Electric utilities (Federal Power Act): Transmission service; undue discrimination and preference prevention,

 
CONTENT

[Federal Register: March 15, 2007 (Volume 72, Number 50)]

[Rules and Regulations]

[Page 12265-12531]

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

[DOCID:fr15mr07-22]

[[Page 12265]]

Part II

Department of Energy

Federal Energy Regulatory Commission

18 CFR Parts 35 and 37

Preventing Undue Discrimination and Preference in Transmission Service; Final Rule

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Parts 35 and 37

[Docket Nos. RM05-17-000 and RM05-25-000; Order No. 890]

Preventing Undue Discrimination and Preference in Transmission Service

Issued February 16, 2007.

AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Final rule.

SUMMARY: The Federal Energy Regulatory Commission is amending the regulations and the pro forma open access transmission tariff adopted in Order Nos. 888 and 889 to ensure that transmission services are provided on a basis that is just, reasonable and not unduly discriminatory or preferential. The final rule is designed to: Strengthen the pro forma open-access transmission tariff, or OATT, to ensure that it achieves its original purpose of remedying undue discrimination; provide greater specificity to reduce opportunities for undue discrimination and facilitate the Commission's enforcement; and increase transparency in the rules applicable to planning and use of the transmission system.

EFFECTIVE DATE: This rule will become effective May 14, 2007.

FOR FURTHER INFORMATION CONTACT: Daniel Hedberg (Technical Information), Office of Energy Markets and Reliability, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-6243.

W. Mason Emnett (Legal Information), Office of the General Counsel--Energy Markets, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-6540.

Kathleen Barr[oacute]n (Legal Information), Office of the General Counsel--Energy Markets, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, (202) 502-6461.

SUPPLEMENTARY INFORMATION:

Paragraph Table of Contents

Nos.

I. Introduction.............................................

1 II. Background..............................................

9

A. Historical Antecedent................................

9

B. Order No. 888 and Subsequent Reforms.................

14

C. EPAct 2005 and Recent Developments...................

22 III. Need for Reform of Order No. 888.......................

26

A. Opportunities for Undue Discrimination Continue to

26 Exist..................................................

B. Lack of Transparency Undermines Confidence in Open

44 Access and Impedes Enforcement of Open Access Requirements...........................................

C. Congestion and Inadequate Infrastructure Development

52 Impede Customers' Use of the Grid......................

D. A Consistent Method of Measuring ATC Is Needed.......

62

E. Discriminatory Pricing of Imbalances.................

70

F. Redispatch/Conditional Firm..........................

73

G. EPAct 2005 Emphasized Certain Policies and Priorities

79 for the Commission..................................... IV. Summary, Scope and Applicability of the Final Rule......

82

A. Summary of Reforms...................................

83

B. Core Elements of Order No. 888 That Are Retained.....

91 1. Federal/State Jurisdiction.......................

92 2. Native Load Protection...........................

95 3. The Types of Transmission Services Offered.......

110 4. Functional Unbundling............................

117

C. Applicability of the Final Rule......................

124 1. Non-ISO/RTO Public Utility Transmission Providers

124 2. ISO and RTO Public Utility Transmission Providers

143 and Transmission Owner Members of ISOs and RTOs.... 3. Non-Public Utility Transmission Providers/

162 Reciprocity........................................ V. Reforms of the OATT......................................

193

A. Consistency and Transparency of ATC Calculations.....

193

B. Coordinated, Open and Transparent Planning...........

418

C. Transmission Pricing.................................

603 1. General..........................................

603 2. Energy and Generation Imbalances.................

627 3. Credits for Network Customers....................

729 4. Capacity Reassignment............................

778 5. ``Operational'' Penalties........................

826 a. Unreserved Use Penalties.....................

826 b. Distribution of Operational Penalties........

850 c. Applicability of Operational Penalties

866 Proposal to RTOs and Other Independent or Non- Profit Entities................................ 6. ``Higher of'' Pricing Policy.....................

870 7. Other Ancillary Services.........................

886

D. Non-Rate Terms and Conditions........................

901 1. Modifications to Long-Term Firm Point-to-Point

901 Service............................................ a. Planning Redispatch and Conditional Firm

901 Options........................................ b. Proposals for Transparent Redispatch.........

1095 c. Other Requested Service Modifications........

1165 2. Hourly Firm Service..............................

1177 3. Rollover Rights..................................

1214 4. Modification of Receipt or Delivery Points.......

1268 5. Acquisition of Transmission Service..............

1296 a. Processing of Service Requests...............

1296 b. Reservation Priority.........................

1394 6. Designation of Network Resources.................

1432 a. Qualification as a Network Resource..........

1432

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b. Documentation for Network Resources..........

1507 c. Undesignation of Network Resources...........

1534 7. Clarifications Related to Network Service........

1592 a. Secondary Network Service....................

1592 b. Behind the Meter Generation..................

1614 8. Transmission Curtailments........................

1620 9. Standardization of Rules and Practices...........

1633 a. Business Practices...........................

1633 b. Liability and Indemnification................

1662 10. OATT Definitions................................

1678

E. Enforcement..........................................

1714 1. General Policy...................................

1715 2. Civil Penalties..................................

1724 VI. Information Collection Statement........................

1752 VII. Environmental Analysis.................................

1758 VIII. Regulatory Flexibility Act Analysis...................

1759 IX. Document Availability...................................

1760 X. Effective Date and Congressional Notification............

1763 Appendix A: Summary of Compliance Filing Requirements Appendix B: Commenting Party Acronyms Appendix C: Pro Forma Open Access Transmission Tariff

Before Commissioners: Joseph T. Kelliher, Chairman; Suedeen G. Kelly, Marc Spitzer, Philip D. Moeller, and Jon Wellinghoff.

I. Introduction

1. This Final Rule addresses and remedies opportunities for undue discrimination under the pro forma Open Access Transmission Tariff (OATT) adopted in 1996 by Order No. 888.\1\ This landmark rulemaking fostered greater competition in wholesale power markets by reducing barriers to entry in the provision of transmission service. In the ten years since Order No. 888, however, the Commission has found that the OATT contains flaws that undermine realizing its core objective of remedying undue discrimination. In the Notice of Proposed Rulemaking (NOPR) issued on May 19, 2006, the Commission proposed to remedy those flaws.\2\ After receiving approximately 6,500 pages of comments from close to 300 parties, we now take final action. We highlight below the most critical reforms being adopted today.

\1\ Promoting Wholesale Competition Through Open Access Non- discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888, 61 FR 21540 (May 10, 1996), FERC Stats. & Regs. Sec. 31,036 (1996), order on reh'g, Order No. 888-A, 62 FR 12274 (Mar. 14, 1997), FERC Stats. & Regs. Sec. 31,048 (1997), order on reh'g, Order No. 888-B, 81 FERC Sec. 61,248 (1997), order on reh'g, Order No. 888-C, 82 FERC Sec. 61,046 (1998), aff'd in relevant part sub nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000) (TAPS v. FERC), aff'd sub nom. New York v. FERC, 535 U.S. 1 (2002).

\2\ Preventing Undue Discrimination and Preference in Transmission Service, Notice of Proposed Rulemaking, 71 FR 32,636 (Jun. 6, 2006), FERC Stats. & Regs. Sec. 32,603 (2006).

2. First, the Final Rule will increase nondiscriminatory access to the grid by eliminating the wide discretion that transmission providers currently have in calculating available transfer capability (ATC).\3\ The calculation of ATC is one of the most critical functions under the OATT because it determines whether transmission customers can access alternative power supplies. Despite this, the existing OATT does not prescribe how ATC should be calculated because the Commission sought to rely on voluntary efforts by the industry to develop consistent methods of ATC calculation. This voluntary industry effort has not proven successful. The Commission therefore acts today to require public utilities, working through the North American Electric Reliability Corporation (NERC), to develop consistent methodologies for ATC calculation and to publish those methodologies to increase transparency. This important reform will eliminate the wide discretion that exists today in calculating ATC and ensure that customers are treated fairly in seeking alternative power supplies.

\3\ The Commission used the term ``Available Transmission Capability'' in Order No. 888 to describe the amount of additional capability available in the transmission network to accommodate additional requests for transmission services. To be consistent with the term generally accepted throughout the industry, the Commission revises the pro forma OATT to adopt the term ``Available Transfer Capability.''

3. Second, the Final Rule will increase the ability of customers to access new generating resources and promote efficient utilization of transmission by requiring an open, transparent, and coordinated transmission planning process. Transmission planning is a critical function under the pro forma OATT because it is the means by which customers consider and access new sources of energy and have an opportunity to explore the feasibility of non-transmission alternatives. Despite this, the existing pro forma OATT provides limited guidance regarding how transmission customers are treated in the planning process and provides them very little information on how transmission plans are developed. These deficiencies are serious, given the substantial need for new infrastructure in this Nation.\4\ We act today to remedy these deficiencies by requiring transmission providers to open their transmission planning process to customers, coordinate with customers regarding future system plans, and share necessary planning information with customers.

\4\ Congress placed special emphasis on the development of transmission infrastructure, including the consideration of advanced transmission technologies, in the Energy Policy Act of 2005 (EPAct 2005). See Pub. L. 109-58, 119 Stat. 594 (to be codified in scattered titles of the U.S.C.). The Commission has taken steps to implement that goal in numerous contexts, including recent rulemaking proceedings that address the promotion of transmission investment through pricing reform and the siting of certain transmission facilities. See Promoting Transmission Investment through Pricing Reform, Order No. 679, 71 FR 43294 (Jul. 31, 2006), FERC Stats. & Regs. Sec. 31,222 (2006), order on reh'g, Order No. 679-A, 72 FR 1152 (Jan. 10, 2007), FERC Stats. & Regs. Sec. 31,236 (2007), reh'g pending; Regulations for Filing Applications for Permits to Site Interstate Electric Transmission Facilities, Order No. 689, 71 FR 69440 (Dec. 1, 2006), FERC Stats. & Regs. Sec. 31,234 (2006), reh'g pending. As discussed herein, several actions taken in this Final Rule also relate to the need for investments in transmission infrastructure and are consistent with the Commission's responsibilities under EPAct 2005.

4. Third, the Final Rule will also increase the efficient utilization of

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transmission by eliminating artificial barriers to use of the grid. The existing pro forma OATT allows a transmission provider to deny a request for long-term point-to-point service if the request cannot be satisfied in only one hour of the requested term. This practice discourages the efficient use of the existing grid and precludes access to alternative power supplies. We reform this practice by requiring that a conditional firm option be offered to customers seeking long- term point-to-point service, i.e., conditional firm service. We also modify the redispatch obligations of transmission providers to increase the efficient utilization of the grid, while also ensuring that reliability to native load customers is maintained.

5. Fourth, by adopting these and other reforms, the Final Rule facilitates the use of clean energy resources such as wind power. Conditional firm service is particularly important to wind resources that can provide significant economic and environmental value even if curtailed under limited circumstances. Open and coordinated transmission planning will enhance the ability of customers to access clean energy resources as part of their future resource portfolio. The Final Rule also benefits clean energy resources by reforming energy and generator imbalance charges. These reforms are particularly important to intermittent resources such as wind power because these resources have limited ability to control their output and, hence, must be assured that imbalance charges are no more than required to provide appropriate incentives for prudent behavior.

6. Fifth, the Final Rule will strengthen compliance and enforcement efforts. We are increasing the transparency of pro forma OATT administration, thereby increasing the ability of customers and our Office of Enforcement to detect undue discrimination. We are adopting operational penalties for clear violations of an OATT, thereby enhancing compliance while also reducing the burdens on our Office of Enforcement. We are also increasing the clarity of many other OATT requirements, thereby facilitating compliance by transmission providers with our regulations. This Final Rule thus reflects the close integration of our Office of Enforcement into policy development at the Commission. Several of the reforms we adopt today are informed by our experience with OATT administration through oversight, audits, and investigations performed by the Office of Enforcement.

7. Finally, we modify and improve several provisions of the pro forma OATT using our experience over the past ten years and clarify others that have proven ambiguous. For example, we reform our rollover rights policy to ensure that the rights and obligations of rollover customers are consistent with the resulting obligations of transmission providers to plan and upgrade the system to accommodate rollovers. We remove the price cap on reassigned capacity because it is not necessary to remedy market power and doing so will otherwise increase the efficient use of existing capacity. We increase the efficient use of existing capacity by providing a priority to certain ``pre-confirmed'' requests for service. We increase certainty by providing greater clarity regarding the wholesale contracts that qualify as network resources. We also adopt numerous clarifications that should assist transmission providers and customers in implementing and using the pro forma OATT

8. Our actions in this proceeding have been informed to a great extent by the comments received in response to our notices of inquiry in the above-captioned dockets and the subsequent NOPR.\5\ We appreciate the time and thoughtfulness of all sectors of the industry in preparing comments. We have found them very informative and useful in reaching our decisions in this Final Rule.

\5\ Preventing Undue Discrimination and Preference in Transmission Services, Notice of Inquiry, 112 FERC ] 61,299 (2005) (NOI); Information Requirements for Available Transfer Capability, Notice of Inquiry, 111 FERC ] 61,274 (2005) (ATC NOI).

II. Background

A. Historical Antecedent

9. In the NOPR, the Commission explained the historical background that led up to the issuance of Order No. 888, and the initiation of this rulemaking proceeding. We repeat that history here to place in context the actions we take today.

10. In the first few decades after enactment of the Federal Power Act (FPA) in 1935, the industry was characterized mostly by self- sufficient, vertically integrated electric utilities, in which generation, transmission, and distribution facilities were owned by a single entity and sold as part of a bundled service to wholesale and retail customers. Most electric utilities built their own power plants and transmission systems, entered into interconnection and coordination arrangements with neighboring utilities, and entered into long-term contracts to make wholesale requirements sales (bundled sales of generation and transmission) to municipal, cooperative, and investor- owned utilities connected to each utility's transmission system. Each system covered a limited service area, which was defined by the retail franchise decisions of State regulatory agencies. This structure of separate systems arose naturally primarily due to cost and the technological limitations on the distance over which electricity could be transmitted.

11. A number of statutory, economic, and technological developments in the 1970s led to an increase in coordinated operations and competition. Among those was the passage of the Public Utility Regulatory Policies Act of 1978 (PURPA),\6\ which was designed to lessen dependence on foreign fossil fuels by encouraging the development of alternative generation sources and imposing a mandatory purchase obligation on utilities for generation from such sources. PURPA also enabled the Commission to order wheeling of electricity under limited circumstances.\7\ The rapid expansion and performance of the independent power industry following the enactment of PURPA demonstrated that traditional, vertically integrated public utilities need not be the only sources of reliable power. During this period, the profile of generation investment began to change, and a market for non- traditional power supply beyond the purchases required by PURPA began to emerge. The economic and technological changes in the transmission and generation sectors helped encourage many new entrants in the generating markets that could sell electric energy profitably with smaller scale technology at a lower price than many utilities selling from their existing generation facilities at rates reflecting cost. However, it became increasingly clear that the potential consumer benefits that could be derived from these technological advances could be realized only if more efficient generating plants could obtain access to the regional transmission grids. Because many traditional vertically integrated utilities still did not provide open access to third parties and favored their own generation if and when they

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provided transmission access to third parties, access to cheaper, more efficient generation sources remained limited.

