop reporter- specific higher heating value(s) and/or emission factor(s), pursuant to

Sec. 98.404(b)(2) and (c)(3).

(ii) The developed HHV(s).

(iii) The developed EF(s).

Page 56502

(b) In addition to the information required by Sec. 98.3(c), the annual report for each LDC shall contain the following information.

(1) Annual volume in Mscf of natural gas received by the LDC at its city gate stations for redelivery on the LDC's distribution system, including for use by the LDC.

(2) Annual volume in Mscf of natural gas placed into storage.

(3) Annual volume in Mscf of vaporized liquefied natural gas (LNG) produced at on-system vaporization facilities for delivery on the distribution system that is not accounted for in paragraph (b)(1) of this section.

(4) Annual volume in Mscf of natural gas withdrawn from on-system storage (that is not delivered to the city gate) for delivery on the distribution system.

(5) Annual volume in Mscf of natural gas delivered directly to LDC systems from producers or natural gas processing plants from local production.

(6) Annual volume in Mscf of natural gas delivered to downstream gas transmission pipelines and other local distribution companies.

(7) Annual volume in Mscf of natural gas delivered by LDC to each meter registering supply equal to or greater than 460,000 Mcsf during the calendar year.

(8) The total annual CO2mass emissions (metric tons) associated with the volumes in paragraphs (b)(1) through (b)(7) of this section, calculated in accordance with Sec. 98.403(a) and (b)(1) through (b)(3).

(9) Annual CO2emissions (metric tons) that would result from the complete combustion or oxidation of the annual supply of natural gas to end-users registering less than 460,000 Mcsf, calculated in accordance with Sec. 98.403(b)(4).

(10) The specific industry standard used to develop the volume reported in paragraph (b)(1) of this section.

(11) If the LDC developed reporter-specific EFs or HHVs, report the following:

(i) The specific industry standard(s) used to develop reporter- specific higher heating value(s) and/or emission factor(s), pursuant to

Sec. 98.404 (b)(2) and (c)(3).

(ii) The developed HHV(s).

(iii) The developed EF(s).

(12) The customer name, address, and meter number of each meter reading used to report in paragraph (b)(7) of this section.

(i) If known, report the EIA identification number of each LDC customer.

(ii) [Reserved]

(13) The annual volume in Mscf of natural gas delivered by the local distribution company to each of the following end-use categories.

For definitions of these categories, refer to EIA Form 176 (Annual

Report of Natural Gas and Supplemental Gas Supply & Disposition) and

Instructions.

(i) Residential consumers.

(ii) Commercial consumers.

(iii) Industrial consumers.

(iv) Electricity generating facilities.

(c) Each reporter shall report the number of days in the reporting year for which substitute data procedures were used for the following purpose:

(1) To measure quantity.

(2) To develop HHV(s).

(3) To develop EF(s).

Sec. 98.407 Records that must be retained.

In addition to the information required by Sec. 98.3(g), each annual report must contain the following information:

(a) Records of all daily meter readings and documentation to support volumes of natural gas and NGLs that are reported under this part.

(b) Records documenting any estimates of missing metered data and showing the calculations of the values used for the missing data.

(d) Records related to the large end-users identified in Sec. 98.406(b)(6).

(e) Records relating to measured Btu content or carbon content showing specific industry standards used to develop reporter-specific higher heating values and emission factors.

(f) Records of such audits as required by Sarbanes Oxley regulations on the accuracy of measurements of volumes of natural gas and NGLs delivered to customers or on behalf of customers.

Sec. 98.408 Definitions.

All terms used in this subpart have the same meaning given in the

Clean Air Act and subpart A of this part.

Table NN-1 to Subpart NN of Part 98--Default Factors for Calculation

Methodology 1 of This Subpart

Default CO2

Default high heating

emission

Fuel

value factor

factor (kg

CO2/MMBtu)

Natural Gas........................ 1.027 MMBtu/Mscf......

53.02

Propane............................ 3.836 MMBtu/bbl.......

63.02

Normal butane...................... 4.326 MMBtu/bbl.......

64.93

Ethane............................. 3.082 MMBtu/bbl.......

59.58

Isobutane.......................... 3.974 MMBtu/bbl.......

65.08

Pentanes plus...................... 4.620 MMBtu/bbl.......

66.90

Table NN-2 to Subpart NN of Part 98--Lookup Default Values for

Calculation Methodology 2 of This Subpart

Default CO2 emission

Fuel

Unit

value (MT

CO2/Unit)

Natural Gas........................ Mscf..................

0.054452

Propane............................ Barrel................

0.241745

Normal butane...................... Barrel................

0.280887

Ethane............................. Barrel................

0.183626

Isobutane.......................... Barrel................

0.258628

Page 56503

Pentanes plus...................... Barrel................

0.309078

Subpart OO--Suppliers of Industrial Greenhouse Gases

Sec. 98.410 Definition of the source category.

(a) The industrial gas supplier source category consists of any facility that produces a fluorinated GHG or nitrous oxide, any bulk importer of fluorinated GHGs or nitrous oxide, and any bulk exporter of fluorinated GHGs or nitrous oxide.

(b) To produce a fluorinated GHG means to manufacture a fluorinated

GHG from any raw material or feedstock chemical. Producing a fluorinated GHG includes the manufacture of a fluorinated GHG for use in a process that will result in its transformation either at or outside of the production facility. Producing a fluorinated GHG also includes the creation of a fluorinated GHG (with the exception of HFC- 23) that is captured and shipped off site for any reason, including destruction. Producing a fluorinated GHG does not include the reuse or recycling of a fluorinated GHG, the creation of HFC-23 during the production of HCFC-22, or the creation of by-products that are released or destroyed at the production facility.

Producing nitrous oxide does not include the reuse or recycling of nitrous oxide or the creation of by-products that are released or destroyed at the production facility.

Sec. 98.411 Reporting threshold.

Any supplier of industrial greenhouse gases who meets the requirements of Sec. 98.2(a)(4) must report GHG emissions.

Sec. 98.412 GHGs to report.

You must report the GHG emissions that would result from the release of the nitrous oxide and each fluorinated GHG that you produce, import, export, transform, or destroy during the calendar year.

Sec. 98.413 Calculating GHG emissions.

(a) Calculate the total mass of each fluorinated GHG or nitrous oxide produced annually, except for amounts that are captured solely to be shipped off site for destruction, by using Equation OO-1 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.171

P = Mass of fluorinated GHG or nitrous oxide produced annually.

Pp= Mass of fluorinated GHG or nitrous oxide produced over the period ``p''.

(b) Calculate the total mass of each fluorinated GHG or nitrous oxide produced over the period ``p'' by using Equation OO-2 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.172

Where:

Pp= Mass of fluorinated GHG or nitrous oxide produced over the period ``p'' (metric tons).

Op= Mass of fluorinated GHG or nitrous oxide that is measured coming out of the production process over the period p

(metric tons).

Up= Mass of used fluorinated GHG or nitrous oxide that is added to the production process upstream of the output measurement over the period ``p'' (metric tons).

(c) Calculate the total mass of each fluorinated GHG or nitrous oxide transformed by using Equation OO-3 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.173

Where:

T = Mass of fluorinated GHG or nitrous oxide transformed annually

(metric tons).

FT= Mass of fluorinated GHG fed into the transformation process annually (metric tons).

ET= The fraction of the fluorinated GHG or nitrous oxide fed into the transformation process that is transformed in the process

(metric tons).

(d) Calculate the total mass of each fluorinated GHG destroyed by using Equation OO-4 of this section:

GRAPHIC

TIFF OMITTED TR30OC09.174

Where:

D = Mass of fluorinated GHG destroyed annually (metric tons).

FD= Mass of fluorinated GHG fed into the destruction device annually (metric tons).

DE = Destruction efficiency of the destruction device (fraction).

Sec. 98.414 Monitoring and QA/QC requirements.

(a) The mass of fluorinated GHGs or nitrous oxide coming out of the production process shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better.

(b) The mass of any used fluorinated GHGs or used nitrous oxide added back into the production process upstream of the output measurement in paragraph (a) of this section shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better. If the mass in paragraph (a) of this section is measured by weighing containers that include returned heels as well as newly produced fluorinated GHGs, the returned heels shall be considered used fluorinated GHGs for purposes of this paragraph (b) of this section and Sec. 98.413(b).

(c) The mass of fluorinated GHGs or nitrous oxide fed into the transformation process shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better.

(d) The fraction of the fluorinated GHGs or nitrous oxide fed into the transformation process that is actually transformed shall be estimated considering yield calculations or quantities of unreacted fluorinated GHGs or nitrous oxide permanently removed from the process and recovered, destroyed, or emitted.

(e) The mass of fluorinated GHG or nitrous oxide sent to another facility for transformation shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better.

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(f) The mass of fluorinated GHG sent to another facility for destruction shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than the fluorinated GHG, the concentration of the fluorinated GHG shall be estimated considering current or previous representative concentration measurements and other relevant process information. This concentration

(mass fraction) shall be multiplied by the mass measurement to obtain the mass of the fluorinated GHG sent to another facility for destruction.

(g) You must estimate the share of the mass of fluorinated GHGs in paragraph (f) of this section that is comprised of fluorinated GHGs that are not included in the mass produced in Sec. 98.413(a) because they are removed from the production process as by-products or other wastes.

(h) The mass of fluorinated GHGs fed into the destruction device shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than the fluorinated GHG being destroyed, the concentrations of fluorinated GHG being destroyed shall be estimated considering current or previous representative concentration measurements and other relevant process information. This concentration (mass fraction) shall be multiplied by the mass measurement to obtain the mass of the fluorinated GHG destroyed.

(i) Very small quantities of fluorinated GHGs that are difficult to measure because they are entrained in other media such as destroyed filters and destroyed sample containers are exempt from paragraphs (f) and (h) of this section.

(j) You must estimate the share of the mass of fluorinated GHGs in paragraph (h) of this section that is comprised of fluorinated GHGs that are not included in the mass produced in Sec. 98.413(a) because they are removed from the production process as by-products or other wastes.

(k) For purposes of Equation OO-4 of this subpart, the destruction efficiency can be equated to the destruction efficiency determined during a previous performance test of the destruction device or, if no performance test has been done, the destruction efficiency provided by the manufacturer of the destruction device.

(l) In their estimates of the mass of fluorinated GHGs destroyed, fluorinated GHG production facilities that destroy fluorinated GHGs shall account for any temporary reductions in the destruction efficiency that result from any startups, shutdowns, or malfunctions of the destruction device, including departures from the operating conditions defined in state or local permitting requirements and/or oxidizer manufacturer specifications.

(m) Calibrate all flow meters, weigh scales, and combinations of volumetric and density measures that are used to measure or calculate quantities that are to be reported under this subpart prior to the first year for which GHG emissions are reported under this part.

Calibrations performed prior to the effective date of this rule satisfy this requirement. Recalibrate all flow meters, weigh scales, and combinations of volumetric and density measures at the minimum frequency specified by the manufacturer. Use NIST-traceable standards and suitable methods published by a consensus standards organization

(e.g., ASTM, ASME, ISO, or others).

Sec. 98.415 Procedures for estimating missing data.

(a) A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality- assured value of a required parameter is unavailable (e.g., if a meter malfunctions), a substitute data value for the missing parameter shall be used in the calculations, according to paragraph (b) of this section.

(b) For each missing value of the mass produced, fed into the production process (for used material being reclaimed), fed into the transformation process, fed into destruction devices, sent to another facility for transformation, or sent to another facility for destruction, the substitute value of that parameter shall be a secondary mass measurement where such a measurement is available. For example, if the mass produced is usually measured with a flowmeter at the inlet to the day tank and that flowmeter fails to meet an accuracy or precision test, malfunctions, or is rendered inoperable, then the mass produced may be estimated by calculating the change in volume in the day tank and multiplying it by the density of the product. Where a secondary mass measurement is not available, the substitute value of the parameter shall be an estimate based on a related parameter. For example, if a flowmeter measuring the mass fed into a destruction device is rendered inoperable, then the mass fed into the destruction device may be estimated using the production rate and the previously observed relationship between the production rate and the mass flow rate into the destruction device.

Sec. 98.416 Data reporting requirements.

In addition to the information required by Sec. 98.3(c), each annual report must contain the following information:

(a) Each fluorinated GHG or nitrous oxide production facility shall report the following information:

(1) Mass in metric tons of each fluorinated GHG or nitrous oxide produced at that facility by process, except for amounts that are captured solely to be shipped off site for destruction.

(2) Mass in metric tons of each fluorinated GHG or nitrous oxide transformed at that facility, by process.

(3) Mass in metric tons of each fluorinated GHG destroyed at that facility, except fluorinated GHGs not included in the calculation of mass produced in Sec. 98.413(a) because they are removed from the production process as by-products or other wastes. Quantities to be reported under this paragraph (a)(3) of this section could include, for example, quantities that are returned to the facility for reclamation but are found to be irretrievably contaminated and are therefore destroyed.

(4) Mass in metric tons of each fluorinated GHG that is destroyed at that facility except GHGs not included in the calculation of mass produced in Sec. 98.413(a) because they are removed from the production process as byproducts or other wastes.

(5) Total mass in metric tons of each fluorinated GHG or nitrous oxide sent to another facility for transformation.

(6) Total mass in metric tons of each fluorinated GHG sent to another facility for destruction, except fluorinated GHGs that are not included in the mass produced in Sec. 98.413(a) because they are removed from the production process as by-products or other wastes.

Quantities to be reported under this paragraph (a)(6) could include, for example, fluorinated GHGs that are returned to the facility for reclamation but are found to be irretrievably contaminated and are therefore sent to another facility for destruction.

(7) Total mass in metric tons of each fluorinated GHG that is sent to another facility for destruction and that is not included in the mass produced in Sec. 98.413(a) because it is removed from

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the production process as a byproduct or other waste.

(8) Total mass in metric tons of each reactant fed into the F-GHG or nitrous oxide production process, by process.

(9) Total mass in metric tons of the reactants, by-products, and other wastes permanently removed from the F-GHG or nitrous oxide production process, by process.

(10) For transformation processes that do not produce an F-GHG or nitrous oxide, mass in metric tons of any fluorinated GHG or nitrous oxide fed into the transformation process, by process.

(11) Mass in metric tons of each fluorinated GHG fed into the destruction device.

(12) Mass in metric tons of each fluorinated GHG or nitrous oxide that is measured coming out of the production process, by process.

(13) Mass in metric tons of each used fluorinated GHGs or nitrous oxide added back into the production process (e.g., for reclamation), including returned heels in containers that are weighed to measure the mass in Sec. 98.414(a), by process.

(14) Names and addresses of facilities to which any nitrous oxide or fluorinated GHGs were sent for transformation, and the quantities

(metric tons) of nitrous oxide and of each fluorinated GHG that were sent to each for transformation.

(15) Names and addresses of facilities to which any fluorinated

GHGs were sent for destruction, and the quantities (metric tons) of nitrous oxide and of each fluorinated GHG that were sent to each for destruction.

(16) Where missing data have been estimated pursuant to Sec. 98.415, the reason the data were missing, the length of time the data were missing, the method used to estimate the missing data, and the estimates of those data.

(b) A fluorinated GHG production facility or importer that destroys fluorinated GHGs shall submit a one-time report containing the following information:

(1) Destruction efficiency (DE) of each destruction unit.

(2) Methods used to determine the destruction efficiency.

(3) Methods used to record the mass of fluorinated GHG destroyed.

(4) Chemical identity of the fluorinated GHG(s) used in the performance test conducted to determine DE.

(5) Name of all applicable federal or state regulations that may apply to the destruction process.

(6) If any process changes affect unit destruction efficiency or the methods used to record mass of fluorinated GHG destroyed, then a revised report must be submitted to reflect the changes. The revised report must be submitted to EPA within 60 days of the change.

(c) A bulk importer of fluorinated GHGs or nitrous oxide shall submit an annual report that summarizes their imports at the corporate level, except for shipments including less than 250 metric tons of

CO2e, transshipments, and heels that meet the conditions set forth at Sec. 98.417(e). The report shall contain the following information for each import:

(1) Total mass in metric tons of nitrous oxide and each fluorinated

GHG imported in bulk.

(2) Total mass in metric tons of nitrous oxide and each fluorinated

GHG imported in bulk and sold or transferred to persons other than the importer for use in processes resulting in the transformation or destruction of the chemical.

(3) Date on which the fluorinated GHGs or nitrous oxide were imported.

(4) Port of entry through which the fluorinated GHGs or nitrous oxide passed.

(5) Country from which the imported fluorinated GHGs or nitrous oxide were imported.

(6) Commodity code of the fluorinated GHGs or nitrous oxide shipped.

(7) Importer number for the shipment.

(8) Total mass in metric tons of each fluorinated GHG destroyed by the importer.

(9) If applicable, the names and addresses of the persons and facilities to which the nitrous oxide or fluorinated GHGs were sold or transferred for transformation, and the quantities (metric tons) of nitrous oxide and of each fluorinated GHG that were sold or transferred to each facility for transformation.

(10) If applicable, the names and addresses of the persons and facilities to which the nitrous oxide or fluorinated GHGs were sold or transferred for destruction, and the quantities (metric tons) of nitrous oxide and of each fluorinated GHG that were sold or transferred to each facility for destruction.

(d) A bulk exporter of fluorinated GHGs or nitrous oxide shall submit an annual report that summarizes their exports at the corporate level, except for shipments including less than 250 metric tons of

CO2e, transshipments, and heels. The report shall contain the following information for each export:

(1) Total mass in metric tons of nitrous oxide and each fluorinated

GHG exported in bulk.

(2) Names and addresses of the exporter and the recipient of the exports.

(3) Exporter's Employee Identification Number.

(4) Commodity code of the fluorinated GHGs and nitrous oxide shipped.

(5) Date on which, and the port from which, fluorinated GHGs and nitrous oxide were exported from the United States or its territories.

(6) Country to which the fluorinated GHGs or nitrous oxide were exported.

(e) By April 1, 2011, a fluorinated GHG production facility shall submit a one-time report describing the following information:

(1) The method(s) by which the producer in practice measures the mass of fluorinated GHGs produced, including the instrumentation used

(Coriolis flowmeter, other flowmeter, weigh scale, etc.) and its accuracy and precision.

(2) The method(s) by which the producer in practice estimates the mass of fluorinated GHGs fed into the transformation process, including the instrumentation used (Coriolis flowmeter, other flowmeter, weigh scale, etc.) and its accuracy and precision.

(3) The method(s) by which the producer in practice estimates the fraction of fluorinated GHGs fed into the transformation process that is actually transformed, and the estimated precision and accuracy of this estimate.

(4) The method(s) by which the producer in practice estimates the masses of fluorinated GHGs fed into the destruction device, including the method(s) used to estimate the concentration of the fluorinated

GHGs in the destroyed material, and the estimated precision and accuracy of this estimate.

(5) The estimated percent efficiency of each production process for the fluorinated GHG produced.

Sec. 98.417 Records that must be retained.

(a) In addition to the data required by Sec. 98.3(g), the fluorinated GHG production facility shall retain the following records:

(1) Dated records of the data used to estimate the data reported under Sec. 98.416.

(2) Records documenting the initial and periodic calibration of the gas chromatographs, weigh scales, flowmeters, and volumetric and density measures used to measure the quantities reported under this subpart, including the industry standards or manufacturer directions used for calibration pursuant to Sec. 98.414(j) and (k).

(b) In addition to the data required by paragraph (a) of this section, the

Page 56506

fluorinated GHG production facility that destroys fluorinated GHGs shall keep records of test reports and other information documenting the facility's one-time destruction efficiency report and annual destruction device outlet reports in Sec. 98.416(b) and (e).

(c) In addition to the data required by Sec. 98.3(g), the bulk importer shall retain the following records substantiating each of the imports that they report:

(1) A copy of the bill of lading for the import.

(2) The invoice for the import.

(3) The U.S. Customs entry form.

(d) In addition to the data required by Sec. 98.3(g), the bulk exporter shall retain the following records substantiating each of the exports that they report:

(1) A copy of the bill of lading for the export and

(2) The invoice for the import.

(e) Every person who imports a container with a heel that is not reported under Sec. 98.416(c) shall keep records of the amount brought into the United States that document that the residual amount in each shipment is less than 10 percent of the volume of the container and will:

(1) Remain in the container and be included in a future shipment.

(2) Be recovered and transformed.

(3) Be recovered and destroyed.

(4) Be recovered and included in a future shipment.

Sec. 98.418 Definitions.

All terms used in this subpart have the same meaning given in the

Clean Air Act and subpart A of this part.

Subpart PP--Suppliers of Carbon Dioxide

Sec. 98.420 Definition of the source category.

(a) The carbon dioxide (CO2) supplier source category consists of the following:

(1) Facilities with production process units that capture a

CO2stream for purposes of supplying CO2for commercial applications or that capture and maintain custody of a

CO2stream in order to sequester or otherwise inject it underground. Capture refers to the initial separation and removal of

CO2from a manufacturing process or any other process.

(2) Facilities with CO2production wells that extract or produce a CO2stream for purposes of supplying

CO2for commercial applications or that extract and maintain custody of a CO2stream in order to sequester or otherwise inject it underground.

(3) Importers or exporters of bulk CO2.

(b) This source category is focused on upstream supply. It does not cover:

(1) Storage of CO2above ground or in geologic formations.

(2) Use of CO2in enhanced oil and gas recovery.

(3) Transportation or distribution of CO2.

(4) Purification, compression, or processing of CO2.

(5) On-site use of CO2captured on site.

Sec. 98.421 Reporting threshold.

Any supplier of CO2who meets the requirements of Sec. 98.2(a)(4) of subpart A of this part must report the mass of

CO2captured, extracted, imported, or exported.

Sec. 98.422 GHGs to report.

(a) Mass of CO2captured from each production process unit.

(b) Mass of CO2extracted from each CO2 production wells.

(d) Mass of CO2exported.

Sec. 98.423 Calculating CO2supply.

(a) Calculate the annual mass of CO2captured, extracted, imported, or exported through each flow meter in accordance with the procedures specified in either paragraph (a)(1) or (a)(2) of this section. If multiple flow meters are used, you shall calculate the annual mass of CO2for all flow meters according to the procedures specified in paragraph (a)(3) of this section.

(1) For each mass flow meter, you shall calculate quarterly the mass of CO2in a CO2stream in metric tons, prior to any subsequent purification, processing, or compressing, by multiplying the mass flow by the composition data, according to

Equation PP-1 of this section. Mass flow and composition data measurements shall be made in accordance with Sec. 98.424 of this subpart.

GRAPHIC

TIFF OMITTED TR30OC09.175

Where:

CO2,u= Annual mass of CO2(metric tons) through flow meter u.

CCO2,p,u= Quarterly CO2 concentration measurement in flow for flow meter u in quarter p (wt.

%CO2).

Qp,u= Quarterly mass flow rate measurement for flow meter u in quarter p (metric tons). p = Quarter of the year. u = Flow meter.

(2) For each volumetric flow meter, you shall calculate quarterly the mass of CO2in a CO2stream in metric tons, prior to any subsequent purification, processing, or compressing, by multiplying the volumetric flow by the concentration and density data, according to Equation PP-2 of this section. Volumetric flow, concentration and density data measurements shall be made in accordance with Sec. 98.424 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.176

Where:

CO2,u= Annual mass of CO2(metric tons) through flow meter u.