\6\ Pub. L. 95-617, 92 Stat. 3117 (1978) (codified in U.S.C. titles 15, 16, 26, 30, 42, and 43).

\7\ Section 211 of the FPA, 16 U.S.C. 824j. In earlier years, a few customers were able to obtain access as a result of litigation, beginning with the U.S. Supreme Court's decision in Otter Tail Power Company v. United States, 410 U.S. 366 (1973). Additionally, some customers gained access by virtue of Nuclear Regulatory Commission license conditions and voluntary preference power transmission arrangements associated with Federal power marketing agencies. See, e.g., Consumers Power Co., 6 NRC 887, 1036-44 (1977); Toledo Edison Co., 10 NRC 265, 327-34 (1979); Florida Municipal Power Agency v. Florida Power and Light Co., 839 F. Supp. 1563 (M.D. Fla. 1993).

12. The Commission encouraged the development of independent power producers (IPPs), as well as emerging power marketers, by authorizing market-based rates for their power sales on a case-by-case basis, and by encouraging more widely available transmission access on a case-by- case basis. Market-based rates helped to develop competitive bulk power markets by allowing generating utilities to move more quickly and flexibly to take advantage of short-term or even long-term market opportunities than those utilities operating under traditional cost-of- service tariffs. In approving these market-based rates, the Commission required that the seller and its affiliates lack market power or mitigate any market power that they may have had.\8\ The major concern of the Commission was whether the seller or its affiliates could limit competition and thereby drive up prices. A key inquiry became whether the seller or its affiliates owned or controlled transmission facilities in the relevant service area and therefore, by denying access or imposing discriminatory terms or conditions on transmission service, could foreclose other generators from competing. Beginning in the late 1980s, in order to mitigate their market power to meet the Commission's conditions, public utilities seeking Commission authorization for blanket approval of market-based rates for generation services under section 205 of the FPA filed ``open access'' transmission tariffs of general applicability.\9\ The Commission also approved proposed mergers under section 203 of the FPA on the condition that the merging companies remedy anticompetitive effects potentially caused by the merger by filing ``open access'' tariffs. The early tariffs submitted in market-based rate proceedings under section 205 and merger proceedings under section 203 did not, however, provide access to the transmission system that was comparable to the service the transmission providers used for their own purposes. Rather, they typically made available only point-to-point transmission service, i.e., service from a single point of receipt to a single point of delivery. As these early tariffs were offered only by transmission providers that volunteered to provide service to third parties, they resulted in a patchwork of open access that was not sufficient to facilitate wholesale generation markets.

\8\ See, e.g., Dartmouth Power Associates Limited Partnership, 53 FERC ] 61,117 (1990); Commonwealth Atlantic Limited Partnership, 51 FERC ] 61,368 (1990); Doswell Limited Partnership, 50 FERC ] 61,251 (1990); Citizens Power & Light Co., 48 FERC ] 61,210 (1989); Ocean State Power, 44 FERC ] 61,261 (1988); and Orange and Rockland Utilities, Inc., 42 FERC ] 61,012 (1988).

\9\ See Order No. 888 at 31,644 n.52.

13. In response to the competitive developments following PURPA, and the fact that limited transmission access and significant regulatory barriers continued to constrain the development of generation by independent power producers, Congress enacted Title VII of the Energy Policy Act of 1992 (EPAct 1992).\10\ EPAct 1992 reduced regulatory barriers to entry by creating a class of ``Exempt Wholesale Generators'' that were exempt from the requirements of the Public Utility Holding Company Act of 1935.\11\ EPAct 1992 also expanded the Commission's authority to approve applications for transmission services under sections 211 and 212 of the FPA.\12\ Though the Commission aggressively implemented expanded section 211, it ultimately concluded that the procedural limitations in section 211 thwarted the Commission's ability to effectively eliminate undue discrimination in the provision of transmission service.

\10\ Pub. L. 102-486, 106 Stat. 2776 (1992) (codified at, among other places, 15 U.S.C. 79z-5a and 16 U.S.C. 796 (22-25), 824j-l).

\11\ 15 U.S.C. 79a, repealed by EPAct 2005 sec. 1263; see Repeal of the Public Utility Holding Company Act of 1935 and Enactment of the Public Utility Holding Company Act of 2005, Order No. 667, 70 FR 75592 (Dec. 20, 2005), FERC Stats. & Regs. ] 31,197 (2005), order on reh'g, Order No. 667-A, 71 FR 28446 (May 16, 2006), FERC Stats. & Regs. ] 31,213 (2006), order on reh'g, Order No. 667-B, 71 FERC 42750 (Jul. 28, 2006), FERC Stats. & Regs. ] 31,224 (2006), reh'g pending.

\12\ 16 U.S.C. 824j (authorizing the Commission to require transmission utilities to provide service in certain circumstances); 16 U.S.C. 824k (establishing rates for service provided pursuant to an order under section 211).

B. Order No. 888 and Subsequent Reforms

14. In April 1996, as part of its statutory obligation under sections 205 and 206 of the FPA to remedy undue discrimination, the Commission adopted Order No. 888 prohibiting public utilities from using their monopoly power over transmission to unduly discriminate against others. In that order, the Commission required all public utilities that own, control or operate facilities used for transmitting electric energy in interstate commerce to file open access non- discriminatory transmission tariffs that contained minimum terms and conditions of non-discriminatory service. It also obligated such public utilities to ``functionally unbundle'' their generation and transmission services. This meant public utilities had to take transmission service (including ancillary services) for their own new wholesale sales and purchases of electric energy under the open access tariffs, and to separately state their rates for wholesale generation, transmission and ancillary services.\13\ Each public utility was required to file the pro forma OATT included in Order No. 888 without any deviation (except a limited number of terms and conditions that reflect regional practices).\14\ After the effectiveness of their OATTs, public utilities were allowed to file, pursuant to section 205 of the FPA, deviations that were consistent with or superior to the pro forma OATT's terms and conditions. Because certain owners, controllers or operators of interstate transmission facilities were not subject to the Commission's jurisdiction under sections 205 and 206 and thus were not subject to Order No. 888, the Commission adopted a reciprocity provision in the pro forma OATT that conditions the use by a non-public utility of a public utility's open access services on an agreement to offer non-discriminatory transmission services in return.

\13\ This is known as ``functional unbundling'' because the transmission element of a wholesale sale is separated or unbundled from the generation element of that sale, although the public utility may provide both functions. See infra section IV.B.4 of this Final Rule.

\14\ See Order No. 888 at 31,769-70 (noting that the pro forma OATT expressly identified certain non-rate terms and conditions, such as the time deadlines for determining available transfer capability in section 18.4 or scheduling changes in sections 13.8 and 14.6, that may be modified to account for regional practices if such practices are reasonable, generally accepted in the region, and consistently adhered to by the transmission provider).

15. In addition to imposing the functional unbundling requirement, the Commission also encouraged broader reforms through the formation of independent system operators (ISOs). The Commission stated that ISOs can provide significant benefits such as enhancing regional efficiencies and further remedying undue discrimination.\15\ While the Commission declined to mandate ISOs, it set forth eleven principles for assessing ISO proposals submitted to the Commission.\16\

\15\ Order No. 888 at 31,655.

\16\ Id. at 31,730-32.

16. Order No. 888 also clarified the Commission's interpretation of the Federal and State jurisdictional boundaries over transmission and local distribution. While Order No. 888 reaffirmed that the Commission has exclusive jurisdiction over the rates,

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terms, and conditions of unbundled retail transmission in interstate commerce by public utilities, it nevertheless recognized the legitimate concerns of State regulatory authorities regarding the transmission component of bundled retail sales. The Commission therefore declined to extend its unbundling requirement to the transmission component of bundled retail sales. On appeal, the U.S. Supreme Court affirmed this element of Order No. 888, finding that the Commission made a statutorily permissible choice.\17\

\17\ New York v. FERC, 535 U.S. 1 (2002).

17. The same day it issued Order No. 888, the Commission issued a companion order, Order No. 889,\18\ addressing the separation of vertically integrated utilities' transmission and merchant functions, the information transmission providers were required to make public, and the electronic means they were required to use to do so. Order No. 889 imposed Standards of Conduct governing the separation of, and communications between, the utility's transmission and wholesale power functions, to prevent the utility from giving its merchant arm preferential access to transmission information. All public utilities that owned, controlled or operated facilities used in the transmission of electric energy in interstate commerce were required to create or participate in an Open Access Same-Time Information System (OASIS) that was to provide existing and potential transmission customers the same access to transmission information.

\18\ Open Access Same-Time Information System (Formerly Real- Time Information Networks) and Standards of Conduct, Order No. 889, 61 FR 21737 (May 10, 1996), FERC Stats. & Regs. ] 31,035 (1996), order on reh'g, Order No. 889-A, FERC Stats. & Regs. ] 31,049 (1997), order on reh'g, Order No. 889-B, 81 FERC ] 61,253 (1997).

18. Among the information public utilities were required to post on their OASIS was the transmission provider's calculation of ATC. Though the Commission acknowledged that before-the-fact measurement of the availability of transmission service is ``difficult,'' it concluded that it was important to give potential transmission customers ``an easy-to-understand indicator of service availability.'' \19\ Because formal methods did not then exist to calculate ATC and total transfer capability (TTC), the Commission encouraged industry efforts to develop consistent methods for calculating ATC and TTC.\20\ Order No. 889 ultimately required transmission providers to base their calculations on ``current industry practices, standards and criteria'' and to describe their methodology in their tariffs.\21\ The Commission noted that the requirement that transmission providers purchase only ATC that is posted as available ``should create an adequate incentive for them to calculate ATC and TTC as accurately and as uniformly as possible.'' \22\

\19\ Order No. 889 at 31,605.

\20\ Id. at 31,607.

\21\ Id.

\22\ Id.

19. The electric industry continued to undergo economic and regulatory changes in the years following the issuance of Order No. 888. Retail access was adopted by approximately 25 states in the late 1990s.\23\ This State restructuring activity spurred significant changes at the wholesale level as well by encouraging or requiring the divestiture of generation plants by traditional electric utilities and the development of ISOs that could manage short-term energy markets necessary to support retail access. At the same time, there was a significant increase in the number of mergers between traditional electric utilities and between electric utilities and gas pipeline companies, and large increases in the number of power marketers and independent generation facility developers entering the marketplace. Trade in bulk power markets increased significantly and the Nation's transmission grid was used more heavily and in new ways as customers took advantage of the pro forma OATT and purchased power from competitive sellers.

\23\ See Energy Information Administration, Retail Unbundling-- U.S. Summary (2005), http://www.eia.doe.gov/oil_gas/natural_gas/restructure/state/us.html .

20. In the wake of these changes, in December 1999, the Commission adopted Order No. 2000.\24\ That rulemaking recognized that Order No. 888 set the foundation upon which competitive electric markets could develop, but did not eliminate the potential to engage in undue discrimination and preference in the provision of transmission service.\25\ The rulemaking also recognized that Order No. 888 did not address the regional nature of the grid, including the treatment of parallel flows, pancaked rates, and congestion management. Thus, the Commission encouraged the creation of RTOs to address important operational and reliability issues and eliminate any residual discrimination in transmission services that can occur when the operation of the transmission system remains in the control of a vertically integrated utility. The Commission found that RTOs would increase the efficiency of wholesale markets by eliminating pancaked rates, internalizing parallel flow, managing congestion efficiently, and operating markets for energy, capacity and ancillary services. The Commission established an open, collaborative process that relied on voluntary regional participation to design RTOs tailored to the specific needs of each region. The Commission noted, however, that ``[i]f the industry fails to form RTOs under this approach, the Commission will reconsider what further regulatory steps are in the public interest.''\26\

\24\ Regional Transmission Organizations, Order No. 2000, 65 FR 809 (Jan. 6, 2000), FERC Stats. & Regs. ] 31,089 (1999), order on reh'g, Order No. 2000-A, 65 FR 12088 (Mar. 8, 2000), FERC Stats. & Regs. ] 31,092 (2000), aff'd sub nom. Public Utility District No. 1 of Snohomish County, Washington v. FERC, 272 F.3d 607 (D.C. Cir. 2001).

\25\ Order No. 2000 at 31,015.

\26\ Id. at 30,993.

21. Following Order No. 2000, RTOs were approved in several regions of the country including the Northeast (PJM; ISO New England),\27\ the Midwest (MISO) and the South (SPP). In most cases, RTOs have assumed responsibility for calculating ATC across the footprint of the RTO, as well as the planning and expansion of the transmission grid, at least for facilities necessary for maintaining system reliability. However, large areas of the Nation have not developed RTOs using the voluntary structure adopted by the Commission in Order No. 2000. Moreover, transmission customers have complained that even in RTO markets there are instances when comparable transmission service is not provided, particularly in the area of transmission planning.

\27\ A list of commenter acronyms can be found in Appendix B.

C. EPAct 2005 and Recent Developments

22. Enacted on August 8, 2005, EPAct added a number of new authorities and priorities for the Commission and emphasized certain of its existing obligations. Among other things, EPAct 2005 recognized the importance of adequate transmission infrastructure development and its role in facilitating the development of competitive wholesale markets. The Congressional directives in EPAct 2005 are intended to reverse the decline in transmission infrastructure investment. For example, Congress required the Commission to adopt a rule establishing incentive ratemaking for transmission infrastructure to help promote reliability and reduce congestion.\28\ Congress also

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directed the Commission to encourage the deployment of advanced technologies.\29\ Congress further directed the Commission to ``exercise its authority'' under EPAct 2005 ``in a manner that facilitates the planning and expansion of transmission facilities to meet the reasonable needs of load-serving entities.''\30\ Congress also gave the Commission certain ``backstop'' transmission siting authority, and authorized the creation of interstate compacts establishing transmission siting agencies.\31\ EPAct 2005 also authorized the Commission to require unregulated transmitting utilities (except for certain small entities) to provide access to their transmission facilities on a comparable basis.\32\ Congress further ordered the Department of Energy (DOE) to study the benefits of economic dispatch and required the Commission to convene regional joint boards to develop a report to Congress containing recommendations for the use of security constrained economic dispatch within each region.\33\ Congress also directed the Commission to facilitate price transparency in markets for the sale and transmission of electric energy in interstate commerce, having due regard for the public interest, the integrity of those markets, fair competition, and the protection of consumers, and it authorized the Commission to prescribe rules to provide for the dissemination of information about the availability and price of wholesale electric energy and transmission service.\34\ Finally, Congress emphasized compliance with the Commission's regulations, adopting and increasing the civil and criminal penalties for violations of Commission-administered statutes and regulations.\35\

\28\ EPAct 2005 sec. 1241 (to be codified at section 219 of the FPA, 16 U.S.C. 824s).

\29\ EPAct 2005 sec. 1223 (to be codified at 42 U.S.C. 16422). Indeed, Congress provided specific guidance as to the types of advanced technologies that should be encouraged in infrastructure improvements to include, among others, optimized transmission line configurations (including multiple phased transmission lines), controllable load, distributed generation (including PV, fuel cells, and microturbines), and enhanced power device monitoring. Id.

\30\ EPAct 2005 sec. 1233(a) (to be codified at section 217(b)(4) of the FPA, 16 U.S.C. 824q).

\31\ EPAct 2005 sec. 1221(a) (to be codified at section 216 of the FPA, 16 U.S.C. 824p).