CCO2,p= Quarterly CO2 concentration measurement in flow for flow meter u in quarter p (wt.

% CO2).

Qp= Quarterly volumetric flow rate measurement for flow meter u in quarter p (standard cubic meters).

Dp= Quarterly CO2stream density measurement for flow meter u in quarter p (metric tons per standard cubic meter). p = Quarter of the year. u = Flow meter.

(3) To aggregate data, sum the mass of CO2for all flow meters in accordance with Equation PP-3 of this section.

Page 56507

GRAPHIC

TIFF OMITTED TR30OC09.177

Where:

CO2= Annual mass of CO2(metric tons) through all flow meters.

CO2,u= Annual mass of CO2(metric tons) through flow meter u. u = Flow meter.

(b) Importers or exporters that import or export CO2in containers shall calculate the total mass of CO2imported or exported in metric tons, prior to any subsequent purification, processing, or compressing, based on summing the mass in each

CO2container using weigh bills, scales, or load cells according to Equation PP-4 of this section.

GRAPHIC

TIFF OMITTED TR30OC09.178

Where:

CO2= Annual mass of CO2(metric tons).

Q = Annual mass in all CO2containers imported or exported during the reporting year (metric tons).

Sec. 98.424 Monitoring and QA/QC requirements.

(a) Determination of quantity.

(1) Reporters that have a mass flow meter or volumetric flow meter installed to measure the flow of a CO2stream shall base calculations in Sec. 98.423 of this subpart on the installed mass flow or volumetric flow meters.

(2) Reporters that do not have a mass flow meter or volumetric flow meter installed to measure the flow of the CO2stream shall base calculations in Sec. 98.423 of this subpart on the flow of gas transferred off site using a mass flow meter or a volumetric flow meter located at the point of off-site transfer.

(3) Importers or exporters that import or export CO2in containers shall measure the mass in each CO2container using weigh bills, scales, or load cells and sum the mass in all containers imported or exported during the reporting year.

(4) All flow meters, scales, and load cells used to measure quantities that are reported in Sec. 98.423 of this subpart shall be operated and calibrated according to the following procedure:

(i) You shall use an appropriate standard method published by a consensus-based standards organization if such a method exists.

Consensus-based standards organizations include, but are not limited to, the following: ASTM International, the American National Standards

Institute (ANSI), the American Gas Association (AGA), the American

Society of Mechanical Engineers (ASME), the American Petroleum

Institute (API), and the North American Energy Standards Board (NAESB).

(ii) Where no appropriate standard method developed by a consensus- based standards organization exists, you shall follow industry standard practices.

(iii) You must ensure that any flow meter calibrations performed are NIST traceable.

(5) Reporters using Equation PP-2 of this subpart shall measure the density of the CO2stream on a quarterly basis in order to calculate the mass of the CO2stream according to the following procedure:

(i) You shall use an appropriate standard method published by a consensus-based standards organization to measure density if such a method exists. Consensus-based standards organizations include, but are not limited to, the following: ASTM International, the American

National Standards Institute (ANSI), the American Gas Association

(AGA), the American Society of Mechanical Engineers (ASME), the

American Petroleum Institute (API), and the North American Energy

Standards Board (NAESB).

(ii) Where no appropriate standard method developed by a consensus- based standards organization exists, you shall follow industry standard practices.

(b) Determination of concentration.

(1) Reporters using Equation PP-1 or PP-2 of this subpart shall sample the CO2stream on a quarterly basis to determine the composition of the CO2stream.

(2) Methods to measure the composition of the CO2stream must conform to applicable chemical analytical standards. Acceptable methods include U.S. Food and Drug Administration food-grade specifications for CO2(see 21 CFR 184.1250) and ASTM standard E1747-95 (Reapproved 2005) Standard Guide for Purity of Carbon

Dioxide Used in Supercritical Fluid Applications (incorporated by reference, see Sec. 98.7 of subpart A of this part).

Sec. 98.425 Procedures for estimating missing data.

(a) Whenever the quality assurance procedures in Sec. 98.424(a) of this subpart cannot be followed to measure quarterly mass flow or volumetric flow of CO2, the most appropriate of the following missing data procedures shall be followed:

(1) A quarterly CO2mass flow or volumetric flow value that is missing may be substituted with a quarterly value measured during another quarter of the current reporting year.

(2) A quarterly CO2mass flow or volumetric flow value that is missing may be substituted with a quarterly value measured during the same quarter from the past reporting year.

(3) If a mass or volumetric flow meter is installed to measure the

CO2stream, you may substitute data from a mass or volumetric flow meter measuring the CO2stream transferred for any period during which the installed meter is inoperable.

(4) The mass or volumetric flow used for purposes of product tracking and billing according to the reporter's established procedures may be substituted for any period during which measurement equipment is inoperable.

(b) Whenever the quality assurance procedures in Sec. 98.424(b) of this subpart cannot be followed to determine concentration of the

CO2stream, the most appropriate of the following missing data procudures shall be followed:

(1) A quarterly concentration value that is missing may be substituted with a quarterly value measured during another quarter of the current reporting year.

(2) A quarterly concentration value that is missing may be substituted with a quarterly value measured during the same quarter from the previous reporting year.

(3) The concentration used for purposes of product tracking and billing according to the reporter's established procedures may be substituted for any quarterly value.

(c) Missing data on density of the CO2stream shall be substituted with quarterly or annual average values from the previous calendar year.

Sec. 98.426 Data reporting requirements.

In addition to the information required by Sec. 98.3(c) of subpart

A of this part, the annual report shall contain the following information, as applicable:

(a) If you use Equation PP-1 of this subpart, report the following information for each mass flow meter:

(1) Annual mass in metric tons of CO2.

(2) Quarterly mass flow of CO2.

(3) Quarterly concentration of the CO2stream.

(4) The standard used to measure CO2concentration.

(b) If you use Equation PP-2 of this subpart, report the following information for each volumetric flow meter:

(1) Annual mass in metric tons of CO2.

(2) Quarterly volumetric flow of CO2.

(3) Quarterly concentration of the CO2stream.

(4) Quarterly density of the CO2stream.

Page 56508

(5) The method used to measure density.

(6) The standard used to measure CO2concentration.

CO2mass in metric tons from all flow meters.

(d) If you use Equation PP-4 of this subpart, report at the corporate level the annual mass of CO2in metric tons in all

CO2containers that are imported or exported.

(e) Each reporter shall report the following information:

(1) The type of equipment used to measure the total flow of the

CO2stream or the total mass in CO2containers.

(2) The standard used to operate and calibrate the equipment reported in (e)(1) of this section.

(3) The number of days in the reporting year for which substitute data procedures were used for the following purpose:

(i) To measure quantity.

(ii) To measure concentration.

(iii) To measure density.

(f) Report the aggregated annual quantity of CO2in metric tons that is transferred to each of the following end use applications, if known:

(1) Food and beverage.

(2) Industrial and municipal water/wastewater treatment.

(3) Metal fabrication, including welding and cutting.

(4) Greenhouse uses for plant growth.

(5) Fumigants (e.g., grain storage) and herbicides.

(6) Pulp and paper.

(7) Cleaning and solvent use.

(8) Fire fighting.

(9) Transportation and storage of explosives.

(10) Enhanced oil and natural gas recovery.

(11) Long-term storage (sequestration).

(12) Research and development.

(13) Other.

(g) Each production process unit that captures a CO2 stream for purposes of supplying CO2for commercial applications or in order to sequester or otherwise inject it underground when custody of the CO2is maintained shall report the percentage of that stream, if any, that is biomass-based during the reporting year.

Sec. 98.427 Records that must be retained.

In addition to the records required by Sec. 98.3(g) of subpart A of this part, you must retain the records specified in paragraphs (a) through (c) of this section, as applicable.

(a) The owner or operator of a facility containing production process units must retain quarterly records of captured or transferred

CO2streams and composition.

(b) The owner or operator of a CO2production well facility must maintain quarterly records of the mass flow or volumetric flow of the extracted or transferred CO2stream and concentration and density if volumetric flow meters are used.

(c) Importers or exporters of CO2must retain annual records of the mass flow, volumetric flow, and mass of CO2 imported or exported.

Sec. 98.428 Definitions.

All terms used in this subpart have the same meaning given in the

Clean Air Act and subpart A of this part.

PART 1033--[AMENDED] 0 21. The authority citation for part 1033 continues to read as follows:

Authority: 42 U.S.C. 7401-7671q.

Subpart C--[Amended] 0 22. Section 1033.205 is amended by revising paragraph (d)(8) to read as follows:

Sec. 1033.205 Applying for a certificate of conformity.

* * * * *

(d) * * *

(8)(i) All test data you obtained for each test engine or locomotive. As described in Sec. 1033.235, we may allow you to demonstrate compliance based on results from previous emission tests, development tests, or other testing information. Include data for NOx,

PM, HC, CO, and CO2.

(ii) Report measured CO2, N2O, and

CH4as described in Sec. 1033.235. Small manufacturers/ remanufacturers may omit reporting N2O and CH4.

* * * * * 0 23. Section 1033.235 is amended by adding paragraph (i) to read as follows:

Sec. 1033.235 Emission testing required for certification.

* * * * *

(i) Measure CO2with each test. Measure CH4 with each low-hour certification test using the procedures specified in 40 CFR part 1065 starting in the 2012 model year. Also measure

N2O with each low-hour certification test using the procedures specified in 40 CFR part 1065 for any engine family that depends on NOx aftertreatment to meet emission standards. Small manufacturers/remanufacturers may omit measurement of N2O and CH4. Use the same units and modal calculations as for your other results to report a single weighted value for

CO2, N2O, and CH4. Round the final values as follows:

(1) Round CO2to the nearest 1 g/bhp-hr.

(2) Round N2O to the nearest 0.001 g/bhp-hr.

(3) Round CH4to the nearest 0.001g/bhp-hr.

Subpart F--[Amended] 0 24. Section 1033.501 is amended by revising paragraph (a) introductory text to read as follows:

Sec. 1033.501 General provisions.

(a) Except as specified in this subpart, use the equipment and procedures for compression-ignition engines in 40 CFR part 1065 to determine whether your locomotives meet the duty-cycle emission standards in Sec. 1033.101. Use the applicable duty cycles specified in this subpart. Measure emissions of all the pollutants we regulate in

Sec. 1033.101 plus CO2. Measure N2O, and

CH4as described in Sec. 1033.235. The general test procedure is the procedure specified in 40 CFR part 1065 for steady- state discrete-mode cycles. However, if you use the optional ramped modal cycle in Sec. 1033.520, follow the procedures for ramped modal testing in 40 CFR part 1065. The following exceptions from the 1065 procedures apply:

* * * * *

Subpart J--[Amended] 0 25. Section 1033.905 is amended by adding the abbreviations

CH4and N2O in alphanumeric order to read as follows:

Sec. 1033.905 Symbols, acronyms, and abbreviations.

* * * * *

CH4methane.

* * * * *

N2O nitrous oxide.

* * * * *

PART 1039--[AMENDED] 0 26. The authority citation for part 1039 continues to read as follows:

Authority: 42 U.S.C. 7401-7671q.

Subpart C--[Amended] 0 27. Section 1039.205 is amended by revising paragraph (r) to read as follows:

Sec. 1039.205 What must I include in my application?

* * * * *

(r) Report test results as follows:

Continued on page 56509

From the Federal Register Online via GPO Access [wais.access.gpo.gov]

]

pp. 56509-56519

Mandatory Reporting of Greenhouse Gases

Continued from page 56508

Page 56509

procedures of subpart F of this part. We may ask you to send other information to confirm that your tests were valid under the requirements of this part and 40 CFR part 1065.

(2) Report measured CO2, N2O, and

CH4as described in Sec. 1039.235. Small-volume engine manufacturers may omit reporting N2O and CH4.

* * * * * 0 28. Section 1039.235 is amended by adding paragraph (g) to read as follows:

Sec. 1039.235 What emission testing must I perform for my application for a certificate of conformity?

* * * * *

(g) Measure CO2and CH4with each low-hour certification test using the procedures specified in 40 CFR part 1065 in the 2011 and 2012 model years, respectively. Also measure

N2O with each low-hour certification test using the procedures specified in 40 CFR part 1065 starting in the 2013 model year for any engine family that depends on NOx aftertreatment to meet emission standards. Small-volume engine manufacturers may omit measurement of N2O and CH4. These measurements are not required for NTE testing. Use the same units and modal calculations as for your other results to report a single weighted value for each constituent. Round the final values as follows:

(1) Round CO2to the nearest 1 g/kW-hr.

(2) Round N2O to the nearest 0.001 g/kW-hr.

(3) Round CH4to the nearest 0.001g/kW-hr.

Subpart F--[Amended] 0 29. Section 1039.501 is amended by revising paragraph (a) to read as follows:

Sec. 1039.501 How do I run a valid emission test?

(a) Use the equipment and procedures for compression-ignition engines in 40 CFR part 1065 to determine whether engines meet the duty- cycle emission standards in subpart B of this part. Measure the emissions of all the exhaust constituents subject to emissions standards as specified in 40 CFR part 1065. Measure CO2,

N2O, and CH4as described in Sec. 1039.235. Use the applicable duty cycles specified in Sec. Sec. 1039.505 and 1039.510.

* * * * *

Subpart I--[Amended] 0 30. Section 1039.805 is amended by adding the abbreviations

CH4and N2O in alphanumeric order to read as follows:

Sec. 1039.805 What symbols, acronyms, and abbreviations does this part use?

* * * * *

CH4methane.

* * * * *

N2O nitrous oxide.

* * * * *

PART 1042--[AMENDED] 0 31. The authority citation for part 1042 continues to read as follows:

Authority: 42 U.S.C. 7401-7671q.

Subpart C--[Amended] 0 32. Section 1042.205 is amended by revising paragraph (r) to read as follows:

Sec. 1042.205 Application requirements.

* * * * *

(r) Report test results as follows:

(1) Report all test results involving measurement of pollutants for which emission standards apply. Include test results from invalid tests or from any other tests, whether or not they were conducted according to the test procedures of subpart F of this part. We may ask you to send other information to confirm that your tests were valid under the requirements of this part and 40 CFR part 1065.

(2) Report measured CO2, N2O, and

CH4as described in Sec. 1042.235. Small-volume engine manufacturers may omit reporting N2O and CH4.

* * * * * 0 33. Section 1042.235 is amended by adding paragraph (g) to read as follows:

Sec. 1042.235 Emission testing required for a certificate of conformity.

* * * * *

(g) Measure CO2with each low-hour certification test using the procedures specified in 40 CFR part 1065 starting in the 2011 model year. Also measure CH4from Category 1 and Category 2 engines with each low-hour certification test using the procedures specified in 40 CFR part 1065 starting in the 2012 model year. Measure

N2O from Category 1 and Category 2 engines with each low- hour certification test using the procedures specified in 40 CFR part 1065 for any engine family that depends on NOx aftertreatment to meet emission standards. Small-volume engine manufacturers may omit measurement of N2O and CH4. These measurements are not required for NTE testing. Use the same units and modal calculations as for your other results to report a single weighted value for each constituent. Round the final values as follows:

(1) Round CO2to the nearest 1 g/kW-hr.

(2) Round N2O to the nearest 0.001 g/kW-hr.

(3) Round CH4to the nearest 0.001 g/kW-hr.

Subpart F--[Amended] 0 34. Section 1042.501 is amended by revising paragraph (a) to read as follows:

Sec. 1042.501 How do I run a valid emission test?

(a) Use the equipment and procedures for compression-ignition engines in 40 CFR part 1065 to determine whether Category 1 and

Category 2 engines meet the duty-cycle emission standards in Sec. 1042.101(a). Measure the emissions of all exhaust constituents subject to emissions standards as specified in 40 CFR part 1065. Measure

CO2, N2O, and CH4as described in

Sec. 1042.235. Use the applicable duty cycles specified in Sec. 1042.505.

* * * * *

Subpart J--[Amended] 0 35. Section 1042.905 is amended by adding the abbreviations

CH4and N2O in alphanumeric order to read as follows:

Sec. 1042.905 Symbols, acronyms, and abbreviations.

* * * * *

CH4methane.

* * * * *

N2O nitrous oxide.

* * * * *

PART 1045--[AMENDED] 0 36. The authority citation for part 1045 continues to read as follows:

Authority: 42 U.S.C. 7401-7671q.

Subpart C--[Amended] 0 37. Section 1045.205 is amended by revising paragraph (q) to read as follows:

Sec. 1045.205 What must I include in my application?

* * * * *

(q) Report test results as follows:

Page 56510

(2) Report measured CO2, N2O, and

CH4as described in Sec. 1045.235. Small-volume engine manufacturers may omit reporting N2O and CH4.

* * * * * 0 38. Section 1045.235 is amended by adding paragraph (g) to read as follows:

Sec. 1045.235 What emission testing must I perform for my application for a certificate of conformity?

* * * * *

(g) Measure CO2and CH4with each low-hour certification test using the procedures specified in 40 CFR part 1065 starting in the 2011 and 2012 model years, respectively. Also measure

N2O with each low-hour certification test using the procedures specified in 40 CFR part 1065 starting in the 2013 model year for any engine family that depends on NOX aftertreatment to meet emission standards. Small-volume engine manufacturers may omit measurement of N2O and

CH4. These measurements are not required for NTE testing.

Use the same units and modal calculations as for your other results to report a single weighted value for each constituent. Round the final values as follows:

(1) Round CO2to the nearest 1 g/kW-hr.

(2) Round N2O to the nearest 0.001 g/kW-hr.

(3) Round CH4to the nearest 0.001 g/kW-hr.

Subpart F--[Amended] 0 39. Section 1045.501 is amended by revising paragraph (b) to read as follows:

Sec. 1045.501 How do I run a valid emission test?

* * * * *

(b) General requirements. Use the equipment and procedures for spark-ignition engines in 40 CFR part 1065 to determine whether engines meet the duty-cycle emission standards in Sec. Sec. 1045.103 and 1045.105. Measure the emissions of all exhaust constituents subject to emissions standards as specified in 40 CFR part 1065. Measure

CO2, N2O, and CH4as described in

Sec. 1045.235. Use the applicable duty cycles specified in Sec. 1045.505. Section 1045.515 describes the supplemental procedures for evaluating whether engines meet the not-to-exceed emission standards in

Sec. 1045.107.

* * * * *

PART 1048--[AMENDED] 0 40. The authority citation for part 1048 continues to read as follows:

Authority: 42 U.S.C. 7401-7671q.

Subpart C--[Amended] 0 41. Section 1048.205 is amended by revising paragraph (s) to read as follows:

Sec. 1048.205 What must I include in my application?

* * * * *

(s) Report test results as follows:

(2) Report measured CO2, N2O, and

CH4as described in Sec. 1048.235. Small-volume engine manufacturers may omit reporting N2O and CH4.

* * * * * 0 42. Section 1048.235 is amended by adding paragraph (g) to read as follows:

Sec. 1048.235 What emission testing must I perform for my application for a certificate of conformity?

* * * * *

(g) Measure CO2and CH4with each low-hour certification test using the procedures specified in 40 CFR part 1065 starting in the 2011 and 2012 model years, respectively. Also measure

N2O with each low-hour certification test using the procedures specified in 40 CFR part 1065 starting in the 2013 model year for any engine family that depends on NOx aftertreatment to meet emission standards. Small-volume engine manufacturers may omit measurement of N2O and CH4. These measurements are not required for measurements using field-testing procedures. Use the same units and modal calculations as for your other results to report a single weighted value for each constituent. Round the final values as follows:

(1) Round CO2to the nearest 1 g/kW-hr.

(2) Round N2O to the nearest 0.001 g/kW-hr.

(3) Round CH4to the nearest 0.001g/kW-hr.

Subpart F--[Amended] 0 43. Section 1048.501 is amended by revising paragraph (a) to read as follows:

Sec. 1048.501 How do I run a valid emission test?

(a) Use the equipment and procedures for spark-ignition engines in 40 CFR part 1065 to determine whether engines meet the duty-cycle emission standards in Sec. 1048.101(a) and (b). Measure the emissions of all the pollutants we regulate in Sec. 1048.101 using the sampling procedures specified in 40 CFR part 1065. Measure CO2,

N2O, and CH4as described in Sec. 1048.235. Use the applicable duty cycles specified in Sec. Sec. 1048.505 and 1048.510.

* * * * *

Subpart I--[Amended] 0 44. Section 1048.805 is amended by adding the abbreviations

CH4and N2O in alphanumeric order to read as follows:

Sec. 1048.805 What symbols, acronyms, and abbreviations does this part use?

* * * * *

CH4methane.

* * * * *

N2O nitrous oxide.

* * * * *

PART 1051--[AMENDED] 0 45. The authority citation for part 1051 continues to read as follows:

Authority: 42 U.S.C. 7401-7671q.

Subpart C--[Amended] 0 46. Section 1051.205 is amended by revising paragraph (p) to read as follows:

Sec. 1051.205 What must I include in my application?

* * * * *

(p) Report test results as follows:

(2) Report measured CO2, N2O, and

CH4as described in Sec. 1051.235. Small-volume manufacturers may omit reporting N2O and CH4.

* * * * * 0 47. Section 1051.235 is amended by adding paragraph (i) to read as follows:

Sec. 1051.235 What emission testing must I perform for my application for a certificate of conformity?

* * * * *

(i) Measure CO2and CH4with each low-hour certification test using the procedures specified in 40 CFR part 1065 starting in the 2011 and 2012

Page 56511

model years, respectively. Also measure N2O with each low- hour certification test using the analytical equipment and procedures specified in 40 CFR part 1065 starting in the 2013 model year for any engine family that depends on NOx aftertreatment to meet emission standards. Small-volume manufacturers may omit measurement of

N2O and CH4; other manufacturers may provide appropriate data and/or information and omit measurement of

N2O and CH4as described in 40 CFR 1065.5. Use the same units and modal calculations as for your other results to report a single weighted value for each constituent. Round the final values as follows:

(1) Round CO2to the nearest 1 g/kW-hr or 1 g/km, as appropriate.

(2) Round N2O to the nearest 0.001 g/kW-hr or 0.001 g/ km, as appropriate.

(3) Round CH4to the nearest 0.001 g/kW-hr or 0.001 g/ km, as appropriate.

Subpart F--[Amended] 0 48. Section 1051.501 is amended by revising paragraphs (a) and (b) to read as follows:

Sec. 1051.501 What procedures must I use to test my vehicles or engines?

* * * * *

(a) Snowmobiles. For snowmobiles, use the equipment and procedures for spark-ignition engines in 40 CFR part 1065 to determine whether your snowmobiles meet the duty-cycle emission standards in Sec. 1051.103. Measure the emissions of all the pollutants we regulate in

Sec. 1051.103. Measure CO2, N2O, and

CH4as described in Sec. 1051.235. Use the duty cycle specified in Sec. 1051.505.