\32\ EPAct 2005 sec. 1231 (to be codified at section 211A of the FPA, 16 U.S.C. 824j-1)

\33\ EPAct 2005 sec. 1234 (to be codified at 42 U.S.C. 16432); EPAct 2005 sec. 1298 (to be codified at section 223 of the FPA, 16 U.S.C. 824w). EPAct 2005 sec. 1234(b) defined economic dispatch as ``the operation of generation facilities to produce energy at the lowest cost to reliably serve consumers, recognizing any operational limits of generation and transmission facilities.''

\34\ EPAct 2005 sec. 1281 (to be codified at section 220 of the FPA, 16 U.S.C. 824t).

\35\ EPAct 2005 sec. 1284(d) (to be codified at section 316 of the FPA, 16 U.S.C. 825o); EPAct 2005 sec. 1284(e) (to be codified at section 316A of the FPA, 16 U.S.C. 825o-1).

23. Recognizing the need for reform of Order No. 888 in light of the Commission's continuing concern regarding whether the pro forma OATT adequately remedies undue discrimination, the Commission issued an NOI on September 16, 2005 \36\ seeking comments on appropriate reforms of the Order No. 888 pro forma OATT. In the NOI, the Commission expressed its preliminary view that reforms to the pro forma OATT and public utilities' OATTs are necessary to avoid undue discrimination or preference in the provision of transmission service. The NOI sought comments on how best to accomplish the Commission's goals, specifically with respect to enhancements that are needed to (1) Remedy any unduly discriminatory or preferential application of the pro forma OATT or (2) improve the clarity of the Order No. 888 pro forma OATT and the individual public utility tariffs in order to more readily identify violations and facilitate compliance.

\36\ See supra note 5.

24. The Commission received over 4,000 pages of initial and reply comments on the NOI. Based on these comments, the comments submitted in response to the ATC NOI,\37\ our experience in implementing Order No. 888, and the changes in the industry since we adopted it, the Commission proposed to reform the pro forma OATT in a number of ways. The Commission issued the NOPR on May 19, 2006 proposing a number of reforms aimed at remedying undue discrimination in the provision of open access transmission service and improving the clarity of the pro forma OATT and the individual tariffs of transmission providers in order to more readily identify violations and facilitate compliance. The Commission received over 5,700 pages of initial and reply comments in response. In response to comments on the particular issue of redispatch and conditional firm service (discussed in more detail below), the Commission issued a Notice of Request for Supplemental Comments on November 15, 2006,\38\ that resulted in receipt of an additional 750 pages of comments.

\37\ Id.

\38\ Preventing Undue Discrimination and Preference in Transmission Service, 117 FERC ] 61,185 (2006).

25. Based on this voluminous record, the Commission concludes that reform of the pro forma OATT and associated amendments to its regulations are necessary to reduce the potential for undue discrimination and provide clarity in the obligations of transmission providers and customers alike. We turn next to a more complete explanation of this need for reform.

III. Need for Reform of Order No. 888

A. Opportunities for Undue Discrimination Continue To Exist

26. Although Order No. 888 has been successful in many important respects, the need for reform of the Order No. 888 pro forma OATT has been apparent for some time. In 1999, the Commission held, in adopting Order No. 2000, that the pro forma OATT could not fully remedy undue discrimination because transmission providers retained both the incentive and the ability to discriminate against third parties, particularly in areas where the pro forma OATT left the transmission provider with significant discretion.\39\ The Commission made a similar finding in Order No. 2003,\40\ holding that opportunities for undue discrimination continue to exist in areas where the pro forma OATT leaves transmission providers with substantial discretion.\41\ The NOPR reaffirmed these findings, preliminarily concluding that opportunities for undue discrimination continue to exist in the provision of open access transmission service. The Commission therefore proposed a number of reforms to the pro forma OATT to address the opportunities and incentives transmission providers have to unduly discriminate.

\39\ Order No. 2000 at 31,105.

\40\ See Standardization of Generator Interconnection Agreements and Procedures, Order No. 2003, 68 FR 49845 (Aug. 19, 2003), FERC Stats. & Regs. ] 31,146 at P 11-12 (2003), order on reh'g, Order No. 2003-A, 69 FR 15932 (Mar. 26, 2004), FERC Stats. & Regs. ] 31,160 (2004), order on reh'g, Order No. 2003-B, 70 FR 265 (Jan. 4, 2005), FERC Stats. & Regs. ] 31,171 (2004), order on reh'g, Order No. 2003- C, 70 FR 37,661 (Jun. 30, 2005), FERC Stats. & Regs. ] 31,190 (2005), aff'd sub nom. National Association of Regulatory Utility Commissioners v. FERC, No. 04-1148, 2007 U.S. App. LEXIS 626 (D.C. Cir. Jan. 12, 2007).

\41\ Order No. 2003 at P 11-12.

Comments

27. Many commenters agree with the Commission that reforms to the pro forma OATT are needed because there continue to be both the opportunity and incentive for transmission providers to engage in undue discrimination.\42\

\42\ E.g., APPA, EPSA, East Texas Cooperatives, Fayetteville, NRG, Occidental, TAPS, TDU Systems, Williams, Entegra Reply, and NRECA Reply.

28. Several commenters offered examples of their experiences with transmission providers, where they believe transmission providers have acted in an unduly discriminatory

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fashion.\43\ Constellation claims that on multiple occasions it has been denied a transmission request when the transmission provider's OASIS indicates that ATC is available, but Constellation had no effective and timely way to challenge that determination because of the ATC ``black box.'' Constellation states that given that its needs for transmission service are often near-term or immediate--e.g., to facilitate a load-serving obligation or wholesale transaction that must be consummated quickly--seeking redress at the Commission for improperly denied service generally is not time- or cost-effective. Instead, Constellation asserts, it is often forced to accept the determination of the transmission provider that ATC is not available (even though its OASIS may indicate otherwise) and seek alternate transmission paths and/or products to consummate its transaction.

\43\ See, e.g., Dow, Fayetteville, Occidental, and Williams.

29. Powerex also describes instances where a transmission provider has granted short-term firm point-to-point transmission service requests to transmission customers who have been allowed to remain in the queue, even when zero ATC is posted, in the hopes that a transmission provider's OASIS site wrongly indicates zero ATC or will soon be updated. Powerex asserts that such practices clog the short- term point-to-point transmission queue with multiple requests and result in duplicative requests for service that reflect customers' attempts to secure service, rather than the actual quantity of service needed. Moreover, Powerex argues, transmission provider discretion in this area and the lack of transparency raise customer concerns about preferential treatment.

30. Occidental claims that it has first-hand experience with a vertically integrated transmission provider that, despite having an OATT, appears to have persistently used its transmission system to preferentially benefit its merchant function. Similarly, Williams alleges that its interests have been consistently and significantly compromised by the discretion afforded transmission providers in the interpretation of the OATT and the lack of transparency in requesting, scheduling and interrupting of transmission service.

31. Other commenters, however, argue that the Commission's proposed reforms are based on unsupported allegations of undue discrimination. EEI maintains that any opportunities to engage in undue discrimination have been largely mitigated by current regulatory policies and changes in the industry. EEI explains that, unlike the situation that existed when the Commission enacted Order No. 888, much of the country's transmission facilities are now under the control of RTOs and ISOs. In addition, EEI states, other transmission providers have transferred (or are in the process of transferring) the administration of their OATTs and OASIS functions to independent transmission service coordinators. Even among the transmission providers who have taken neither of those steps, EEI argues that the open access requirements of Order No. 888 and the Standards of Conduct of Order Nos. 889 and 2004 have largely eliminated the ability of transmission providers to engage in undue discrimination in the provision of transmission service.\44\ In addition, EEI states, the Commission's expanded civil penalty authority added to the FPA by EPAct 2005 gives the Commission a powerful tool that will further eliminate any remaining incentive of transmission providers to engage in undue discrimination in the provision of transmission service. Therefore, EEI asserts, any modifications to the OATT should be narrowly tailored to address the perceptions of residual undue discrimination. To the extent that such perceptions exist, however, Community Power Alliance states that, in the absence of concrete record evidence, they are just that--perceptions.

\44\ See also Southern Reply.

32. Although Duke strongly supports, as a policy matter, OATT reforms that will eliminate the perception that undue discrimination is possible and/or likely, Duke argues that the FPA does not provide the Commission the authority to remedy mere ``opportunities'' to discriminate. Duke states that, in some cases, the Commission is attempting to remedy an opportunity for undue discrimination that does not exist or is proposing to impose a remedy that does not actually remedy the perceived opportunity. Duke notes, however, that some OATT terms and conditions are subject to multiple interpretations and argues that the Commission can, and should, justify the OATT reforms proposed in the NOPR as reforms needed to provide clarity to existing policies.

33. With regard to specific allegations made by commenters, several transmission providers respond that the examples given by transmission customers do not illustrate instances of undue discrimination. Rather, they assert, these examples demonstrate the transmission customers' lack of understanding of the OATT requirements, and the data available on OASIS.\45\

\45\ See, e.g., Entergy Reply, Progress Energy Reply, and Southern Reply.

34. New Mexico Attorney General argues that the traditional State- regulated, vertically-integrated cost-of-service world is not in need of reform. Contrary to the ``conspiracy theorists'' who argue that utilities have an incentive to engage in undue discrimination and preference in transmission services, New Mexico Attorney General asserts that utilities have an incentive to maximize throughput and revenue between State-level rate cases because incremental transmission revenue is not deducted from the State-jurisdictional retail revenues between rate cases. Similarly, Southern, in its reply comments, asserts that broad claims of undue discrimination fail to take into consideration that vertically-integrated utilities have more of an incentive to act appropriately than do independent utilities because the former have more to lose (e.g., loss of market-based rates, state prudence reviews of costs, etc.) if they are found to have engaged in wrong-doing. Southern states that any OATT revisions ultimately adopted by the Commission must be reasonably tailored to address an identified problem or to provide a specific improvement.

35. Other commenters argue that the Commission's focus should be on transmission providers in non-organized markets, arguing that remaining concerns about undue discrimination have already been addressed in the world of ISOs and RTOs.\46\ According to ISO/RTO Council, this proceeding provides an opportunity for the Commission to harmonize the worlds of organized and non-organized markets in a manner that encourages competition, promotes non-discriminatory access, and maximizes the flow of electricity across various ISO/RTO and non-ISO/ RTO regions. ISO/RTO Council states that, in the existing regulatory environment, a utility that is not a member of an ISO or RTO can sell into, or purchase from, an ISO or RTO market even though the non-ISO/ RTO utility operates under tariff rules that are less open and transparent, particularly in terms of access to generation resources and pricing/system information, than their competitors that belong to an ISO or RTO. Such asymmetry, ISO/RTO Council argues, operates as an

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impediment to fair and non-discriminatory transmission access and management of grid congestion.

\46\ E.g., Indicated New York Transmission Owners, ISO/RTO Council, and Northeast Utilities.

36. ISO/RTO Council states that its members do not seek to impose their market designs on the rest of the nation. At the same time, ISO/ RTO Council argues that meaningful reform should ensure a level of transparency (of both price and the dispatch utilized by non-ISO/RTO vertically-integrated entities) in regions without an ISO or RTO that can assist the flow of electricity and enhance reliability and planning in both ISO/RTO and non-ISO/RTO regions.

37. Exelon urges the Commission to hold the transmission providers outside ISOs or RTOs to the same standard of non-discrimination that exists within those organizations. Further, MISO/PJM States argue that in order to achieve some level of independence in non-RTO regions, non- independent transmission providers should be encouraged to turn over operational control of their transmission systems to an independent coordinator of transmission whose functions would include security coordination, determination of ATC, granting of transmission service and oversight for transmission planning.

38. Finally, EPSA suggests that the Commission establish a one-year review period for the reformed pro forma OATT. EPSA urges the Commission to revisit this Final Rule after one year of operation under the reformed pro forma OATT to ensure that the revisions adopted here do, in fact, protect against non-discriminatory or preferential behavior by transmission providers. NRECA responds that, after this comprehensive rulemaking process, there is simply no need for another major look at the OATT in one year. Moreover, NRECA states, one year is likely too short a period for the Commission and industry participants to fully appreciate all of the consequences of those elements of OATT reform resulting from this proceeding. At the same time, NRECA agrees that the Commission should carefully monitor implementation of the reformed OATT. This monitoring, NRECA states, must be an ongoing process and cannot wait a year to begin. Commission Determination

39. The Commission concludes that reforms are needed to address deficiencies in the pro forma OATT that have become apparent since 1996, by limiting remaining opportunities for undue discrimination. As the Commission found in Order No. 888, it is in the economic self- interest of transmission monopolists, particularly those with high-cost generation assets, to deny transmission or to offer transmission on a basis that is inferior to that which they provide to themselves.\47\ Such an incentive can lead to unduly discriminatory behavior against third parties, particularly if public utilities have unnecessarily broad discretion in the application of their tariffs. This discretion also can create problems for transmission providers seeking to comply with our regulations in good faith because so many issues are left for their interpretation, thereby increasing the possibility of disputes with transmission customers and enforcement actions by the Commission.\48\ Transmission customers also have found ways to use the tariffs to their own advantage, particularly in the scheduling and queuing processes.\49\

\47\ Order No. 888 at 31,682.

\48\ See, e.g., Order No. 2003 at P 11-12.

\49\ See, e.g., Potomac Economics, Ltd., 2004 State of the Market Report: Midwest ISO at 30-31, 34-35 (Jun. 2005), http://www.midwestmarket.org/publish/Document/2b8a32_103ef711180_-7bf20a48324a/2004%20MISO%20SOM%20Report.pdf?action=download&_property=Attachment (explaining that the queuing process, by giving

eport.pdf?action=download&_property=Attachment (explaining that the queuing process, by giving

provides a low- or no-cost option that restricts other customers' access to congested interfaces, and the scheduling process, by allowing customers to leave transmission requests unconfirmed, provides a free option that may invite hoarding or result in underutilized capacity).

40. As some commenters note, opportunities for undue discrimination persist, particularly in areas where the pro forma OATT leaves the transmission provider with substantial discretion. The Commission has a responsibility under section 206 of the FPA to remedy undue discrimination. Indeed, the court concluded in Associated Gas Distributors v. FERC,\50\ that, like the Natural Gas Act,\51\ the FPA ``fairly bristles'' with concern over undue discrimination. Based on AGD, the Commission determined in Order No. 888 that:

\50\ 824 F.2d 981 (D.C. Cir. 1987) (AGD).

\51\ 15 U.S.C. 717.

The Commission has a mandate under sections 205 and 206 of the FPA to ensure that, with respect to any transmission in interstate commerce or any sale of electric energy for resale in interstate commerce by a public utility, no person is subject to any undue prejudice or disadvantage. We must determine whether any rule, regulation, practice or contract affecting rates for such transmission or sale for resale is unduly discriminatory or preferential, and must prevent those contracts and practices that do not meet this standard. * * * AGD demonstrates that our remedial power is very broad and includes the ability to order industry-wide non-discriminatory open access as a remedy for undue discrimination.

Order No. 888 at 31,669. Through this Final Rule, the Commission exercises that remedial authority again to limit further opportunities for undue discrimination, by minimizing areas of discretion, addressing ambiguities and clarifying various aspects of the pro forma OATT.