(b) Motorcycles and ATVs. For motorcycles and ATVs, use the equipment, procedures, and duty cycle in 40 CFR part 86, subpart F, to determine whether your vehicles meet the exhaust emission standards in

Sec. 1051.105 or Sec. 1051.107. Measure the emissions of all the pollutants we regulate in Sec. 1051.105 or Sec. 1051.107. Measure

CO2, N2O, and CH4as described in

Sec. 1051.235. If we allow you to certify ATVs based on engine testing, use the equipment, procedures, and duty cycle described or referenced in the section that allows engine testing. For motorcycles with engine displacement at or below 169 cc and all ATVs, use the driving schedule in paragraph (c) of appendix I to 40 CFR part 86. For all other motorcycles, use the driving schedule in paragraph (b) of

Appendix I to part 86. With respect to vehicle-speed governors, test motorcycles and ATVs in their ungoverned configuration, unless we approve in advance testing in a governed configuration. We will only approve testing in a governed configuration if you can show that the governor is permanently installed on all production vehicles and is unlikely to be removed in use. With respect to engine-speed governors, test motorcycles and ATVs in their governed configuration. Run the test engine, with all emission-control systems operating, long enough to stabilize emission levels; you may consider emission levels stable without measurement if you accumulate 12 hours of operation.

* * * * *

Subpart I--[Amended] 0 49. Section 1051.805 is amended by adding the abbreviations

CH4and N2O in alphanumeric order to read as follows:

Sec. 1051.805 What symbols, acronyms, and abbreviations does this part use?

* * * * *

CH4methane.

* * * * *

N2O nitrous oxide.

* * * * *

PART 1054--[AMENDED] 0 50. The authority citation for part 1054 continues to read as follows:

Authority: 42 U.S.C. 7401-7671q.

Subpart C--[Amended] 0 51. Section 1054.205 is amended by revising paragraph (p) to read as follows:

Sec. 1054.205 What must I include in my application?

* * * * *

(p) Report test results as follows:

(2) Report measured CO2, N2O, and

CH4as described in Sec. 1054.235. Small-volume engine manufacturers may omit reporting N2O and CH4.

* * * * * 0 52. Section 1054.235 is amended by adding paragraph (g) to read as follows:

Sec. 1054.235 What exhaust emission testing must I perform for my application for a certificate of conformity?

* * * * *

(g) Measure CO2and CH4with each low-hour certification test using the procedures specified in 40 CFR part 1065 starting in the 2011 and 2012 model years, respectively. Also measure

N2O with each low-hour certification test using the procedures specified in 40 CFR part 1065 starting in the 2013 model year for any engine family that depends on NOx aftertreatment to meet emission standards. Small-volume engine manufacturers may omit measurement of N2O and CH4. Use the same units and modal calculations as for your other results to report a single weighted value for each constituent. Round the final values as follows:

(1) Round CO2to the nearest 1 g/kW-hr.

(2) Round N2O to the nearest 0.001 g/kW-hr.

(3) Round CH4to the nearest 0.001 g/kW-hr.

Subpart F--[Amended] 0 53. Section 1054.501 is amended by revising paragraph (b)(1) to read as follows:

Sec. 1054.501 How do I run a valid emission test?

* * * * *

(b) * * *

(1) Measure the emissions of all exhaust constituents subject to emissions standards as specified in Sec. 1054.505 and 40 CFR part 1065. Measure CO2, N2O, and CH4as described in Sec. 1054.235. See Sec. 1054.650 for special provisions that apply for variable-speed engines (including engines shipped without governors).

* * * * *

PART 1065--[AMENDED] 0 54. The authority citation for part 1065 continues to read as follows:

Authority: 42 U.S.C. 7401-7671q.

Subpart A--[Amended] 0 55. Section 1065.5 is amended by revising paragraph (a)(3) to read as follows:

Sec. 1065.5 Overview of this part 1065 and its relationship to the standard-setting part.

(a) * * *

(3) Which exhaust constituents do I need to measure? Measure all exhaust constituents that are subject to emission standards, any other exhaust constituents needed for calculating emission rates, and any additional

Page 56512

exhaust constituents as specified in the standard-setting part.

Alternatively, you may omit the measurement of N2O and

CH4for an engine, provided it is not subject to an

N2O or CH4emission standard. If you omit the measurement of N2O and CH4, you must provide other information and/or data that will give us a reasonable basis for estimating the engine's emission rates.

* * * * *

Subpart C--[Amended] 0 56. The center heading ``NOxMeasurements'' preceding Sec. 1065.270 is revised to read as follows:

NOX and N2O Measurements 0 57. A new Sec. 1065.275 is added under the center heading

``NOxand N2O Measurements'' to read as follows:

Sec. 1065.275 N2O measurement devices.

(a) General component requirements. We recommend that you use an analyzer that meets the specifications in Table 1 of Sec. 1065.205.

Note that your system must meet the linearity verification in Sec. 1065.307.

(b) Instrument types. You may use any of the following analyzers to measure N2O:

(1) Nondispersive infra-red (NDIR) analyzer. You may use an NDIR analyzer that has compensation algorithms that are functions of other gaseous measurements and the engine's known or assumed fuel properties.

The target value for any compensation algorithm is 0.0% (that is, no bias high and no bias low), regardless of the uncompensated signal's bias.

(2) Fourier transform infra-red (FTIR) analyzer. You may use an

FTIR analyzer that has compensation algorithms that are functions of other gaseous measurements and the engine's known or assumed fuel properties. The target value for any compensation algorithm is 0.0%

(that is, no bias high and no bias low), regardless of the uncompensated signal's bias. Use appropriate analytical procedures for interpretation of infrared spectra. For example, EPA Test Method 320 is considered a valid method for spectral interpretation (see http:// www.epa.gov/ttn/emc/methods/method320.html).

(3) Photoacoustic analyzer. You may use a photoacoustic analyzer that has compensation algorithms that are functions of other gaseous measurements. The target value for any compensation algorithm is 0.0%

(that is, no bias high and no bias low), regardless of the uncompensated signal's bias. Use an optical wheel configuration that gives analytical priority to measurement of the least stable components in the sample. Select a sample integration time of at least 5 seconds.

Take into account sample chamber and sample line volumes when determining flush times for your instrument.

(4) Gas chromatograph analyzer. You may use a gas chromatograph with an electron-capture detector (GC-ECD) to measure N2O concentrations of diluted exhaust for batch sampling.

(i) You may use a packed or porous layer open tubular (PLOT) column phase of suitable polarity and length to achieve adequate resolution of the N2O peak for analysis. Examples of acceptable columns are a PLOT column consisting of bonded polystyrene-divinylbenzene or a

Porapack Q packed column. Take the column temperature profile and carrier gas selection into consideration when setting up your method to achieve adequate N2O peak resolution.

(ii) Use good engineering judgment to zero your instrument and correct for drift. You do not need to follow the specific procedures in

Sec. 1065.530 and Sec. 1065.550(b) that would otherwise apply. For example, you may perform a span gas measurement before and after sample analysis without zeroing. Use the average area counts of the pre-span and post-span measurements to generate a response factor (area counts/ span gas concentration), which you then multiply by the area counts from your sample to generate the sample concentration.

NDIR, FTIR, and photoacoustic analyzers using the procedures of Sec. 1065.375. Interference validation is not required for GC-ECD. Certain interference gases can positively interfere with NDIR, FTIR, and photoacoustic analyzers by causing a response similar to

N2O. When running the interference verification for these analyzers, use interference gases as follows:

(1) The interference gases for NDIR analyzers are CO,

CO2, H2O, CH4and SO2. Note that interference species, with the exception of H2O, are dependent on the N2O infrared absorption band chosen by the instrument manufacturer and should be determined dently for each analyzer.

(2) Use good engineering judgment to determine interference gases for FTIR. Note that interference species, with the exception of

H2O, are dependent on the N2O infrared absorption band chosen by the instrument manufacturer and should be determined independently for each analyzer.

(3) The interference gases for photoacoustic analyzers are CO,

CO2, and H2O.

Subpart D--[Amended] 0 58. Section 1065.303 is revised to read as follows:

Sec. 1065.303 Summary of required calibration and verifications

The following table summarizes the required and recommended calibrations and verifications described in this subpart and indicates when these have to be performed:

Table 1 of Sec. 1065.303-Summary of Required Calibration and

Verifications

Type of calibration or verification

Minimum frequency \a\

Sec. 1065.305: Accuracy,

Accuracy: Not required, but repeatability and noise.

recommended for initial installation.

Repeatability: Not required, but recommended for initial installation.

Noise: Not required, but recommended for initial installation.

Sec. 1065.307: Linearity........... Speed: Upon initial installation, within 370 days before testing and after major maintenance.

Torque: Upon initial installation, within 370 days before testing and after major maintenance.

Electrical power: Upon initial installation, within 370 days before testing and after major maintenance.

Clean gas and diluted exhaust flows: Upon initial installation, within 370 days before testing and after major maintenance, unless flow is verified by propane check or by carbon or oxygen balance.

Page 56513

Raw exhaust flow: Upon initial installation, within 185 days before testing and after major maintenance, unless flow is verified by propane check or by carbon or oxygen balance.

Gas analyzers: Upon initial installation, within 35 days before testing and after major maintenance.

FTIR and photoacoustic analyzers:

Upon initial installation, within 370 days before testing and after major maintenance.

GC-ECD: Upon initial installation and after major maintenance.

PM balance: Upon initial installation, within 370 days before testing and after major maintenance.

Stand-alone pressure and temperature: Upon initial installation, within 370 days before testing and after major maintenance.

Sec. 1065.308: Continuous gas

Upon initial installation or analyzer system response and

after system modification that updating-recording verification--for would effect response. gas analyzers not continuously compensated for other gas species.

Sec. 1065.309: Continuous gas

Upon initial installation or analyzer system-response and

after system modification that updating-recording verification--for would effect response. gas analyzers continuously compensated for other gas species.

Sec. 1065.310: Torque.............. Upon initial installation and after major maintenance.

Sec. 1065.315: Pressure,

Upon initial installation and temperature, dewpoint.

after major maintenance.

Sec. 1065.320: Fuel flow........... Upon initial installation and after major maintenance.

Sec. 1065.325: Intake flow......... Upon initial installation and after major maintenance.

Sec. 1065.330: Exhaust flow........ Upon initial installation and after major maintenance.

Sec. 1065.340: Diluted exhaust flow Upon initial installation and

(CVS).

after major maintenance.

Sec. 1065.341: CVS and batch

Upon initial installation, within sampler verification \b\.

35 days before testing, and after major maintenance.

Sec. 1065.345: Vacuum leak......... Before each laboratory test according to subpart F of this part and before each field test according to subpart J of this part.

Sec. 1065.350: CO2 NDIR H2O

Upon initial installation and interference.

after major maintenance.

Sec. 1065.355: CO NDIR CO2 and H2O Upon initial installation and interference.

after major maintenance.

Sec. 1065.360: FID calibration, THC Calibrate all FID analyzers: upon

FID optimization, and THC FID

initial installation and after verification..

major maintenance.

Optimize and determine CH4 response for THC FID analyzers: upon initial installation and after major maintenance.

Verify CH4 response for THC FID analyzers: upon initial installation, within 185 days before testing, and after major maintenance.

Sec. 1065.362: Raw exhaust FID O2

For all FID analyzers: upon interference.

initial installation, and after major maintenance.

For THC FID analyzers: upon initial installation, after major maintenance, and after FID optimization according to Sec. 1065.360.

Sec. 1065.365: Nonmethane cutter

Upon initial installation, within penetration.

185 days before testing, and after major maintenance.

Sec. 1065.370: CLD CO2 and H2O

Upon initial installation and quench.

after major maintenance.

Sec. 1065.372: NDUV HC and H2O

Upon initial installation and interference.

after major maintenance.

Sec. 1065.375: N2O analyzer

Upon initial installation and interference.

after major maintenance.

Sec. 1065.376: Chiller NO2

Upon initial installation and penetration.

after major maintenance.

Sec. 1065.378: NO2-to-NO converter Upon initial installation, within conversion.

35 days before testing, and after major maintenance.

Sec. 1065.390: PM balance and

Independent verification: upon weighing.

initial installation, within 370 days before testing, and after major maintenance.

Zero, span, and reference sample verifications: within 12 hours of weighing, and after major maintenance.

Sec. 1065.395: Inertial PM balance Independent verification: upon and weighing.

initial installation, within 370 days before testing, and after major maintenance.

Other verifications: upon initial installation and after major maintenance.

\a\ Perform calibrations and verifications more frequently, according to measurement system manufacturer instructions and good engineering judgment.

\b\ The CVS verification described in Sec. 1065.341 is not required for systems that agree within 2% based on a chemical balance of carbon or oxygen of the intake air, fuel, and diluted exhaust. 0 59. Section 1065.307 is amended by revising paragraph (c)(6) to read as follows:

Sec. 1065.307 Linearity verification.

* * * * *

(6) For all measured quantities, use instrument manufacturer recommendations and good engineering judgment to select reference values, yrefi, that cover a range of values that you expect would prevent extrapolation beyond these values during emission testing. We recommend selecting a zero reference signal as one of the reference values of the linearity verification. For stand-alone pressure and temperature linearity verifications and for GC-ECD linearity verifications, we recommend at least three reference values.

For all other linearity verifications select at least ten reference values.

* * * * * 0 60. Section 1065.365 is amended by revising paragraphs (d), (e), and

(f) to read as follows:

Page 56514

Sec. 1065.365 Nonmethane cutter penetration fractions.

* * * * *

(d) Procedure for a FID calibrated with the NMC. The method described in this paragraph (d) is recommended over the procedures specified in paragraphs (e) and (f) of this section. If your FID arrangement is such that a FID is always calibrated to measure

CH4with the NMC, then span that FID with the NMC using a

CH4span gas, set the product of that FID's CH4 response factor and CH4penetration fraction,

RFPFCH4[NMC-FID], equal to 1.0 for all emission calculations, and determine its combined ethane

(C2H6) response factor and penetration fraction,

RFPFC2H6[NMC-FID]as follows:

(1) Select CH4and C2H6analytical gas mixtures and ensure that both mixtures meet the specifications of

Sec. 1065.750. Select a CH4concentration that you would use for spanning the FID during emission testing and select a

C2H6concentration that is typical of the peak

NMHC concentration expected at the hydrocarbon standard or equal to the

THC analyzer's span value.

(2) Start, operate, and optimize the nonmethane cutter according to the manufacturer's instructions, including any temperature optimization.

(3) Confirm that the FID analyzer meets all the specifications of

Sec. 1065.360.

(4) Start and operate the FID analyzer according to the manufacturer's instructions.

(5) Zero and span the FID with the nonmethane cutter as you would during emission testing. Span the FID through the cutter by using

CH4span gas.

(6) Introduce the C2H6analytical gas mixture upstream of the nonmethane cutter. Use good engineering judgment to address the effect of hydrocarbon contamination if your point of introduction is vastly different from the point of zero/span gas introduction.

(7) Allow time for the analyzer response to stabilize.

Stabilization time may include time to purge the nonmethane cutter and to account for the analyzer's response.

(8) While the analyzer measures a stable concentration, record 30 seconds of sampled data. Calculate the arithmetic mean of these data points.

(9) Divide the mean C2H6concentration by the reference concentration of C2H6, converted to a

C1basis. The result is the C2H6 combined response factor and penetration fraction,

RFPFC2H6[NMC-FID]. Use this combined response factor and penetration fraction and the product of the CH4response factor and CH4penetration fraction,

RFPFCH4[NMC-FID], set to 1.0 in emission calculations according to Sec. 1065.660(b)(2)(i), Sec. 1065.660(c)(1)(i), or Sec. 1065.665, as applicable.

(e) Procedure for a FID calibrated with propane, bypassing the NMC.

If you use a single FID for THC and CH4determination with an NMC that is calibrated with propane, C3H8, by bypassing the NMC, determine its penetration fractions,

PFC2H6[NMC-FID]and PFCH4[NMC-FID], as follows:

(1) Select CH4and C2H6analytical gas mixtures and ensure that both mixtures meet the specifications of

Sec. 1065.750. Select a CH4concentration that you would use for spanning the FID during emission testing and select a

C2H6concentration that is typical of the peak

NMHC concentration expected at the hydrocarbon standard or equal to the

THC analyzer's span value.

(2) Start and operate the nonmethane cutter according to the manufacturer's instructions, including any temperature optimization.

(3) Confirm that the FID analyzer meets all the specifications of

Sec. 1065.360.

(4) Start and operate the FID analyzer according to the manufacturer's instructions.

(5) Zero and span the FID as you would during emission testing.

Span the FID by bypassing the cutter and by using

C3H8span gas.

(7) Allow time for the analyzer response to stabilize.

Stabilization time may include time to purge the nonmethane cutter and to account for the analyzer's response.

(8) While the analyzer measures a stable concentration, record 30 seconds of sampled data. Calculate the arithmetic mean of these data points.

(9) Reroute the flow path to bypass the nonmethane cutter, introduce the C2H6analytical gas mixture, and repeat the steps in paragraph (e)(7) through (e)(8) of this section.

(10) Divide the mean C2H6concentration measured through the nonmethane cutter by the mean

C2H6concentration measured after bypassing the nonmethane cutter. The result is the C2H6 penetration fraction, PFC2H6[NMC-FID]. Use this penetration fraction according to Sec. 1065.660(b)(2)(ii), Sec. 1065.660(c)(1)(ii), or Sec. 1065.665, as applicable.

(11) Repeat the steps in paragraphs (e)(6) through (e)(10) of this section, but with the CH4analytical gas mixture instead of

C2H6. The result will be the CH4 penetration fraction, PFCH4[NMC-FID]. Use this penetration fraction according to Sec. 1065.660(b)(2)(ii), Sec. 1065.660(c)(1)(ii), or Sec. 1065.665, as applicable.

(f) Procedure for a FID calibrated with methane, bypassing the NMC.

If you use a FID with an NMC that is calibrated with methane,

CH4, by bypassing the NMC, determine its combined ethane

(C2H6) response factor and penetration fraction,

RFPFC2H6[NMC-FID], as well as its CH4penetration fraction, PFCH4[NMC-FID], as follows:

(1) Select CH4and C2H6analytical gas mixtures and ensure that both mixtures meet the specifications of

Sec. 1065.750. Select a CH4concentration that you would use for spanning the FID during emission testing and select a

C2H6concentration that is typical of the peak

NMHC concentration expected at the hydrocarbon standard or equal to the

THC analyzer's span value.

(2) Start and operate the nonmethane cutter according to the manufacturer's instructions, including any temperature optimization.

(3) Confirm that the FID analyzer meets all the specifications of

Sec. 1065.360.

(4) Start and operate the FID analyzer according to the manufacturer's instructions.

(5) Zero and span the FID as you would during emission testing.

Span the FID by bypassing the cutter and by using CH4span gas. Note that you must span the FID on a C1basis. For example, if your span gas has a methane reference value of 100 [mu]mol/ mol, the correct FID response to that span gas is 100 [mu]mol/mol because there is one carbon atom per CH4molecule.

(7) Allow time for the analyzer response to stabilize.

Stabilization time may include time to purge the nonmethane cutter and to account for the analyzer's response.

(8) While the analyzer measures a stable concentration, record 30 seconds of sampled data. Calculate the arithmetic mean of these data points.

(9) Divide the mean C2H6concentration by the reference concentration of C2H6, converted to a

C1basis. The result is the C2H6 combined response factor and penetration fraction,

RFPFC2H6[NMC-FID]. Use this combined response factor and penetration fraction according to Sec. 1065.660(b)(2)(iii),

Page 56515

Sec. 1065.660(c)(1)(iii), or Sec. 1065.665, as applicable.

(10) Introduce the CH4analytical gas mixture upstream of the nonmethane cutter. Use good engineering judgment to address the effect of hydrocarbon contamination if your point of introduction is vastly different from the point of zero/span gas introduction.

(11) Allow time for the analyzer response to stabilize.

Stabilization time may include time to purge the nonmethane cutter and to account for the analyzer's response.

(12) While the analyzer measures a stable concentration, record 30 seconds of sampled data. Calculate the arithmetic mean of these data points.

(13) Reroute the flow path to bypass the nonmethane cutter, introduce the CH4analytical gas mixture, and repeat the steps in paragraphs (e)(11) and (12) of this section.

(14) Divide the mean CH4concentration measured through the nonmethane cutter by the mean CH4concentration measured after bypassing the nonmethane cutter. The result is the CH4 penetration fraction, PFCH4[NMC-FID]. Use this penetration fraction according to Sec. 1065.660(b)(2)(iii), Sec. 1065.660(c)(1)(iii), or Sec. 1065.665, as applicable. 0 61. The center heading ``NOXMEASUREMENTS'' preceding Sec. 1065.370 is revised to read as follows:

NOXand N2O Measurements 0 62. A new Sec. 1065.375 is added under the center header

``NOXand N2O Measurements'' to read as follows:

Sec. 1065.375 Interference verification for N2O analyzers.

(a) Scope and frequency. See Sec. 1065.275 to determine whether you need to verify the amount of interference after initial analyzer installation and after major maintenance.

(b) Measurement principles. Interference gasses can positively interfere with certain analyzers by causing a response similar to

N2O. If the analyzer uses compensation algorithms that utilize measurements of other gases to meet this interference verification, simultaneously conduct these other measurements to test the compensation algorithms during the analyzer interference verification.

(c) System requirements. Analyzers must have combined interference that is within (0.0 1.0) [mu]mol/mol. We strongly recommend a lower interference that is within (0.0 0.5)

mu mol/mol.

(d) Procedure. Perform the interference verification as follows:

(1) Start, operate, zero, and span the N2O analyzer as you would before an emission test. If the sample is passed through a dryer during emission testing, you may run this verification test with the dryer if it meets the requirements of Sec. 1065.342. Operate the dryer at the same conditions as you will for an emission test. You may also run this verification test without the sample dryer.

(2) Create a humidified test gas by bubbling a multi component span gas that incorporates the target interference species and meets the specifications in Sec. 1065.750 through distilled water in a sealed vessel. If the sample is not passed through a dryer during emission testing, control the vessel temperature to generate an H2O level at least as high as the maximum expected during emission testing.

If the sample is passed through a dryer during emission testing, control the vessel temperature to generate an H2O level at least as high as the level determined in Sec. 1065.145(e)(2) for that dryer. Use interference span gas concentrations that are at least as high as the maximum expected during testing.

(3) Introduce the humidified interference test gas into the sample system. You may introduce it downstream of any sample dryer, if one is used during testing.

(4) If the sample is not passed through a dryer during this verification test, measure the water mole fraction, xH2O, of the humidified interference test gas as close as possible to the inlet of the analyzer. For example, measure dewpoint, Tdew, and absolute pressure, ptotal, to calculate xH2O.

Verify that the water content meets the requirement in paragraph (d)(2) of this section. If the sample is passed through a dryer during this verification test, you must verify that the water content of the humidified test gas downstream of the vessel meets the requirement in paragraph (d)(2) of this section based on either direct measurement of the water content (e.g., dewpoint and pressure) or an estimate based on the vessel pressure and temperature. Use good engineering judgment to estimate the water content. For example, you may use previous direct measurements of water content to verify the vessel's level of saturation.

(5) If a sample dryer is not used in this verification test, use good engineering judgment to prevent condensation in the transfer lines, fittings, or valves from the point where xH2Ois measured to the analyzer. We recommend that you design your system so that the wall temperatures in the transfer lines, fittings, and valves from the point where xH2Ois measured to the analyzer are at least 5 [deg]C above the local sample gas dewpoint.

(6) Allow time for the analyzer response to stabilize.

Stabilization time may include time to purge the transfer line and to account for analyzer response.

(7) While the analyzer measures the sample's concentration, record its output for 30 seconds. Calculate the arithmetic mean of this data.