41. We disagree with commenters who assert that the Commission is relying on unsubstantiated allegations of discriminatory conduct to justify OATT reform. The courts have made clear that the Commission need not make specific factual findings of discrimination in order to promulgate a generic rule to eliminate undue discrimination.\52\ In AGD, the court explained that the promulgation of generic rate criteria involves the determination of policy goals and the selection of the means to achieve them and that courts do not insist on empirical data for every proposition upon which the selection depends: ``[a]gencies do not need to conduct experiments in order to rely on the prediction that an unsupported stone will fall.'' \53\ During this multi-year proceeding, the Commission has received many comments arguing that commenters have either experienced or perceived that they have experienced unduly discriminatory conduct by transmission providers. Even transmission providers have acknowledged that there is a continuing perception that there is the opportunity for them to unduly discriminate against their competitors and, accordingly, they state their support for our reform effort.\54\ Moreover, it is undisputed that the existing pro forma OATT provides wide discretion in implementing some of its basic requirements, such as the assessment of whether sufficient ATC exists to grant third party access to the grid and the manner in which new facilities are planned to satisfy third party needs. This wide discretion, when coupled with a transmission provider's incentive to discriminate, creates opportunities for discrimination under the pro forma OATT. We have an obligation under section 206 to remedy that discrimination.

\52\ TAPS v. FERC, 225 F.3d at 667, 688; National Fuel Gas Supply Corp. v. FERC, 468 F.3d 831 (D.C. Cir. 2006) (National Fuel).

\53\ 824 F.2d at 1008.

\54\ See, e.g., Duke and EEI.

42. It is thus clear to us that, notwithstanding the Commission's efforts in Order No. 888, opportunities to engage in undue discrimination can and will persist unless the existing pro forma OATT is reformed. We therefore exercise our broad remedial authority today to limit these remaining

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opportunities for undue discrimination. The Commission concludes that any additional costs incurred by transmission providers to implement the reforms required in this Final Rule are fully justified by the need to ensure open, transparent and non-discriminatory access to transmission service. We also believe it is appropriate to adopt these reforms by rulemaking, rather than rely on complaints filed by transmission customers or other parties. Case-by-case application of the reforms adopted in this Final Rule would be inappropriate since the most fundamental problems addressed here arise from deficiencies in the pro forma OATT itself, not simply the implementation of the pro forma OATT by a few transmission providers. Also, we decline to establish a one-year review period for the reformed pro forma OATT, as EPSA recommends. The Commission will continue to actively monitor compliance with its orders and, as necessary, institute further proceedings to meet its statutory obligation to remedy undue discrimination.

43. The Commission will not catalog each and every basis for its reform of the pro forma OATT in this section. Rather, we identify the bases for some of the most fundamental reforms herein and, in addition, we explain in each individual section of the Final Rule the inadequacies of the existing pro forma OATT provisions being addressed there and the reasons why our reforms are necessary to remedy undue discrimination or otherwise provide for rates, terms and conditions of service under the pro forma OATT that are just and reasonable.

B. Lack of Transparency Undermines Confidence in Open Access and Impedes Enforcement of Open Access Requirements

44. Following the issuance of the NOI, the Commission received a number of comments asserting that increased transparency would aid transmission customers in their participation in the wholesale market. A common theme in the comments was that a lack of transparency could lead to claims of discrimination and could make such claims more difficult to resolve. Commenters urged the Commission to improve transparency in a number of areas, particularly the evaluation of ATC and the planning of the transmission system, as well as the processing of transmission service requests and studies.

45. In the NOPR, the Commission agreed that a lack of transparency both increases the potential for undue discrimination and makes it more difficult to detect. The Commission reasoned that this lack of sufficient transparency was caused in part by inadequate compliance with the existing OASIS regulations and in part by inadequate transparency requirements. The Commission stated that the proposed reforms were intended to address both elements of the problem in an effort to increase confidence in open access tariffs and to facilitate compliance with the Commission's regulations and its enforcement of them. Comments

46. Williams states that its interests have been consistently and significantly compromised by the discretion afforded transmission providers in the interpretation of the OATT and the lack of transparency in requesting, scheduling and interrupting of transmission service. According to Williams, simply being told that service is being curtailed for reliability purposes under opaque local procedures, in the absence of a NERC Transmission Loading Relief (TLR) event, leaves market participants suffering the consequences without knowing on what basis the decision was reached, and without assurance that the decision was made in a non-discriminatory manner. Ultimately, Williams adds, the lack of transparency and latitude taken by the transmission provider to determine which requests for service are confirmed or denied and which are curtailed or interrupted in real time frustrates the Commission's goal of preventing undue discrimination and preference in the provision of transmission service. Furthermore, Williams states, the same lack of transparency exists around the opaque processes utilized, assumptions made, and basis on which the results of transmission planning studies are conducted to grant or deny requests for service.

47. APPA agrees that additional transparency in the administration of public utility transmission providers' OATTs will be of material assistance to both the Commission and transmission customers. However, APPA argues that the Commission must go beyond increasing transparency in the administration of public utility transmission providers' OATTs. According to APPA, more transparency will not change the basic industry paradigm with transmission customers depending on monopoly transmission providers for service. In APPA's view, customers are often reluctant to file complaints or bring problems to the Commission's attention because they depend on their transmission providers' systems for the vital services they need to serve their loads. APPA argues that the Commission not only has an obligation to act to remedy undue discrimination when it sees it, but also has an affirmative duty to look for it. According to APPA, the Commission must continue to actively regulate the transmission services that public utility transmission providers offer, even if full transparency is achieved through the revisions to the OATT implemented in the instant docket.

48. EPSA agrees that greater transparency will help enable market participants and the Commission to monitor and audit the behavior of transmission providers. EPSA states that the several ``black boxes'' shielding discriminatory transmission service over the past ten years must be opened. However, EPSA argues, there must be meaningful clarity and obligations set out in the rules and OATT requirements-- transparency simply for the sake of knowing why transmission service has been denied only illuminates a ``bridge to nowhere'' and fails to satisfy the Federal Power Act.

49. Entergy also supports the Commission's efforts to provide greater clarity in the rights and obligations of transmission providers and transmission customers under the OATT. According to Entergy, many of the improvements proposed by the Commission will reduce the likelihood of disputes and promote greater confidence on the part of customers that they are being treated fairly. Entergy states that, while it recognizes that the lack of clarity makes it difficult for the Commission to detect instances of non-compliance by transmission providers, Entergy also believes that this lack of clarity often makes it easier for transmission customers to convert every practice or policy into a claim of discrimination or other misconduct.

50. Although not convinced that there is a compelling need for increased transparency since transmission providers are already required to disclose voluminous amounts of information, Southern states that it recognizes that some reforms in the availability of information may be advantageous. However, Southern asserts, providing additional transparency must not simply impose additional reporting requirements; any such transparency-related reforms should be made after taking into consideration the extent and type of data and information that is already provided.

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Commission Determination

51. The Commission concludes that inadequate transparency requirements, combined with inadequate compliance with existing OASIS regulations, increases the opportunities for undue discrimination under the pro forma OATT and makes instances of undue discrimination more difficult to detect. We find that the reforms we adopt in this Final Rule will improve transparency in the OATT, reduce opportunities for undue discrimination, and increase our ability to detect undue discrimination.

C. Congestion and Inadequate Infrastructure Development Impede Customers' Use of the Grid

52. The Commission noted in the NOPR that the ability and incentive to discriminate increases as the transmission system becomes more congested. The Commission observed that the pro forma OATT contained only minimal requirements regarding transmission planning, which have proven to be inadequate as the Nation faces insufficient transmission investment in many areas. The Commission preliminarily concluded that the inadequacy of the existing obligation to conduct transmission system planning, coupled with the lack of transparency surrounding system planning generally, required reform of the pro forma OATT to ensure that transmission infrastructure is constructed on a nondiscriminatory basis and is otherwise sufficient to support reliable and economic service to all eligible customers. The Commission therefore proposed to require public utilities to engage in an open and transparent planning process at both the local and regional levels. Comments

53. APPA agrees that the lack of adequate transmission infrastructure is one of the core problems facing the electric utility industry. APPA supports revisions to the pro forma OATT to enhance and improve transmission planning on both an individual system and regional basis. Several commenters go further, arguing that the proposed reforms are insufficient and urging the Commission to more strongly encourage infrastructure development. EPSA asserts that successful implementation of the Congressional policy in favor of wholesale competition and State policies in favor of competitive procurement is frustrated by the lack of sufficient open access to the transmission grid. According to EPSA, new power plant investment is highly unlikely to occur, except by the transmission provider or its affiliate on a ``sole source'' or ``no bid'' basis (despite Federal and State policies to the contrary), if unaffiliated suppliers cannot effectively and efficiently obtain transmission service. EPSA argues that failure to boldly reform the Commission's open access transmission rules at this critical juncture would effectively hand an undeserved victory to the very transmission providers who, by the Commission's own findings, have the motive and the opportunity to discriminate. International Transmission argues that tariff reform is no substitute for prudent investment in the transmission infrastructure needed to increase the underlying physical capability of the transmission system.

54. On the other hand, some commenters dispute the Commission's assertion in the NOPR that vertically-integrated utilities operating in non-RTO regions have an incentive to discriminate and, therefore, are not adequately expanding the transmission grid to accommodate new entry by more efficient competitors. New Mexico Attorney General argues that vertically-integrated utilities operating under the traditional rate- base, rate-of-return model of regulation in fact have been historically criticized for having incentives to overbuild. New Mexico Attorney General asserts that most transmission projects are in reality derailed by strong ``NIMBY'' opposition to the actual siting of transmission lines. Another countervailing factor to the utility's incentive to overbuild, in New Mexico Attorney General's view, is the fact that State regulators attempt to limit capacity investment to reasonable levels only necessary to serve native load.

55. Southern states that the Commission's assertion in the NOPR that vertically-integrated utilities do not have an incentive to expand the grid overlooks the fact that many such utilities are under State legal duties to procure generation supplies through open, non- discriminatory requests for proposals, with the winners of those requests for proposals often being competitors of the vertically- integrated utility. Southern maintains that the winning competitive generation is then integrated into the host utility's transmission system and dispatch, and the transmission system is expanded to ensure the deliverability of this competitive generation. Furthermore, Southern states, a competitive generator can also have the output of its generator planned into the transmission provider's system if it takes long-term firm service under the OATT, with the transmission provider then being under a legal duty to expand its transmission system accordingly. Southern notes that it alone has invested $3.2 billion in transmission over the past decade and plans to invest another $2.8 billion over the next five years (2006-2010).

56. Community Power Alliance also argues that the Commission's own June 2005 ``State of the Markets Report'' contradicts the Commission's assertion that vertically-integrated utilities do not have the proper incentives to expand the grid. Community Power Alliance contends that this report shows that the amount of transmission investments made in the non-RTO regions, where vertically-integrated utilities typically operate, substantially exceeds the amount of transmission investments made in RTO regions. Commission Determination

57. The Commission concludes that reforms are needed to ensure that transmission infrastructure is evaluated, and if needed, constructed on a nondiscriminatory basis and is otherwise sufficient to support reliable and economic service to all eligible customers. As noted above, vertically-integrated utilities do not have an incentive to expand the grid to accommodate new entries or to facilitate the dispatch of more efficient competitors. Despite this, the existing pro forma OATT contains very few requirements regarding how transmission planning should be conducted to ensure that undue discrimination does not occur.

58. Our concern over this flaw is heightened by the critical need for new transmission infrastructure in this Nation. As the Commission explained in the NOPR, transmission capacity is being constructed at a much slower rate than the rate of increase in customer demand, with transmission capacity per MW of peak demand declining at an average rate of 2.1 percent per year during the period 1992 to 2002.\55\ The projections suggest that this trend will continue through 2012.\56\ As a result, there has been a significant decrease in transmission capacity relative to load in every NERC region.\57\ In light of this trend, there is a compelling need to build new transmission and respond to increasing demand through other

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means. EEI estimates that capital spending must increase by 25 percent, from $4 billion annually to $5 billion annually, to ensure system reliability and to accommodate wholesale electric markets.\58\ The legacy systems constructed by vertically-integrated utilities prior to the adoption of Order No. 888 support ``only limited amounts of inter- regional power flows and transactions. Thus, existing systems cannot fully support all of society's goals for a modern electric-power system.'' \59\

\55\ Eric Hirst, U.S. Transmission Capacity: Present Status and Future Prospects (Aug. 2004), http://www.eei.org/industry_issues/energy_infrastructure/transmission/USTransCapacity10-18-04.pdf

(Present Status and Future Prospects).

\56\ Present Status and Future Prospects at v.

\57\ Brendan Kirby (Oak Ridge National Laboratory, U.S. Department of Energy), Barriers to Transmission Investment, Technical Conference Presentation, (Docket No. AD05-5-000) (April 22, 2005).

\58\ Energy Policy Act of 2005: Hearings before the Subcommittee on Energy and Air Quality of the House Committee on Energy and Commerce, 109th Congress, First Sess. (2005) (Prepared statement of Thomas R. Kuhn, President of EEI).

\59\ Present Status and Future Prospects at v.

59. Expansion of the transmission system, as well as more efficient use of the grid, will alleviate the growth of congestion in most regions of the country. Transmission congestion has created fairly small local load pockets in primarily urban areas, e.g., New York City, Long Island, Boston, parts of Connecticut, and the San Francisco Bay Area. Other load pocket concerns have arisen in parts of northern Virginia, and various load centers in SPP. Still other constraints are more regional in scope: from the Midwest to the Mid-Atlantic, from the Midwest to TVA, into and within California, from TVA and Southern into Entergy, from Mid-America Interconnected Network into Wisconsin-Upper Michigan Systems, and into Florida.

60. Transmission congestion can have significant cost impacts on consumers. In 2002, DOE issued a study estimating the costs of congestion in four U.S. regions: California, PJM, New York and New England.\60\ DOE found that, despite the overall savings of wholesale electricity markets that lowered consumers' electricity bills by nearly $13 billion annually, interregional transmission congestion cost consumers hundreds of millions of dollars annually. DOE concluded that relieving bottlenecks in these four regions alone could save consumers about $500 million annually.\61\ In 2006, DOE released another study identifying two areas of the country with severe existing or growing congestion problems: the Atlantic coastal area from metropolitan New York southward through Northern Virginia, and Southern California.\62\

\60\ U.S. Department of Energy, National Transmission Grid Study at 11, 16-17 (May 2002), available at http://www.ferc.gov/industries/electric/indus-act/transmission-grid.pdf. To conduct this

study, DOE estimated the benefits of interregional wholesale power markets using the Policy Office Electricity Modeling System (POEMS). POEMS is a national energy model designed specifically to examine the impacts of electricity restructuring. The model includes economic, regional, and temporal detail that is needed to analyze the economics of interregional trade. In the first step of the study, DOE used POEMS to examine the cost reductions that would occur if increased electricity transfers across congested paths were allowed in these four regions, assuming generators bid their marginal costs. Under this assumption, consumer costs declined by $157 million per year. In the second step, DOE calculated the increase in congestion costs under the assumption that generators bid above their marginal operating costs when supplies are tight and additional electricity cannot be imported. The price spikes were assumed to occur during hours when at least one transmission link into a sub-region was congested and demand was greater than 90 percent of peak demand. When prices spike an additional $50 per MWh (above the price predicted when generators bid their marginal operating cost) during these periods, congestion costs nearly double to $300 million.

\61\ Id. at xi and ii.