(8) The analyzer meets the interference verification if the result of paragraph (d)(7) of this section meets the tolerance in paragraph

(9) You may also run interference procedures separately for individual interference gases. If the interference gas levels used are higher than the maximum levels expected during testing, you may scale down each observed interference value by multiplying the observed interference by the ratio of the maximum expected concentration value to the actual value used during this procedure. You may run separate interference concentrations of H2O (down to 0.025 mol/mol

H2O content) that are lower than the maximum levels expected during testing, but you must scale up the observed H2O interference by multiplying the observed interference by the ratio of the maximum expected H2O concentration value to the actual value used during this procedure. The sum of the scaled interference values must meet the tolerance specified in paragraph (c) of this section.

Subpart F--[Amended] 0 63. Section 1065.550 is amended by revising paragraphs (b) introductory text and (b)(1), adding and reserving paragraph (b)(3), and adding paragraph (b)(4) to read as follows:

Sec. 1065.550 Gas analyzer range validation, drift validation, and drift correction.

* * * * *

(b) Drift validation and drift correction. Calculate two sets of brake-specific emission results for each test interval. Calculate one set using the data before drift correction and calculate the other set after correcting all the data for drift according to Sec. 1065.672.

Use the two sets of brake-specific emission results to validate the duty cycle for drift as follows:

(1) The duty cycle is validated for drift if you satisfy one of the following criteria:

(i) For each test interval of the duty cycle and for each measured exhaust constituent, the difference between the uncorrected and the corrected brake-

Page 56516

specific emission values over the test interval is within 4% of the uncorrected value or applicable emission standard, whichever is greater. This requirement also applies for CO2, whether or not an emission standard applies for CO2. Where no emission standard applies for CO2, the difference must be within 4% of the uncorrected value. See paragraph (b)(4) of this section for exhaust constituents other than CO2for which no emission standard applies.

(ii) For the entire duty cycle and for each regulated pollutant, the difference between the uncorrected and corrected composite brake- specific emission values over the entire duty cycle is within 4% of the uncorrected value or the applicable emission standard, whichever is greater. Note that for purposes of drift validation using composite brake-specific emission values over the entire duty cycle, leave unaltered any negative emission results over a given test interval (i.e., do not set them to zero). A third calculation of composite brake-specific emission values is required for final reporting. This calculation uses drift-corrected mass (or mass rate) values from each test interval and sets any negative mass (or mass rate) values to zero before calculating the composite brake-specific emission values over the entire duty cycle. This requirement also applies for CO2, whether or not an emission standard applies for CO2. Where no emission standard applies for

CO2, the difference must be within 4% of the uncorrected value. See paragraph (b)(3) of this section for exhaust constituents other than CO2for which no emission standard applies.

* * * * *

(3) [Reserved]

(4) The provisions of paragraph (b)(3) of this section apply for measurement of pollutants other than CO2for which no emission standard applies. You may use measurements that do not meet the drift validation criteria specified in paragraph (b)(1) of this section. For example, this allowance may be appropriate for measuring and reporting very low concentrations of CH4and

N2O as long as no emission standard applies for these compounds.

Subpart G--[Amended] 0 64. Section 1065.601 is amended by revising paragraph (a)(1) to read as follows:

Sec. 1065.601 Overview.

(a) * * *

(1) Use the signals recorded before, during, and after an emission test to calculate brake-specific emissions of each measured exhaust constituent.

* * * * * 0 65. Section 1065.660 is amended by revising paragraphs (a), (b) introductory text, (b)(1), (b)(2), and (b)(3) introductory text, and adding paragraph (c) to read as follows:

Sec. 1065.660 THC, NMHC, and CH4determination.

(a) THC determination and THC/CH4 initial contamination corrections. (1) If we require you to determine THC emissions, calculate xTHC[THC-FID]corusing the initial THC contamination concentration xTHC[THC-FID]initfrom Sec. 1065.520 as follows:

GRAPHIC

TIFF OMITTED TR30OC09.179

Example: xTHCuncor= 150.3 [micro]mol/mol xTHCinit= 1.1 [micro]mol/mol xTHCcor= 150.3-1.1 xTHCcor= 149.2 [micro]mol/mol

(2) For the NMHC determination described in paragraph (b) of this section, correct xTHC[THC-FID]for initial HC contamination using Eq. 1065.660-1. You may correct xTHC[NMC-FID]for initial contamination of the CH4sample train using Eq. 1065.660-1, substituting in CH4concentrations for THC.

(3) For the CH4determination described in paragraph (c) of this section, you may correct xTHC[NMC-FID]for initial contamination of the CH4sample train using Eq. 1065.660-1, substituting in CH4concentrations for THC.

(b) NMHC determination. Use one of the following to determine NMHC concentration, xNMHC:

(1) If you do not measure CH4, you may determine NMHC concentrations as described in Sec. 1065.650(c)(1)(vi).

(2) For nonmethane cutters, calculate xNMHCusing the nonmethane cutter's penetration fractions (PF) of CH4and

C2H6from Sec. 1065.365, and using the HC contamination and dry-to-wet corrected THC concentration xTHC[THC-FID]coras determined in paragraph (a) of this section.

(i) Use the following equation for penetration fractions determined using an NMC configuration as outlined in Sec. 1065.365(d):

GRAPHIC

TIFF OMITTED TR30OC09.180

Where: xNMHC= concentration of NMHC. xTHC[THC-FID]cor= concentration of THC, HC contamination and dry-to-wet corrected, as measured by the THC FID during sampling while bypassing the NMC. xTHC[NMC-FID]cor= concentration of THC, HC contamination

(optional) and dry-to-wet corrected, as measured by the NMC FID during sampling through the NMC.

RFCH4[THC-FID]= response factor of THC FID to

CH4, according to Sec. 1065.360(d).

RFPFC2H6[NMC-FID]= nonmethane cutter combined ethane response factor and penetration fraction, according to Sec. 1065.365(d).

Example: xTHC[THC-FID]cor= 150.3 [mu]mol/mol xTHC[NMC-FID]cor= 20.5 [mu]mol/mol

RFPFC2H6[NMC-FID]= 0.019

RFCH4[THC-FID]= 1.05

GRAPHIC

TIFF OMITTED TR30OC09.181 xNMHC= 131.4 [mu]mol/mol

(ii) For penetration fractions determined using an NMC configuration as outlined in section Sec. 1065.365(e), use the following equation:

Page 56517

GRAPHIC

TIFF OMITTED TR30OC09.182

Where: xNMHC= concentration of NMHC. xTHC[THC-FID]cor= concentration of THC, HC contamination and dry-to-wet corrected, as measured by the THC FID during sampling while bypassing the NMC.

PFCH4[NMC-FID]= nonmethane cutter CH4 penetration fraction, according to Sec. 1065.365(e). xTHC[NMC-FID]cor= concentration of THC, HC contamination

(optional) and dry-to-wet corrected, as measured by the THC FID during sampling through the NMC.

PFC2H6[NMC-FID]= nonmethane cutter ethane penetration fraction, according to Sec. 1065.365(e).

Example: xTHC[THC-FID]cor= 150.3 [mu]mol/mol

PFCH4[NMC-FID]= 0.990 xTHC[NMC-FID]cor= 20.5 [mu]mol/mol

PFC2H6[NMC-FID]= 0.020

GRAPHIC

TIFF OMITTED TR30OC09.183 xNMHC= 132.3 [mu]mol/mol

(iii) For penetration fractions determined using an NMC configuration as outlined in Sec. 1065.365(f), use the following equation:

GRAPHIC

TIFF OMITTED TR30OC09.184

Where: xNMHC= concentration of NMHC. xTHC[THC-FID]cor= concentration of THC, HC contamination and dry-to-wet corrected, as measured by the THC FID during sampling while bypassing the NMC.

PFCH4[NMC-FID]= nonmethane cutter CH4 penetration fraction, according to Sec. 1065.365(f). xTHC[NMC-FID]cor= concentration of THC, HC contamination

(optional) and dry-to-wet corrected, as measured by the THC FID during sampling through the NMC.

RFPFC2H6[NMC-FID]= nonmethane cutter CH4 combined ethane response factor and penetration fraction, according to Sec. 1065.365(f).

RFCH4[THC-FID]= response factor of THC FID to

CH4, according to Sec. 1065.360(d).

Example: xTHC[THC-FID]cor= 150.3 [mu]mol/mol

PFCH4[NMC-FID]= 0.990 xTHC[NMC-FID]cor= 20.5 [mu]mol/mol

RFPFC2H6[NMC-FID]= 0.019

RFCH4[THC-FID]= 0.980

GRAPHIC

TIFF OMITTED TR30OC09.185 xNMHC= 132.5 [mu]mol/mol

(3) For a gas chromatograph, calculate xNMHCusing the THC analyzer's response factor (RF) for CH4, from

Sec. 1065.360, and the HC contamination and dry-to-wet corrected initial THC concentration xTHC[THC-FID]coras determined in paragraph (a) of this section as follows:

* * * * *

(1) For nonmethane cutters, calculate xCH4using the nonmethane cutter's penetration fractions (PF) of CH4and

C2H6from Sec. 1065.365, using the dry-to-wet corrected CH4concentration xTHC[NMC-FID]cor as determined in paragraph (a) of this section and optionally using the CH4contamination correction under paragraph (a) of this section.

(i) Use the following equation for penetration fractions determined using an NMC configuration as outlined in Sec. 1065.365(d):

GRAPHIC

TIFF OMITTED TR30OC09.186

Where: xCH4= concentration of CH4. xTHC[NMC-FID]cor= concentration of THC, HC contamination

(optional) and dry-to-wet corrected, as measured by the NMC FID during sampling through the NMC. xTHC[THC-FID]cor= concentration of THC, HC contamination and dry-to-wet corrected, as measured by the THC FID during sampling while bypassing the NMC.

RFPFC2H6[NMC-FID]= the combined ethane response factor and penetration fraction of the nonmethane cutter, according to

Sec. 1065.365(d).

RFCH4[THC-FID]= response factor of THC FID to

CH4, according to Sec. 1065.360(d).

Example: xTHC[NMC-FID]cor= 10.4 [mu]mol/mol xTHC[THC-FID]cor= 150.3 [mu]mol/mol

RFPFC2H6[NMC-FID]= 0.019

RFCH4[THC-FID]= 1.05

GRAPHIC

TIFF OMITTED TR30OC09.187 xCH4= 7.69 [mu]mol/mol

(ii) For penetration fractions determined using an NMC configuration as outlined in Sec. 1065.365(e), use the following equation:

GRAPHIC

TIFF OMITTED TR30OC09.188

Where: xCH4= concentration of CH4. xTHC[NMC-FID]cor= concentration of THC, HC contamination

PFC2H6[NMC-FID]= nonmethane cutter ethane penetration fraction, according to Sec. 1065.365(e).

RFCH4[THC-FID]= response factor of THC FID to

CH4, according to Sec. 1065.360(d).

PFCH4[NMC-FID]= nonmethane cutter CH4 penetration fraction, according to Sec. 1065.365(e).

Example: xTHC[NMC-FID]cor= 10.4 [mu]mol/mol xTHC[THC-FID]cor= 150.3 [mu]mol/mol

PFC2H6[NMC-FID]= 0.020

RFCH4[THC-FID]= 1.05

Page 56518

PFCH4[NMC-FID]= 0.990

GRAPHIC

TIFF OMITTED TR30OC09.189 xCH4= 7.25 [mu]mol/mol

(iii) For penetration fractions determined using an NMC configuration as outlined in Sec. 1065.365(f), use the following equation:

GRAPHIC

TIFF OMITTED TR30OC09.190

Where: xCH4= concentration of CH4. xTHC[NMC-FID]cor= concentration of THC, HC contamination

RFPFC2H6[NMC-FID]= the combined ethane response factor and penetration fraction of the nonmethane cutter, according to

Sec. 1065.365(f).