\62\ U.S. Department of Energy, National Electric Transmission Congestion Study, Executive Summary at 2 (August 2006), available at http://www.ferc.gov/industries/electric/indus-act/doe-congestion-study-2006.pdf .

61. The decline in transmission investment and increase in transmission congestion underscore our concerns over inadequate planning provisions of the existing pro forma OATT. The existing pro forma OATT, as indicated above, contains very little specificity regarding how transmission planning should be conducted, how customers' needs are incorporated into that process, and what information is publicly available regarding the transmission providers' assumptions, criteria and data used in the planning process. These inadequacies are sufficiently severe, standing alone, to merit reform of the OATT. However, they are of even greater concern given the current state of the transmission grid. With inadequate levels of investment in the grid and increasing transmission congestion, customers' ability to access alternatives to the transmission provider's resources is limited. It is therefore imperative for the Commission to ensure that the planning process under each transmission provider's OATT is sufficient to prevent undue discrimination and transparent enough to detect any remaining instances of undue discrimination. We have done so in the reforms adopted and explained in section V.B.

D. A Consistent Method of Measuring ATC Is Needed

62. Another area in which transmission providers have significant discretion under the pro forma OATT is the calculation of ATC. While Order No. 888 obligated each public utility to calculate the amount of transfer capability on its system available for sale to third parties, the Commission did not standardize the methodology for calculating ATC, nor did it impose any specific requirements regarding the disclosure of the methodologies used by each transmission provider.\63\ As a result, there are a variety of ATC calculation methodologies in use today and very few clear rules governing their use. Moreover, there is often very little transparency about the nature of these calculations, given that many transmission providers have filed only summary explanations of their ATC methodologies in Attachment C to their OATTs.

\63\ Order No. 888 at 31,794 n.610.

63. In the NOPR, the Commission noted that, although the industry has sought to pursue greater consistency in ATC calculations through existing NERC processes, these efforts to date have been largely unsuccessful. The Commission expressed its preliminary determination that the lack of a consistent, industry-wide methodology for calculating ATC gives transmission providers the ability and the opportunity to unduly discriminate against third parties. The Commission therefore proposed a number of reforms to the process of calculating ATC to provide clarity and transparency to users of the grid. Comments

64. As discussed further in section V.A below, most commenters support the Commission's goal of requiring greater consistency in the manner in which ATC is calculated and additional transparency of ATC calculations. Commenters generally favor the Commission's proposal to increase consistency in the calculation of ATC, including consistent definitions of its components, data inputs, modeling assumptions, and data exchange and coordination protocols. For example, Exelon argues that each ATC component should be used in the same manner for all purposes (e.g., granting transmission service to third parties or for the transmission provider's own network load). Some commenters assert that industry-wide standardization of ATC calculation might not be possible and that the Commission should consider interconnection-wide, regional or even sub-regional standardization. Others suggest allowing flexibility in order to capture differences in system operation, usage, market operations and topology.

65. At the technical conference organized in this proceeding on October 12, 2006 (October 12 Technical Conference), the entire panel agreed that definitions must be consistent and a panelist representing Constellation

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asserted that broad differences in the core definitions of the ATC calculation are neither rational nor explainable.\64\ NERC, however, recognized that the goal of achieving consistency may not mean that a single ATC methodology is required.\65\ NERC explained that consistency can be achieved with a limited number of methodologies if the requirements of those methodologies are properly coordinated and communicated.

\64\ Transcript of October 12 Technical Conference at 149-50, available at Preventing Undue Discrimination and Preference in Transmission Service, Technical Conference (Docket No. RM05-25-000).

\65\ Id. at 125-50.

66. Numerous commenters support the Commission's proposals to increase transparency in the manner in which transmission providers derive ATC, including greater OASIS posting. Commenters opposing the transparency-related reforms focus on the Commission's proposal to require the posting of narratives on OASIS explaining reasons for changes in monthly and yearly ATC values on constrained paths. They argue that such a requirement would be too burdensome and would not provide customers with any significant new information.

67. Several commenters believe that making substantial ATC calculation and modeling data transparent will compromise Critical Energy Infrastructure Information (CEII) but provide suggestions for resolving the issue. Others express concern that the data required for posting on OASIS is not CEII but commercially sensitive. Finally, commenters provide suggestions regarding the requirement to post metrics on OASIS related to the provision of transmission service under the pro forma OATT, including various additional metrics the Commission should consider. Others state that this information is already available on OASIS. Commission Determination

68. We find that the lack of a consistent and transparent methodology for calculating ATC gives transmission providers the ability and opportunity to unduly discriminate in the provision of open access transmission service. There are few clear rules respecting ATC calculation, and transmission providers retain unnecessarily broad discretion in this area. This resulting discretion is a significant problem because calculation of ATC, which varies greatly depending on the criteria and assumptions used, may allow the transmission provider to discriminate in subtle ways against its competitors. On systems where transmission capacity is congested, this lack of consistency, coupled with a lack of transparency, is of heightened importance and has led to recurring disputes over whether the transmission provider is exercising its discretion to discriminate against its competitors. This discretion also hampers the detection of undue discrimination and, thereby, undermines the Commission's ability to enforce the general requirement in Order No. 888 that transmission service be provided on a not unduly discriminatory basis.

69. As discussed more fully below in section V.AIII.D, this Final Rule adopts a number of reforms that address the potential for remaining undue discrimination in the determination of ATC by requiring consistency in how ATC is evaluated, as well as providing greater transparency about how a transmission provider calculates and allocates ATC.

E. Discriminatory Pricing of Imbalances

70. Order No. 888 focused primarily on the adoption of non-rate terms and conditions of service, rather than instituting broad reform of the Commission's transmission pricing policies. Consistent with this focus, the Commission did not propose broad transmission pricing reform in the NOPR, but rather focused on instances where current pricing practices under the pro forma OATT may no longer be sufficient to remedy undue discrimination or ensure just and reasonable rates. One significant reform proposed in the NOPR related to charges for imbalance energy. The Commission preliminarily found that the existing policies provide wide discretion in the development of these charges and hence the potential for undue discrimination. The Commission therefore proposed certain principles to remedy that potential and sought comment on whether a specific imbalance pricing method would be appropriate. Comments

71. In general, transmission customers complain about the level and scope of energy and generator imbalance charges that are levied under the pro forma OATT and under individual interconnection agreements.\66\ Customers complain that energy imbalance charges are excessive and not related to the actual costs incurred by transmission providers. They also argue that the inconsistency between these charges in different control areas is unnecessary, and that other means of compensating the transmission provider, such as return-in-kind, should be considered. Generators likewise complain that generator imbalance charges are excessive, that transmission providers refuse to credit generators with the revenues resulting from imbalance penalties that are collected, and that transmission providers prevent unaffiliated generators from purchasing or self-supplying generator imbalance services. In addition, owners of intermittent resources complain that generator imbalance charges, which are imposed to provide an incentive for generators to schedule accurately, are inappropriate given their lack of control and ability to cure deviations.

\66\ Energy imbalance charges, including penalties on some systems, are imposed on a transmission customer when the amount of energy scheduled for delivery to the transmission grid does not equal the amount of energy withdrawn by that customer. Generator imbalance charges are levied on generators for deviations between the amount of energy they schedule and the amount they actually deliver to the grid.

Commission Determination

72. The Commission agrees that imbalance charges should provide appropriate incentives to keep schedules accurate without being excessive. We also find that consistency in imbalance charges, both between and among energy and generator imbalances, is preferable to the wide variety of imbalance provisions in place today. All imbalances have the same net effect on the transmission system in that they require other generation to be ramped up or down to compensate for the imbalance. As such, the Commission adopts two pro forma OATT provisions (Schedule 4 for energy imbalances and Schedule 9 for generator imbalances) based on a tiered structure similar to the imbalance provision used by Bonneville, as described further below. Such an approach recognizes the link between escalating deviations and potential reliability impacts on the system while keeping imbalance charges closely related to incremental costs. The Commission finds, however, that intermittent resources should be exempt from the highest- tier deviation band. We also require transmission providers to credit to all non-offending transmission customers the revenues they collect in excess of incremental costs.

F. Redispatch/Conditional Firm

73. In the NOPR, the Commission examined whether existing methods for evaluating requests for long-term firm point-to-point service continue to be just and reasonable. When a transmission provider considers a new resource to serve native load, the transmission provider does not eliminate an otherwise economic option because the resource may not be

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deliverable during a few hours of the year. For transmission customers, however, the transmission provider evaluates whether service can be granted in every hour of the year that is modeled and, if not, it informs the customer that service cannot be provided out of existing transfer capability. Only if the transmission customer agrees to pay for facilities studies does the transmission provider evaluate redispatch options, including whether they are less expensive than the upgrade costs. The Commission therefore proposed to reform the existing pro forma OATT planning redispatch \67\ obligation, or, in the alternative, to add a conditional firm service to the pro forma OATT. As proposed by the Commission, conditional firm would have been a long- term service allowing the transmission provider to give a lower curtailment priority than firm to the transmission customer during a pre-specified number of hours.

\67\ Although pro forma OATT section 13.5 refers to ``redispatch,'' we refer to it here as ``planning redispatch'' to distinguish it from the reliability redispatch provisions in the network integration transmission service sections of the pro forma OATT. See infra notes 552 and 557.

Comments

74. Some commenters support the inclusion of both a modified planning redispatch obligation and a conditional firm service in the pro forma OATT, stating that both are required to remedy undue discrimination and provide for comparable transmission service. These commenters urge the Commission to require transmission providers to offer planning redispatch and conditional firm service and allow customers to choose the option that best suits their physical, commercial and economic circumstances.

75. Others opine that conditional firm service may be simpler and less costly to implement. These commenters prefer the development of conditional firm service over the modifications to the planning redispatch service because of the complexities surrounding redispatch costs and protocols. For example, Entergy believes conditional firm service can provide benefits to transmission customers without unfairly socializing costs to native load and network customers of the transmission provider.

76. On the other hand, many commenters argue that the Commission should not require either option because the services are unnecessary, operationally unworkable, and legally unjustified, or because they would harm reliability and the quality of existing network service and provide disincentives for transmission investment. Several commenters state that these services would make curtailments of existing firm service more likely and limit opportunities for use of secondary network service, thereby harming native load protections and reducing reliability, contrary to FPA sections 215 and 217 respectively. While it recognizes that conditional firm service has been successful in parts of the Western Interconnection, NRECA contends that a mandate would undermine responsible planning and expansion of the transmission grid by harnessing the transmission provider's planning and dispatch functions to frame elaborate service conditions for conditional firm service.

77. Several commenters argue that, if the services are required, the Commission should ensure that reliability is not adversely affected. Others urge the Commission to make the new services an interim option until transmission upgrades are in place to provide firm service. Some commenters believe planning redispatch and conditional firm customers should bear the actual costs of the services received, including costs associated with system operational changes needed to accommodate the services. A few commenters believe that the Commission should allow for regional differences in development of the new services. Commission Determination

78. The Commission believes it is necessary to modify the manner in which transmission providers assess point-to-point service requests to eliminate the potential for undue discrimination in transmission service. We find that both techniques--planning redispatch and conditional firm service--are currently used under certain circumstances by transmission providers to serve native load and, therefore, that transmission customers should have comparable services in order to avoid undue discrimination, facilitate the provision of long-term transmission service and provide customers with greater flexibility in choosing resources to meet their needs. We expect that both options will help integrate new generation more quickly. This can be particularly beneficial to renewable generation resources, such as wind, that can be constructed more quickly than the transmission upgrades necessary to deliver their power on a firm basis over the long-run.

G. EPAct 2005 Emphasized Certain Policies and Priorities for the Commission

79. Finally, we note that the reforms adopted in this proceeding are consistent with the policies and priorities embodied in EPAct 2005, in which Congress emphasized many of the same principles reflected in this Final Rule. First, in EPAct 2005, Congress placed special emphasis on the development of transmission infrastructure. Congress required the Commission to adopt a rule establishing incentive-based rates for new transmission infrastructure investment. The stated purpose of new FPA section 219 is to benefit ``consumers by ensuring reliability and reducing the cost of delivered power by reducing transmission congestion.'' \68\ Among other steps, FPA section 219 requires the Commission to ``(1) Promote reliable and economically efficient transmission and generation of electricity by promoting capital investment in the enlargement, improvement, maintenance, and operation of all facilities for the transmission of electric energy in interstate commerce, regardless of the ownership of the facilities; (2) provide a return on equity that attracts new investment in transmission facilities (including related transmission technologies); [and] (3) encourage deployment of transmission technologies and other measures to increase the capacity and efficiency of existing transmission facilities and improve the operation of the facilities.'' \69\ In addition, Congress directed the Commission to encourage the deployment of advanced transmission technologies.\70\ Congress also gave the Commission certain ``backstop'' transmission siting authority, and authorized the creation of interstate compacts establishing transmission siting agencies.\71\ Finally, the Commission was directed to exercise its authority under EPAct 2005 ``in a manner that facilitates the planning and expansion of transmission facilities to meet the reasonable needs of load-serving entities to satisfy the

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service obligations of the load-serving entities, and enables load- serving entities to secure firm transmission rights * * * on a long- term basis for long-term power supply arrangements made, or planned, to meet such needs.'' \72\ Although these provisions have been, or will be, addressed primarily in other proceedings, we conclude that the Final Rule is consistent with these provisions because it supports improvements in infrastructure by reforming the transmission planning process to ensure that it is open, transparent and nondiscriminatory.

\68\ EPAct 2005 sec. 1241 (to be codified at section 219 of the FPA, 16 U.S.C. 824s). The Commission has issued a Final Rule implementing such an incentive rate program. See Order Nos. 679 and 679-A.

\69\ FPA Sec. 219(b)(1).

\70\ EPAct 2005 sec. 1223 (to be codified at 42 U.S.C. 16442).

\71\ EPAct 2005 sec. 1221(a) (to be codified at section 216 of the FPA, 16 U.S.C. 824p). The Commission implemented new regulations in accordance with this section to establish filing requirements and procedures for entities seeking to construct electric transmission facilities in Order No. 689.

\72\ EPAct 2005 sec. 1233(a) (to be codified at section 217(b)(4) of the FPA, 16 U.S.C. 824q). The Commission implemented FPA section 217(b)(4) in Long-Term Firm Transmission Rights in Organized Electricity Markets, Order No. 681, 71 FR 43564 (Aug. 1, 2006), FERC Stats. & Regs. ] 31,226 (2006), order on reh'g, Order No. 681-A, 117 FERC ] 61,201 (2006), reh'g pending.

80. Second, Congress emphasized the need for greater transparency in electricity markets, including transmission service. EPAct 2005 added section 220 to the FPA, which requires the Commission to facilitate ``price transparency in markets for the sale and transmission of electric energy in interstate commerce, having due regard for the public interest, the integrity of [that market], fair competition, and the protection of consumers.'' \73\ The Commission was authorized to ``prescribe such rules as the Commission determines necessary and appropriate to carry out the purposes of'' FPA section 220. Those rules ``shall provide for the dissemination, on a timely basis, of information about the availability and prices of wholesale electric energy and transmission service to the Commission, State commissions, buyers and sellers of wholesale electric energy, users of transmission services, and the public.'' This Final Rule similarly will promote greater transparency in the provision of transmission service in many important areas, including ATC calculation and transmission planning.

\73\ EPAct 2005 sec. 1281 (to be codified at 16 U.S.C. 824t).