PFCH4[NMC-FID]= nonmethane cutter CH4 penetration fraction, according to Sec. 1065.365(f).

RFCH4[THC-FID]= response factor of THC FID to

CH4, according to Sec. 1065.360(d).

Example: xTHC[NMC-FID]cor= 10.4 [micro]mol/mol xTHC[THC-FID]cor= 150.3 [micro]mol/mol

RFPFC2H6[NMC-FID]= 0.019

PFCH4[NMC-FID]= 0.990

RFCH4[THC-FID]= 1.05

GRAPHIC

TIFF OMITTED TR30OC09.191 xCH4= 7.78 [micro]mol/mol

(2) For a gas chromatograph, xCH4is the actual dry- to-wet corrected CH4concentration as measured by the analyzer.

Subpart H--[Amended] 0 66. Section 1065.750 is amended by revising paragraph (a)(1)(ii) and adding paragraph (a)(3)(xi) to read as follows:

Sec. 1065.750 Analytical Gases.

* * * * *

(a) * * *

(1) * * *

(ii) Contamination as specified in the following table:

Table 1 of Sec. 1065.750--General specifications for purified gases.

Purified synthetic

Constituent

air \1\

Purified N2\1\

THC (C1 equivalent)............. 2O, balance purified synthetic air.

* * * * * 0 67. Section 1065.1001 is amended by revising the definition for

``Oxides of nitrogen'' to read as follows:

Sec. 1065.1001 Definitions.

* * * * *

Oxides of nitrogen means NO and NO2as measured by the procedures specified in Sec. 1065.270. Oxides of nitrogen are expressed quantitatively as if the NO is in the form of NO2, such that you use an effective molar mass for all oxides of nitrogen equivalent to that of NO2.

* * * * * 0 68. Section 1065.1005 is amended by revising paragraphs (b), (f)(2), and (g) to read as follows:

Sec. 1065.1005 Symbols, abbreviations, acronyms, and units of measure.

* * * * *

(b) Symbols for chemical species. This part uses the following symbols for chemical species and exhaust constituents:

Symbol

Species

Ar..................................... argon.

C...................................... carbon.

CH4.................................... methane.

C2H6................................... ethane.

C3H8................................... propane.

C4H10.................................. butane.

C5H12.................................. pentane.

CO..................................... carbon monoxide.

CO2.................................... carbon dioxide.

H...................................... atomic hydrogen.

H2..................................... molecular hydrogen.

H2O.................................... water.

He..................................... helium.

\85\Kr................................. krypton 85.

N2..................................... molecular nitrogen.

NMHC................................... nonmethane hydrocarbon.

NMHCE.................................. nonmethane hydrocarbon equivalent.

NO..................................... nitric oxide.

NO2.................................... nitrogen dioxide.

NOX.................................... oxides of nitrogen.

N2O.................................... nitrous oxide.

NOTHC.................................. nonoxygenated hydrocarbon.

O2..................................... molecular oxygen.

OHC.................................... oxygenated hydrocarbon.

\210\Po................................ polonium 210.

PM..................................... particulate mass.

S...................................... sulfur.

SO2.................................... sulfur dioxide.

THC.................................... total hydrocarbon.

ZrO2................................... zirconium dioxide.

* * * * *

(f) * * *

(2) This part uses the following molar masses or effective molar masses of chemical species:

Page 56519

g/mol (10-

Symbol

Quantity

3.kg\.\mol- 1)

Mair............................. molar mass of dry air...

28.96559

MAr.............................. molar mass of argon.....

39.948

MC............................... molar mass of carbon....

12.0107

MCO.............................. molar mass of carbon

28.0101 monoxide.

MCO2............................. molar mass of carbon

44.0095 dioxide.

MH............................... molar mass of atomic

1.00794 hydrogen.

MH2.............................. molar mass of molecular

2.01588 hydrogen.

MH2O............................. molar mass of water.....

18.01528

MHe.............................. molar mass of helium....

4.002602

MN............................... molar mass of atomic

14.0067 nitrogen.

MN2.............................. molar mass of molecular

28.0134 nitrogen.

MNMHC............................ effective molar mass of

13.875389 nonmethane hydrocarbon

\2\.

MNMHCE........................... effective molar mass of

13.875389 nonmethane equivalent hydrocarbon \2\.

MNOx............................. effective molar mass of

46.0055 oxides of nitrogen \3\.

MN2O............................. effective molar mass of

44.0128 nitrous oxide.

MO............................... molar mass of atomic

15.9994 oxygen.

MO2.............................. molar mass of molecular

31.9988 oxygen.

MC3H8............................ molar mass of propane...

44.09562

MS............................... molar mass of sulfur....

32.065

MTHC............................. effective molar mass of

13.875389 total hydrocarbon \2\.

MTHCE............................ effective molar mass of

13.875389 total hydrocarbon equivalent \2\.

\1\ See paragraph (f)(1) of this section for the composition of dry air

\2\ The effective molar masses of THC, THCE, NMHC, and NMHCE are defined by an atomic hydrogen-to-carbon ratio, [alpha], of 1.85

\3\ The effective molar mass of NOx is defined by the molar mass of nitrogen dioxide, NO2

* * * * *

(g) Other acronyms and abbreviations. This part uses the following additional abbreviations and acronyms:

ASTM American Society for Testing and Materials.

BMD bag mini-diluter.

BSFC brake-specific fuel consumption.

CARB California Air Resources Board.

CFR Code of Federal Regulations.

CFV critical-flow venturi.

CI compression-ignition.

CITT Curb Idle Transmission Torque.

CLD chemiluminescent detector.

CVS constant-volume sampler.

DF deterioration factor.

ECM electronic control module.

EFC electronic flow control.

EGR exhaust gas recirculation.

EPA Environmental Protection Agency.

FEL Family Emission Limit

FID flame-ionization detector.

GC gas chromatograph.

GC-ECD gas chromatograph with an electron-capture detector.

IBP initial boiling point.

ISO International Organization for Standardization.

LPG liquefied petroleum gas.

NDIR nondispersive infrared.

NDUV nondispersive ultraviolet.

NIST National Institute for Standards and Technology.

PDP positive-displacement pump.

PEMS portable emission measurement system.

PFD partial-flow dilution.

PMP Polymethylpentene. pt. a single point at the mean value expected at the standard.

PTFE polytetrafluoroethylene (commonly known as TeflonTM).

RE rounding error.

RMC ramped-modal cycle.

RMS root-mean square.

RTD resistive temperature detector.

SSV subsonic venturi.

SI spark-ignition.

UCL upper confidence limit.

UFM ultrasonic flow meter.

U.S.C. United States Code.

FR Doc. E9-23315 Filed 10-29-09; 8:45 am

BILLING CODE 6560-50-P

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Advanced A.I. technology developed exclusively by vLex editorially enriches legal information to make it accessible, with instant translation into 14 languages for enhanced discoverability and comparative research.
Over 2 million registered users

Founded over 20 years ago, vLex provides a first-class and comprehensive service for lawyers, law firms, government departments, and law schools around the world.

Subscribers are able to see the revised versions of legislation with amendments.

You can sign up for a trial and make the most of our service including these benefits.

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Why Sign-up to vLex?

Over 100 Countries

Search over 120 million documents from over 100 countries including primary and secondary collections of legislation, case law, regulations, practical law, news, forms and contracts, books, journals, and more.
Thousands of Data Sources

Updated daily, vLex brings together legal information from over 750 publishing partners, providing access to over 2,500 legal and news sources from the world’s leading publishers.
Find What You Need, Quickly

Advanced A.I. technology developed exclusively by vLex editorially enriches legal information to make it accessible, with instant translation into 14 languages for enhanced discoverability and comparative research.
Over 2 million registered users

Founded over 20 years ago, vLex provides a first-class and comprehensive service for lawyers, law firms, government departments, and law schools around the world.

Subscribers are able to see any amendments made to the case.

You can sign up for a trial and make the most of our service including these benefits.

Request your trial

Why Sign-up to vLex?

Over 100 Countries

Search over 120 million documents from over 100 countries including primary and secondary collections of legislation, case law, regulations, practical law, news, forms and contracts, books, journals, and more.
Thousands of Data Sources

Updated daily, vLex brings together legal information from over 750 publishing partners, providing access to over 2,500 legal and news sources from the world’s leading publishers.
Find What You Need, Quickly

Advanced A.I. technology developed exclusively by vLex editorially enriches legal information to make it accessible, with instant translation into 14 languages for enhanced discoverability and comparative research.
Over 2 million registered users

Founded over 20 years ago, vLex provides a first-class and comprehensive service for lawyers, law firms, government departments, and law schools around the world.

Subscribers are able to see a visualisation of a case and its relationships to other cases. An alternative to lists of cases, the Precedent Map makes it easier to establish which ones may be of most relevance to your research and prioritise further reading. You also get a useful overview of how the case was received.

Request your trial

Why Sign-up to vLex?

Over 100 Countries

Search over 120 million documents from over 100 countries including primary and secondary collections of legislation, case law, regulations, practical law, news, forms and contracts, books, journals, and more.
Thousands of Data Sources

Updated daily, vLex brings together legal information from over 750 publishing partners, providing access to over 2,500 legal and news sources from the world’s leading publishers.
Find What You Need, Quickly

Advanced A.I. technology developed exclusively by vLex editorially enriches legal information to make it accessible, with instant translation into 14 languages for enhanced discoverability and comparative research.
Over 2 million registered users

Founded over 20 years ago, vLex provides a first-class and comprehensive service for lawyers, law firms, government departments, and law schools around the world.

Subscribers are able to see the list of results connected to your document through the topics and citations Vincent found.

You can sign up for a trial and make the most of our service including these benefits.

Request your trial

Why Sign-up to vLex?

Over 100 Countries

Search over 120 million documents from over 100 countries including primary and secondary collections of legislation, case law, regulations, practical law, news, forms and contracts, books, journals, and more.
Thousands of Data Sources

Updated daily, vLex brings together legal information from over 750 publishing partners, providing access to over 2,500 legal and news sources from the world’s leading publishers.
Find What You Need, Quickly

Advanced A.I. technology developed exclusively by vLex editorially enriches legal information to make it accessible, with instant translation into 14 languages for enhanced discoverability and comparative research.
Over 2 million registered users

Founded over 20 years ago, vLex provides a first-class and comprehensive service for lawyers, law firms, government departments, and law schools around the world.

Part II

You can sign up for a trial and make the most of our service including these benefits.

Why Sign-up to vLex?

Over 100 Countries

Thousands of Data Sources

Find What You Need, Quickly

Over 2 million registered users

You can sign up for a trial and make the most of our service including these benefits.

Why Sign-up to vLex?

Over 100 Countries

Thousands of Data Sources

Find What You Need, Quickly

Over 2 million registered users

You can sign up for a trial and make the most of our service including these benefits.

Why Sign-up to vLex?

Over 100 Countries

Thousands of Data Sources

Find What You Need, Quickly

Over 2 million registered users

You can sign up for a trial and make the most of our service including these benefits.

Why Sign-up to vLex?

Over 100 Countries

Thousands of Data Sources

Find What You Need, Quickly

Over 2 million registered users

You can sign up for a trial and make the most of our service including these benefits.

Why Sign-up to vLex?

Over 100 Countries

Thousands of Data Sources

Find What You Need, Quickly

Over 2 million registered users

Why Sign-up to vLex?

Over 100 Countries

Thousands of Data Sources

Find What You Need, Quickly

Over 2 million registered users

You can sign up for a trial and make the most of our service including these benefits.

Why Sign-up to vLex?

Over 100 Countries

Thousands of Data Sources

Find What You Need, Quickly

Over 2 million registered users