81. Finally, Congress emphasized compliance with the Commission's regulations, increasing the civil and criminal penalties for violations of Commission-administered statutes and regulations.\74\ This new authority buttresses the Commission's efforts to enforce public utility OATTs and the regulations requiring transmission information to be posted on OASIS. As we explained in the Policy Statement on Enforcement, however, this new authority carries with it the responsibility to ensure that enforcement is firm but fair and that our rules are as clear as practicable to facilitate compliance.\75\ We conclude that this Final Rule is fully consistent with these principles because it clarifies our rules, in many areas, which will facilitate compliance by transmission providers.

\74\ EPAct 2005 sec. 1284(e)(1) (to be codified at section 316(A) of the FPA, 16 U.S.C. 825o-1).

\75\ Enforcement of Statutes, Orders, Rules and Regulations, Policy Statement on Enforcement, 113 FERC ] 61,068 (2005) (Policy Statement on Enforcement).

IV. Summary, Scope and Applicability of the Final Rule

82. This section provides a summary of the major components of the Final Rule, a description of the core elements of Order No. 888 that we retain, and a discussion of the applicability of the proposed rule to various entities.

A. Summary of Reforms

83. Consistency and transparency of ATC calculations. The Commission affirms the finding in the NOPR that the lack of a consistent, industry-wide methodology for calculating ATC, and the lack of adequate transparency in ATC calculations, increases the potential for undue discrimination and also makes undue discrimination more difficult to detect. The lack of consistent standards can facilitate undue discrimination by giving a transmission provider the discretion, and hence the ability and opportunity, to favor itself and its affiliates over third parties in how it calculates and allocates ATC. In this Final Rule, we give the industry specific guidance regarding the calculation of ATC and establish a firm deadline to develop certain requirements to make more consistent the ATC calculation process and the process of exchanging data between transmission providers about ATC. In addition, we amend pro forma OATT requirements as well as our OASIS regulations to increase the transparency in how ATC is calculated.

84. Requirement for coordinated, open and transparent transmission planning. The Commission also affirms the finding in the NOPR that Order No. 888 does not contain sufficient protections to guard against undue discrimination in transmission system planning. Without adequate coordination and open participation, market participants have minimal input or insight into whether a particular transmission plan treats all loads and generators comparably. To ensure that truly comparable transmission service is provided by all public utility transmission providers, including RTOs and ISOs, we amend the pro forma OATT to require coordinated, open, and transparent transmission planning on both a sub-regional and regional level. To implement this remedy, we adopt the eight planning principles proposed in the NOPR, as well as one additional principle, that each public utility transmission provider will be required to follow. We recognize that many regions have made significant progress in recent years in creating greater openness and transparency in transmission planning and believe our proposed reforms will build upon, strengthen, and improve this progress to reform transmission planning.

85. Transmission Pricing Reforms. Consistent with the focus of Order No. 888 on the non-rate terms and conditions of open access, the Commission does not initiate broad reform of transmission pricing policy through this Final Rule. However, we have identified several pricing rules that are part and parcel of OATT service that merit reform.

Energy and Generator Imbalance Charges. We find that energy and generator imbalance charges we have previously accepted are excessive, too varied, and otherwise unrelated to the cost of providing the service and, therefore, we reform energy and generator imbalance pricing. We adopt tiered pro forma OATT energy and generator imbalance provisions similar to those in use by Bonneville and exempt intermittent resources from the highest deviation band. In these new provisions, imbalance charges are based on incremental cost and escalate as the imbalance increases. Any deviations from these provisions must be consistent with or superior to the pro forma OATT as modified by this Final Rule and must meet the following criteria: the charges must (1) Be related to the cost of correcting the imbalance, (2) be tailored to encourage accurate scheduling behavior, such as by increasing the percentage of the adder as the deviations become larger, and (3) account for the special circumstances presented by intermittent generators, such as by waiving the higher ends of the deviation penalties.

Capacity Reassignment Pricing. We find that the existing cap on the reassignment of point-to-point service is no longer just and reasonable and, therefore, we eliminate the cap. We believe that removing the cap will eliminate an unnecessary impediment to the resale of capacity, which in turn should increase utilization of the grid and otherwise ensure that point-to-point service is just, reasonable, and not unduly discriminatory.

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Crediting of Customer-Owned Facilities. We retain most elements of our existing policy respecting the crediting of customer- owned facilities, including the requirement that such facilities meet the integration standard. However, we eliminate the requirement that new facilities can receive credits only if they are ``jointly planned'' because this requirement provides a disincentive to coordinated planning. Rather, we provide that such new facilities are eligible for credits if such facilities are integrated into the operations of the transmission provider's facilities. Customer-owned facilities shall be presumed to be integrated if those facilities, if owned by the transmission provider, would be eligible for inclusion in the transmission provider's annual transmission revenue requirement.

86. Improvements to Point-to-Point Service. The Commission concludes that the existing methods for evaluating requests for long- term firm point-to-point service are no longer just, reasonable, and not unduly discriminatory. The existing pro forma OATT allows the transmission provider to deny a request for long-term point-to-point service if that service is not available in a single hour of the period studied. We find that this approach is not comparable because, when a transmission provider considers a new resource to serve native load, the transmission provider does not eliminate an otherwise economic option because the resource may not be deliverable in a few hours of the year. To remedy this problem, the Commission adopts a ``conditional firm'' component to long-term point-to-point service that addresses the situation where firm service can be provided for most, but not all, hours of the period requested. We also reform the existing requirements for the provision of redispatch service to ensure that they are of greater use to transmission customers and more consistent with reliability planning and operation of the system.

87. Reform of rollover rights. The Commission concludes that section 2.2 of the pro forma OATT, which grants an ongoing right to transmission customers to renew or ``roll over'' their contracts, should be reformed. The current rollover rights do not provide consistency between the rights of rollover customers and the resulting obligations of transmission providers to plan and upgrade the system to accommodate rollovers. The Commission therefore amends section 2.2 to ensure greater consistency with transmission planning and construction timelines and modifies the minimum term of the rollover rights to five years, rather than the current minimum term of one year. The Commission also requires that a transmission customer eligible for rollover rights provide notice of whether or not it will exercise its right of first refusal to renew the contract no less than one year before the expiration date of the transmission service agreement, rather than within the current 60-day period.

88. Increases in transparency to lessen the opportunities to discriminate and reduce transaction costs. In addition to the increased transparency we require regarding the calculation of ATC and transmission planning, we increase the transparency of transmission service provided under the pro forma OATT in several other respects. For example, we require transmission providers and their network customers to use the transmission providers' OASIS to request designation of a new network resource and to terminate the designation of an existing network resource. In addition, we require transmission providers to modify their OASIS so that requests to designate and terminate a network resource can be queried, allowing all parties access to such information. We also require transmission providers to post a list of their current designated network resources and all network customers' current designated network resources on their OASIS. Finally, we require transmission providers to post on OASIS all their business rules, practices and standards that relate to transmission services provided under the pro forma OATT.

89. Strengthening enforcement of the pro forma OATT. The reforms adopted in this Final Rule provide greater clarity in the terms and conditions of the pro forma OATT, resolving ambiguities in the existing pro forma OATT that have made undue discrimination easier to accomplish and more difficult to detect. Our new civil penalty authority under EPAct 2005 gives us ample power to remedy tariff violations, but it also places upon us an increased responsibility to make the rules as clear as possible. We fulfill that responsibility in the Final Rule by providing greater clarity where appropriate to several critical OATT provisions. We also adopt a number of posting and reporting requirements that will provide the Commission and market participants with information about each transmission provider's performance of pro forma OATT obligations. For example, we require transmission providers to post specific performance metrics related to their completion of studies required under the pro forma OATT. We note that the Commission will continue to audit compliance with the pro forma OATT, and toward that end require transmission information kept on OASIS to be retained for audit purposes for five years. Finally, we adopt a number of reforms to operational penalties assessed under the pro forma OATT, including so-called ``over-use'' penalties and the treatment of operational penalty revenues collected from transmission providers and their affiliates.

90. Miscellaneous OATT improvements. Finally, we implement a number of improvements to the terms and conditions of the pro forma OATT to incorporate the lessons learned over the past ten years. We briefly note these below:

Designation of network resources. We provide clarification regarding the types of agreements that may be designated as network resources, the process for verifying whether agreements meet the requirements in the pro forma OATT, and the requirement for transmission providers to designate and undesignate network resources. We also require customers to submit an attestation with each application to designate a new network resource.

Reservation priorities. We change the priority rules to give certain priority to pre-confirmed transmission service requests submitted in the same time period. We also add price as a tie-breaker in determining reservation queue priority when the transmission provider is willing to discount transmission service.

Clarifications related to network service. We provide clarification related to use of network service on an ``as available basis'' and to ``redirects'' of network service.

B. Core Elements of Order No. 888 That Are Retained

91. Although we are adopting many important reforms to Order No. 888 and the pro forma OATT in this Final Rule, we emphasize that many of the core elements of Order No. 888 are retained. As the Commission noted in the NOPR, many of these core elements enjoy broad support from many sectors of the industry. A variety of commenters--in response to the NOI issued earlier in this proceeding and again in response to the NOPR--have urged the Commission to focus on meaningful incremental reforms to the pro forma OATT, rather than on industry restructuring. We share the view that Order No. 888 can be strengthened without discarding its fundamental structure. We discuss

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below the core elements that are being retained and the comments received on these points. 1. Federal/State Jurisdiction

92. In Order No. 888, the Commission stated that it has exclusive jurisdiction over the rates, terms, and conditions of unbundled retail transmission in interstate commerce.\76\ Though the Commission adopted a test for determining what constitute Commission-jurisdictional transmission facilities and what constitute State-jurisdictional local distribution facilities in situations involving unbundled wholesale wheeling and unbundled retail wheeling,\77\ the Commission stated that it generally would defer to determinations by State regulatory authorities concerning where to draw the jurisdictional line under that test.\78\ The Commission declined to assert jurisdiction over bundled retail transmission, reasoning that ``when transmission is sold at retail as part and parcel of the delivered product called electric energy, the transaction is a sale of electric energy at retail.'' \79\ The U.S. Supreme Court affirmed the Commission's decision to assert jurisdiction over unbundled but not bundled retail transmission, finding that the Commission made a statutorily permissible choice.\80\ In the NOPR, the Commission proposed to retain the jurisdictional divide established in Order No. 888.

\76\ Order No. 888 at 31,781.

\77\ Id. at 31,771 (setting forth the seven-factor test).

\78\ Id. at 31,781.

\79\ Id.

\80\ See New York v. FERC, 535 U.S. at 28.

Comments

93. Several commenters support the Commission's proposal to retain the existing jurisdictional divide.\81\ Though APPA concludes that the most politic course at this juncture is to leave the current jurisdictional boundaries in place and develop cooperative mechanisms in each region to coordinate Federal policy implementation with the relevant State regulators, APPA notes that there is disagreement among its members about whether the current jurisdictional lines are properly drawn. APPA explains that a substantial number of its members believe that all interstate transmission services (both retail and wholesale) should be provided under one consistent set of tariff terms and conditions. Other APPA members, however, believe that the Commission made the proper jurisdictional call in Order No. 888. NARUC urges the Commission to clarify that its planning proposals will not reopen or attempt to change the jurisdictional split over transmission facilities delineated in Order No. 888.

\81\ E.g., Ameren, APPA, North Carolina Commission Reply, PNM- TNMP, and Southern.

Commission Determination

94. The Commission will retain the existing jurisdictional divide that was established in Order No. 888, which has been affirmed by the U.S. Supreme Court and accepted by the industry and State regulatory authorities.\82\ We also reiterate our recognition of the need for heightened cooperation between Federal and State regulators in areas where there are overlapping Federal and State policy concerns. As explained in greater detail in the planning section below, and in response to NARUC's concern, the planning reforms adopted in the Final Rule contemplate coordinated and open transmission planning, but do not reopen or otherwise change the existing jurisdictional divide for transmission facilities.

\82\ See New York v. FERC, 535 U.S. at 28.

2. Native Load Protection

95. In Order No. 888, the Commission did not require transmission providers to unbundle transmission service to their retail native load. The Commission also did not require that bundled retail service be taken under the terms of the pro forma OATT.\83\ Moreover, the Commission allowed a transmission provider to reserve, in its calculation of ATC, transmission capacity necessary to accommodate native load growth reasonably forecasted in its planning horizon.\84\ Order No. 888 also granted a rollover right to existing firm service customers,\85\ but allowed transmission providers to restrict that rollover right if the capacity was reasonably forecasted as needed to serve native load customers, as long as that restriction was set forth in the customer's initial service contract.\86\

\83\ Order No. 888 at 31,745.

\84\ Id. at 31,694.

\85\ Id.; see pro forma OATT section 2.2.

\86\ Order No. 888-A at 30,198.

96. Congress, in section 1233 of EPAct 2005, added section 217 to the FPA, entitled ``Native Load Service Obligation,'' which addresses transmission rights held by load-serving entities (LSEs). FPA section 217 allows LSEs to use their own and contracted-for transmission capacity to deliver energy as required to meet their service obligations, without being subject to charges of unlawful discrimination. The provision makes clear, however, that this requirement does not abrogate any contract or service agreement for firm transmission service or rights in effect as of the date of enactment of EPAct 2005.\87\ In the NOPR, the Commission concluded that the protection of native load embodied in Order No. 888 is consistent with FPA section 217, and reaffirmed its commitment to the protection of native load.

\87\ 16 U.S.C. 217(f).

Comments

97. Several commenters agree with the Commission's preliminary conclusion that the protection of native load embodied in Order No. 888 is consistent with FPA section 217 and support the Commission's continued commitment to the protection of native load.\88\ While APPA \89\ and TAPS generally agree with the Commission that the overall OATT regime is consistent with section 217, they urge the Commission to maintain and reinforce the comparability requirement. APPA urges the Commission to broaden its preliminary conclusion in the NOPR and conclude instead that the protection of native load and the provision of fully comparable transmission service to other LSEs with long-term service obligations, as embodied in Order No. 888, are consistent with FPA section 217. TAPS also supports the Commission's reading of FPA section 217 as consistent with the Order No. 888 pro forma OATT's ``native load'' priority, recognizing that FPA section 217 reinforces the OATT's commitment to comparable treatment of all LSEs--e.g., transmission providers and network customers.

\88\ E.g., Ameren, E.ON, Tacoma, Arkansas Commission, EPSA, Southern, and TAPS.

\89\ APPA argues that the proposed definition of native load customers in section 1.21 is not technically consistent with FPA section 217 because FPA section 217 does not distinguish among the types of power supply arrangements that an LSE must have to enjoy the protection of FPA section 217. Nevertheless, APPA states that it would not be fruitful to reopen the entire OATT framework to address this technical (but very important) definitional difference.

98. Other commenters dispute the Commission's preliminary conclusion that the native load protection embodied in Order No. 888 is consistent with FPA section 217.\90\ Many commenters argue that FPA section 217 protects all load, not just native load.\91\ Constellation states that the Commission must recognize that there are other market participants besides the transmission providers themselves that are LSEs under FPA section 217. Under the definition of LSEs in FPA section

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217, EPSA argues that many entities other than traditional, vertically- integrated utilities are in the business of serving load. The statute, EPSA asserts, applies to any native load service obligation, whether that obligation is served by a competitive supplier, an affiliate of the transmission provider, or by the transmission provider itself. Salt River contends that FPA section 217 is self-implementing, though it urges the Commission to act to remove impediments to the full exercise of rights granted to LSEs.

\90\ E.g., Arkansas Municipal, Constellation, Duke, Salt River, and South Carolina E&G.

\91\ E.g., Constellation, EPSA, and South Carolina E&G.

99. Constellation argues that the Commission should require native load and OATT customers to take service under the same terms and conditions because experience has proven that discrimination has occurred as a result of having two different sets of rules applicable to transmission customers. EPSA urges the Commission to further clarify that the transmission provider has an affirmative obligation to serve native load in a non-discriminatory manner. According to EPSA, section 217 supports the Commission's paramount statutory mission of ensuring non-discrimination and makes clear that a transmission provider, when utilizing transmission capacity or rights reserved to serve native load, must ``put its blinders on'' to ensure that the load's needs are being met in the most economical way available, whether that decision means the deployment of its own affiliated generation, or the deployment of available non-utility alternatives.

100. Arkansas Municipal asserts that FPA section 217 recognizes the need to give priority to LSEs in certain situations, such as when the transmission grid may be constrained and one group of customers may be denied service at the expense of other customers. Arkansas Municipal states that a priority list could be instituted in this reform proceeding that places LSEs at the top of the list in competing requests for transmission service when not all requests could be granted or honored by the transmission provider.

101. New Mexico Attorney General argues that native load is fundamentally different than merchant load and therefore, in the planning process, the needs of merchants should not be treated comparably with the needs of New Mexico utilities' native loads. New Mexico Attorney General asserts that New Mexico utilities have a statutory obligation to serve retail load while merchants are free to come and go with cycles inherent in wholesale markets. According to New Mexico Attorney General, the transmission requirements of the utilities' native loads amount to an ongoing long-term firm contract, while the transmission needs of merchants are, by comparison, short- term and speculative.

102. Several commenters urge the Commission to revisit various aspects of the reforms proposed in the NOPR in order to enhance the protection of native load. For example, some commenters urge the Commission to modify the rollover proposal in the NOPR. Salt River argues that the Commission's regulations must include a clear provision for a transmission owner anticipating, or unexpectedly facing, load growth to recapture capacity temporarily made available to the wholesale market. Arkansas Commission disagrees with the Commission's proposal to require a transmission provider to compete for transmission capacity rather than reclaim it through its rights to reserve capacity for future load growth. The proposal is inequitable, Arkansas Commission argues, because native load customers have historically paid for most of the transmission providers' assets and will continue to do so in the future. Because of this, Arkansas Commission asserts, native load customers should be given preference in the reservation of transmission capacity. In response to Arkansas Commission's position, MDEA urges the Commission to make clear, consistent with the comparability principle adopted in Order No. 888 and reaffirmed in the NOPR, and with FPA section 217, that any reservation of rights or preference available to a transmission provider's native load customers must be available to network customer loads as well. South Carolina E&G argues that the Commission's interpretation of ``reasonably forecasted'' capacity under section 2.2 of the pro forma OATT has been effectively impossible to meet and, therefore, the Commission should now provide clear standards for evaluation of native load protecting rollover restrictions. A clear standard, South Carolina E&G states, would have the Commission consider rollover restrictions in light of a utility's transmission planning process. On reply, Progress Energy supports South Carolina E&G's comments. Progress Energy urges the Commission to revisit the rollover rights policy to develop a policy by which an LSE may be assured of future transmission service for reasonably forecasted native load growth.

103. South Carolina E&G also asks the Commission to revise section 13.6 of the pro forma OATT, regarding curtailment of firm point-to- point transmission service. South Carolina E&G urges the Commission to comply with the mandate of Northern States Power Co. v. FERC,\92\ which South Carolina E&G asserts held that the Commission had exceeded its authority in rejecting a vertically-integrated transmission provider's proposal to modify section 13.6 of the OATT to give a higher curtailment priority to native load. According to South Carolina E&G, the Commission has responded by applying the court's decision narrowly, but FPA section 217 requires the Commission to change that position and recognize the primacy of service to native load in section 13.6 of the OATT. In its reply comments, Progress Energy supports the comments of South Carolina E&G and states that the Commission must affirmatively recognize the priority of service to LSEs in the application of the curtailment priorities in section 13.6 of the OATT.

\92\ 176 F.3d 1090, 1096 (8th Cir. 1999), cert. denied sub nom. Enron Power Marketing, Inc. v. Northern States Power Co., 528 U.S. 1182 (2000).

104. Duke argues that several of the Commission's proposed reforms--such as hourly firm service, redispatch, and conditional firm service--actually reduce the protection afforded native/network load. Salt River suggests that the Commission should modify its ATC proposal to bring the Commission's native load priority policies in line with FPA section 217. Salt River asserts that, in calculating ATC, the transmission provider must be able to exercise reasonable professional judgment as to the amount of transmission that must be reserved to meet native load service obligations; the Commission should not get into the business of dictating forecasting methodology. Salt River proposes that a native load forecast that is used by an LSE as the basis for committing capital for generation expansion or procurement should be presumed to be valid for purposes of establishing available capacity. EPSA, however, argues that, unless and until the Commission mandates a hard and enforceable definition of ATC, transmission-owning utilities that also own affiliated generation will continue to hide behind the native load service obligation as an excuse for being unable to find ATC for any but self-serving purposes.

105. EPSA also argues that the Commission must ensure that transmission owners' planning accommodates all supply options. EPSA urges the Commission to clarify that transmission capacity reserved for native load is to be made available (including for study and other purposes) to competitive suppliers who wish to

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serve native load as allowed by State law. According to EPSA, all generation assets ultimately serve load and the pro forma OATT should be clarified to ensure that the transmission system is available on a non-discriminatory basis now and in the future to ensure that load is optimally served--regardless of which generation resources are serving that load. In its reply comments, EPSA also challenges the initial comments of New Mexico Attorney General, which EPSA argues incorrectly interpret FPA section 217 as drawing a distinction between the types of generation that serve load. EPSA argues that the statute protects the customer load that all suppliers would seek to serve regardless of the source.

106. APPA agrees with the Commission's response in the NOPR to Metropolitan Water District that the specific issues related to an RTO's provision of long-term transmission rights are better left to the rulemaking in Docket Nos. RM06-8-000 and AD05-7-000, and the proceedings in each RTO region to implement the Final Rule issued in those dockets on July 20, 2006. APPA notes, however, that the Commission has not proposed in this docket to exempt RTOs from the provisions of the NOPR. Rather, APPA notes, departures from the pro forma OATT, including departures in RTO OATTs, must be justified under the ``consistent with or superior to'' standard. APPA argues that the Commission should apply this standard to long-term transmission rights, as well as to the other terms and conditions of OATT transmission service that RTOs provide. Commission Determination

107. In Order No. 888, the Commission gave public utilities the right to reserve existing transmission capacity needed for native load growth reasonably forecasted within the utility's current planning horizon. The Commission also allowed transmission providers to restrict rollover rights based on reasonably forecasted need at the time the contract is executed. We continue to believe these protections for native load are appropriate and do not eliminate them in this Final Rule, as suggested by some commenters. We also believe that the protection of native load embodied in Order No. 888, as enhanced by the reforms adopted in this Final Rule, is consistent with FPA section 217, which protects the transmission rights of entities with service obligations to end-users or a distribution utility, to the extent required to meet their service obligations. The additional reforms proposed by commenters are not necessary at this time to remedy undue discrimination. We conclude that the native load priority established in Order No. 888 continues to strike the appropriate balance between the transmission provider's need to meet its native load obligations and the need of other entities to obtain service from the transmission provider to meet their own obligations.

108. In response to comments regarding reforms needed to ATC calculation and transmission planning to bring the native load priority policies in line with FPA section 217, we believe that the Commission's reforms in this Final Rule appropriately reflect the transmission provider's obligation to serve native load. As discussed more fully in the ATC and planning sections below, the processes we adopt herein are open, transparent and non-discriminatory and assume that the transmission provider is meeting its obligations, including its native load service obligation. We disagree with Duke's assertion that the reforms proposed in the NOPR will result in a reduction of the protection afforded native or network load. Not only have we reaffirmed the fundamental protections for native load contained in Order No. 888, but we have modified, where appropriate, the pro forma OATT to ensure that a transmission provider's obligations can be met consistent with maintaining the reliability to existing customers, including native load. For example, we are eliminating the current requirement to provide planning redispatch over long periods of time (e.g., 10-30 years) because it is unnecessary to remedy undue discrimination and can create problems in forecasting system conditions consistent with maintaining reliability to native load customers.\93\

\93\ Proposals related to other reforms, such as curtailments and rollovers, are discussed in the sections below dealing with each of those issues.

109. With regard to APPA's comments regarding long-term transmission rights in organized markets, we note that the Commission has issued its Final Rule in Docket Nos. RM06-8-000 and AD05-7-000.\94\ As discussed more fully in the applicability section of this rulemaking, and in response to APPA's comments, we reiterate that any departures from the pro forma OATT proposed by an ISO or an RTO must be ``consistent with or superior to'' the pro forma OATT in this Final Rule.

\94\ See supra note 72.

3. The Types of Transmission Services Offered

110. In Order No. 888, the Commission required all public utilities to offer, on a non-discriminatory, open-access basis, firm network service and firm and non-firm point-to-point service. In the NOPR, the Commission proposed to retain these services and did not propose to require transmission providers to adopt a network contract demand service, either as a replacement for network or point-to-point service or as a third category of service under the OATT. Comments

111. Several commenters support the Commission's proposal to retain the current services in the pro forma OATT and to not adopt contract demand service.\95\ While APPA supports the Commission's proposal, it states that the Commission should remain open to individual public utility transmission provider's proposals to add ``hybrid'' service to the base network and point-to-point services.

\95\ E.g., MISO/PJM States, TVA, and Southern.

112. Other commenters, such as AMP-Ohio and Nevada Companies, argue that the Commission should require all transmission providers to offer network contract demand service. Nevada Companies argue that the Commission's network designation process can substantially interfere with State jurisdiction over resource acquisition, especially for transmission providers that are required to purchase substantial amounts of power to serve their retail customers instead of relying primarily on their own generation. Nevada Companies reason that allowing transmission providers to move to a contract demand-based network service would remove them from the dilemma of being forced to make resource procurement decisions that are inconsistent with State requirements. On reply, MidAmerican, Newmont Mining, and Utah Municipals oppose the suggestion that the contract demand service should be made a mandatory service offering in the pro forma OATT. In its reply comments, Newmont Mining states that, if the Commission is inclined to provide some relief to allow Nevada Companies to comply with both the pro forma OATT and their State-approved resource plans, that relief should come only after an investigation of how similar problems are handled on other systems and should be a narrowly and carefully monitored exception to the resource designation requirements.

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113. Alberta Intervenors argue that undue discrimination is most likely to occur in situations where there is a single or dominant network customer and that customer either has a dual mandate for serving the network customers or that customer has a ``free option'' for procuring transmission.\96\ Alberta Intervenors recommend that the Commission implement standardized rules with respect to the ``free option'' concept while offering regional flexibility to ensure the objectives of open access and the absence of undue discrimination continue to be advanced. Alberta Intervenors also argue that, despite the Commission's proposal to address undue discrimination against transmission customers in attempting to redirect to new receipt and delivery points, undue discrimination remains a concern since network customers retain a flexibility of receipt and delivery points that is not granted to third party point-to-point customers. This flexibility provided to the network customer allows the use of the system for activities known as ``parking'' \97\ and ``hubbing.'' \98\ Alberta Intervenors urge the Commission to eliminate this unfair competitive advantage under the OATT by making a common service available to all participants rather than differing service for network customers, or alternatively, by restricting the use of point-to-point services by the network customer to exclude its use for ``parking'' and ``hubbing.''

\96\ Alberta Intervenors assert that the purchase of point-to- point service by dominant network customers results in an equal and offsetting reduction to the network customer's network charges, resulting in a net cost of zero. They state that point-to-point service is a net cost to all competitors except the dominant network customer. Thus, they argue, a dominant network customer can buy point-to-point service for an extended period and use this service for a limited number of hours at little (or no) net cost compared to not purchasing point-to-point service for an extended period. In Alberta Intervenors' view, this ``free option'' provides network customers with a competitive advantage when reserving point-to-point service because it enables the network customers to over-consume or buy excess point-to-point service than they would if the true net cost were reflected. Alberta Intervenors contend that such over- consumption reduces access to point-to-point service for other customers.

\97\ Alberta Intervenors define ``parking'' as a network customer reserving point-to-point service using a network load point of delivery to purchase energy that it intends to sell but where no buyer has been identified at the time of the reservation. The energy notionally reduces network load. Once a buyer is found, the network customer completes the sale by delivering the energy from freed-up generation at a generation point of receipt to a buyer's point of delivery.

\98\ Alberta Intervenors define ``hubbing'' as a practice very similar to ``parking,'' but involving multiple buyers and sellers. The network customer can reserve point-to-point transmission to purchase energy from multiple sellers and to sell energy to multiple buyers by creating a hub within its network load. Alberta Intervenors explain that this allows the network customer to organize purchases and sales by physically matching the requirements of multiple buyers and sellers.

114. MidAmerican states that in the Western Interconnection, a utility's loads are not necessarily located within a confined geographical boundary served by a single transmission owner. In these cases, MidAmerican argues, neither network nor point-to-point service under the current pro forma OATT is suitable to serve those loads. To remedy these shortcomings in standard OATT service, MidAmerican states that the Commission should require the incorporation of dynamic scheduling and long-term, seasonally-shaped, firm point-to-point as new service offerings under the pro forma OATT. Commission Determination

115. The Commission will not alter the types of services that we required in Order No. 888. We continue to believe that network and point-to-point services are the appropriate base-line service offerings in the OATT, and we will not mandate that transmission providers adopt new service offerings such as network contract demand service. Although the Commission has accepted forms of network contract demand service proposed by individual transmission providers, and the service may provide benefits to certain customers, we do not believe the service is necessary to remedy undue discrimination. For example, the service would require a departure from full load-ratio pricing for network customers, which may not be warranted to the extent the transmission provider plans its system to serve all native load. However, while the Commission concludes that it will not require all transmission providers to offer this service, in response to the arguments raised by commenters such as AMP-Ohio and Nevada Companies, we reiterate that the Commission already has accepted forms of network contract demand service and will continue to entertain such proposals on a voluntary basis from transmission providers.

116. The Commission also is not persuaded by Alberta Intervenors' and MidAmerican's arguments in support of further alternative services under the pro forma OATT. As with network contract demand service, transmission providers may propose such services if appropriate for their region. We do not believe mandating that such services be provided by all transmission providers is necessary at this time to prevent undue discrimination. 4. Functional Unbundling

117. In Order No. 888, the Commission chose to mandate functional, rather than corporate (in which a public utility's transmission and generation assets would be placed in separate corporate entities), unbundling of transmission and generation services. The Commission explained that functional unbundling has three components:

1. A public utility must take transmission services (including ancillary services) for all of its new wholesale sales and purchases of energy under the same tariff of general applicability as do others;

2. A public utility must state separate rates for wholesale generation, transmission, and ancillary services;

3. A public utility must rely on the same electronic information network that its transmission customers rely on to obtain information about its transmission system when buying or selling power.\99\

\99\ Order No. 888 at 31,654.

118. In the years following Order No. 888, a number of public utilities nonetheless underwent corporate unbundling. Many of these entities did so as a result of State-mandated restructuring laws. Others did so for corporate or tax reasons. Some entities divested all of their generation assets to a non-affiliate, while others simply restructured internally to place the generation assets in a different corporate subsidiary than the transmission assets. There remain, however, a significant number of vertically-integrated public utilities that operate under the functional unbundling approach.

119. In the NOPR, we proposed to preserve the functional unbundling approach adopted in Order No. 888, rather than impose a corporate or structural unbundling requirement. While the Commission expressed its continued support for voluntary efforts to adopt structural changes (such as transmission-only companies, RTOs, or other reforms), the Commission found that the more intrusive and costly corporate unbundling was not necessary at this time. The Commission also declined to mandate an independent transmission coordinator for all transmission providers. Though the Commission has previously found that such entities may be appropriate in certain circumstances and we support voluntary efforts to rely on them,\100\ the

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Commission concluded that there was not a sufficient basis for requiring them as a generic remedy for undue discrimination.

\100\ See Duke Power, 113 FERC ] 61,288 (2005); MidAmerican Energy Co., 113 FERC ] 61,274 (2005); see also Entergy Services, Inc., 110 FERC 61,295 (2005), order on clarification, 111 FERC ] 61,222 (2005), order conditionally approving filing, 115 FERC ] 61,095 (2006).

Comments

120. Commenters generally support the Commission's proposal to retain functional unbundling.\101\ APPA also supports the Commission's decision not to mandate an independent transmission coordinator for all public utility transmission providers. Similarly, Tacoma supports the Commission's decision to continue to view participation in an RTO or ISO as voluntary actions. While PJM and EPSA would prefer a structural remedy, they generally support the Commission's proposal to retain functional unbundling. However, EPSA states that given the Commission's proposal to continue to rely on functional unbundling, it is critical, particularly in those areas without organized markets, that OATT rules regarding unbundled transmission service be clear, transparent, consistent, and rigorously enforced. APPA states that it will be vital to obtain the cooperation of State regulators in each region where the OATT reforms will be implemented to ensure that the current functional unbundling regime in fact is sufficient to do the job.

\101\ E.g., Santee Cooper, LPPC, TVA, Tacoma, Southern, MISO Transmission Owners, and E.ON.

121. E.ON and TVA express concern that the Commission may yet choose a structural remedy. E.ON urges the Commission to look at the full depth and breadth of its existing powers to monitor and fully redress any abuses in the allocation of transmission services before considering structural unbundling. Similarly, TVA notes that the Commission already has the option to impose a structural remedy on a case-by-case basis.\102\

\102\ Some commenters argue that adoption of the ``open dispatch'' proposals raised by commenters such as Chandley-Hogan and PJM would constitute a departure from functional unbundling. We discuss the ``open dispatch'' and similar proposals in section V.C below.

Commission Determination

122. The Commission will, as proposed in the NOPR, continue to require functional--rather than corporate or structural--unbundling. As explained in the NOPR, for public utilities that keep transmission and generation assets in the same corporate entity, the Commission has strict Standards of Conduct that require the separation of the utilities' transmission system operations and wholesale marketing functions.\103\ These rules require that employees engaged in transmission functions operate separately from employees of energy affiliates and marketing affiliates. A number of information sharing restrictions also apply, which prohibit transmission providers from allowing employees of their energy and marketing affiliates to obtain access to transmission or customer information, except via OASIS.

\103\ The rules were first established in Order No. 889. See Order No. 889 at 31,595. The Standards of Conduct rules were later replaced by a broader set of rules adopted in Order No. 2004, which were subsequently vacated in part by the United States Court of Appeals pending remand proceedings before the Commission. See Standards of Conduct for Transmission Providers, Order No. 2004, 68 FR 69134 (Dec. 11, 2003), FERC Stats. & Regs. ] 31,155 (2003), order on reh'g, Order No. 2004-A, 69 FR 23562 (Apr. 29, 2004), FERC Stats. & Regs. ] 31,161 (2004), order on reh'g, Order No. 2004-B, 69 FR 48371 (Aug. 10, 2004), FERC Stats. & Regs. ] 31,166 (2004), order on reh'g, Order No. 2004-C, 70 FR 284 (Jan. 4, 2005), FERC Stats. & Regs. ] 31,172 (2005), order on reh'g, Order No. 2004-D, 110 FERC ] 61,320 (2005), vacated, National Fuel, 468 F.3d 831. The Commission has issued an interim rule promulgating temporary regulations consistent with the Court's decision and initiated a further rulemaking to propose permanent regulations. See Standards of Conduct for Transmission Providers, Order No. 690, 72 FR 2427 (Jan. 19, 2007), FERC Stats. & Regs. ] 31,327 (2007); Standards of Conduct for Transmission Providers, Notice of Proposed Rulemaking, 72 FR 3958 (Jan. 29, 2007), FERC Stats. & Regs. ] 32,611 (2007) (Standards of Conduct NOPR).

123. The Commission aggressively enforces the Standards of Conduct and, as referenced by APPA, cooperates with State regulators to ensure that the functional unbundling regime is sufficient to prevent undue discrimination. The Commission's Office of Enforcement is well-suited to investigate potential violations of the Standards of Conduct and to propose remedies, including structural remedies if necessary, to ensure that the separation of functions and information restrictions are fully implemented. We believe that the increased clarity and transparency adopted in other parts of this Final Rule, when coupled with the Standards of Conduct rules and our rigorous enforcement program, will ensure that the functional unbundling requirement will serve its original purpose.

C. Applicability of the Final Rule

1. Non-ISO/RTO Public Utility Transmission Providers

124. In the NOPR, the Commission proposed to apply the Final Rule to all public utility transmission providers, including those that are approved ISOs and RTOs. With respect to non-ISO/RTO transmission providers, the Commission proposed to require all such transmission providers to submit FPA section 206 compliance filings, within 60 days after the publication of the Final Rule in the Federal Register, that contain the non-rate terms and conditions set forth in the Final Rule. The Commission also acknowledged that certain non-rate terms and conditions, such as Attachment C (relating to the transmission provider's ATC calculation methodology) and Attachment K (relating to the transmission provider's transmission planning process), may require more than 60 days to prepare and sought comment on an appropriate time period in which to require the submission of these attachments.

125. Following their FPA section 206 compliance filings, the Commission proposed that transmission providers could submit filings under FPA section 205 proposing rates for the services provided for in the tariff, as well as non-rate terms and conditions that differ from those set forth in the Final Rule if those provisions are ``consistent with or superior to'' the pro forma OATT. Comments

126. Several commenters ask the Commission to clarify and/or revise the proposal for dealing with previously-approved provisions that depart from the existing (Order No. 888) pro forma OATT. APPA contends that after this multi-phase rulemaking (NOI/NOPR/Final Rule) to revise the OATT, the Commission should hold those public utility transmission providers that propose non-rate terms and conditions differing from the new pro forma OATT to a high standard of proof under the ``consistent with or superior to'' standard. According to APPA, any non-rate term and condition that differs from the revised pro forma OATT should be ``additive'' in nature (for example, a new service offering, such as network contract demand service) or should propose substantive improvements in transmission service to customers. APPA argues that a public utility transmission provider should not be able to make an FPA section 206 compliance filing to implement the pro forma OATT and then ``water down'' its new OATT through an FPA section 205 filing that degrades its transmission service offerings or diminishes the quality of that service.

127. In its reply comments, APPA recommends that the Commission require non-ISO/RTO transmission providers to file the new pro forma OATT set out in the Final Rule and add in redline--either in that filing, or a companion one--all previously approved transmission provider-specific

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provisions. APPA states that transmission providers should then explain whether they propose to include these provisions in their revised OATTs, why they propose to retain or delete these provisions, and whether they believe these provisions are ``affected by the revisions adopted in the Final Rule.''

128. In contrast, Duke and EEI ask the Commission to clarify that transmission providers with previously-approved departures from the OATT that are not related to the reforms adopted in this Final Rule will not be required to rejustify these provisions in their FPA section 206 compliance filings. They also ask that transmission providers not be required first to adopt all of the provisions of the revised pro forma OATT and then make an FPA section 205 filing to refile a departure previously approved by the Commission. They recommend that existing, approved departures from the pro forma OATT that are not affected in a substantive way by the changes to the pro forma OATT should be included in the initial FPA section 206 filing.\104\ On reply, Indianapolis Power agrees with Duke and EEI and urges the Commission to consider the unwieldy and cost prohibitive nature of a process that would require transmission providers to demonstrate that previously-accepted elements of their OATTs are acceptable.

\104\ Duke and EEI propose that a utility would redline its compliance filing OATT against the revised pro forma OATT so that the Commission can readily identify the ``already-approved'' differences.

129. Duke and EEI, in their reply comments, argue that APPA's approach would be inefficient and would cause a substantial disruption to transmission service because both transmission providers and transmission customers would be required to abandon tariff provisions that the Commission has previously found to be consistent with or superior to the pro forma OATT and that are regularly being used. For example, Duke notes, Duke Carolina has an Attachment K that covers the Independent Entity that will oversee the provision of transmission service by Duke. Duke asserts that a literal interpretation of the NOPR proposal would mean that it would have to delete this attachment and replace its entire OATT with the revised pro forma OATT and then refile its entire Independent Entity proposal with its FPA section 205 filing. Similarly, Entergy states that it currently has a pro forma Generator Imbalance Agreement in place that was agreed to by the IPPs on its system and accepted by the Commission. Entergy urges the Commission to permit transmission providers to propose their own imbalance pricing methodology as long as the proposed generator imbalance charges are consistent with or superior to the generator imbalance provisions ultimately adopted in the OATT.

130. On reply, NRECA opposes EEI's compliance proposal. NRECA states that the Commission should retain the two-phased compliance procedure proposed in the NOPR because it strikes a fair balance by providing transmission providers the opportunity to suggest changes to their pro forma OATTs under FPA section 205, while allowing transmission customers and others the opportunity to argue that the deviations from the new pro forma OATT are neither consistent with nor superior to the pro forma OATT.

131. NRECA acknowledges that there will be a burden on the transmission provider to prepare a compliance filing; however, it urges the Commission to retain its proposal and require transmission providers to identify those terms and conditions that differ from the pro forma OATT. NRECA agrees that, if a term or condition unrelated to any modification of the pro forma OATT in the instant rulemaking has already been found to be consistent with or superior to the existing Order No. 888 pro forma OATT, it likely continues to be consistent with or superior to the revised pro forma OATT term or condition. NRECA argues, however, that a public utility transmission provider should still be required in a compliance filing to identify these deviations from the revised pro forma OATT and, ultimately, to justify them in the event that they are fairly contested. Otherwise, NRECA contends, the Commission and industry lose the consistency and related advantages the pro forma OATT seeks to provide.

132. Several commenters addressed the deadlines proposed in the NOPR. APPA suggests that the Commission set a 60 or 90-day deadline for those provisions the transmission provider can complete itself and a 120 or 180-day deadline for those provisions and attachments that will require the transmission provider to incorporate regional practices and protocols, such as Attachments C and K. Tacoma proposes 180 days for transmission providers to submit Attachments C and K. PGP recommends that transmission providers be given one year to file Attachment K.

133. EEI and National Grid urge the Commission to align the compliance filing deadlines for ISOs and RTOs and their transmission- owning members in order to eliminate any potential confusion and to enhance coordination within the ISOs and RTOs. To the extent that public utility transmission owners whose transmission facilities are under the control of RTOs and ISOs have filing rights under the RTO or ISO tariffs, EEI asks that such public utility transmission owners be required to submit any necessary tariff filings within 90 days after the effective date of the Final Rule, rather than the currently- proposed 60 days. National Grid suggests that the Commission establish a single deadline for ISOs/RTOs and their transmission-owning members, set at six months from the date of publication of the Final Rule.

134. TDU Systems recommend that the Commission adopt a staggered filing approach for the compliance filings (i.e., have transmission providers come in at different times based on criteria chosen by the Commission, such as alphabetically or by size). TDU Systems argue that this would ensure that transmission customers are not forced to review all of their transmission providers' filings at the same time.

Commission Determination

135. The Commission adopts the two-tiered implementation process proposed in the NOPR, with certain clarifications and modifications, as discussed below. As the Commission proposed in the NOPR, all transmission providers that have not been approved as ISOs or RTOs, and whose transmission facilities are not under the control of an ISO or RTO, are required to submit FPA section 206 compliance filings that contain the revised non-rate terms and conditions set forth in the Final Rule, within 60 days after the publication of the Final Rule in the Federal Register.\105\ However, this filing only need to contain the revised provisions adopted in the Final Rule, rather than the transmission provider's entire pro forma OATT.\106\ After the submission of their

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FPA section 206 compliance filings, these transmission providers may submit FPA section 205 filings proposing rates for the services provided for in the tariff, as well as non-rate terms and conditions that differ from those set forth in the Final Rule if those provisions are ``consistent with or superior to'' the pro forma OATT.

\105\ The Commission clarifies that existing waivers of the obligation to file an OATT or otherwise offer open access transmission service in accordance with Order No. 888 shall remain in place. The reforms to the pro forma OATT adopted in this Final Rule therefore do not apply to transmission providers with such waivers, although we expect those transmission providers to participate in the regional planning processes in place in their regions, as discussed in more detail in section V.B. Whether an existing waiver of OATT requirements should be revoked will be considered on a case-by-case basis in light of the circumstances surrounding the particular transmission provider.

\106\ As explained below, the Commission is not requiring transmission providers to submit in their compliance filing tariff sheets associated with provisions of the pro forma OATT that have not been modified in this proceeding. To the extent, however, a transmission provider desires to refile its entire OATT in order to simplify pagination or other tariff designation issues associated with implementing the modifications required under the Final Rule, it may do so. We note that such a filing is a compliance filing and, therefore, the only deviations in this filing should be the revised provisions in this Final Rule. If a transmission provider wishes to propose different terms and conditions, it must make a separate FPA section 205 filing.

136. The Commission recognizes that, since the issuance of Order No. 888, some non-ISO/RTO transmission providers have received approval from the Commission to adopt variations from the non-rate terms and conditions of the pro forma OATT that are consistent with or superior to the Order No. 888 pro forma OATT. Under the compliance procedure adopted above, those variations that are not affected in a substantive manner by the reforms to the pro forma OATT adopted in this Final Rule may remain in place. We disagree with the implementation procedures proposed by APPA, which would require non-ISO/RTO transmission providers with provisions in their OATTs that depart from the pro forma OATT, but which are not substantively affected by the reforms in this NOPR, to make a filing that explains whether and why they would retain or delete these provisions. We see no need to require non-ISO/RTO transmission providers to ``rejustify'' such provisions if they are not substantively affected by the reforms in this Final Rule, given that the Commission has already found these provisions to be consistent with or superior to terms and conditions set forth in the pro forma OATT that remain unchanged, and the Commission has not otherwise found these provisions to be unjust and unreasonable.

137. In other circumstances, however, non-ISO/RTO transmission providers may have provisions in their existing OATTs that the Commission deemed to be consistent with or superior to terms and conditions of the Order No. 888 pro forma OATT that are being modified by the Final Rule. Such transmission providers must demonstrate that these previously-approved variations continue to be consistent with or superior to the pro forma OATT as modified by the Final Rule. We continue to believe that use of the ``consistent with or superior to'' standard is appropriate when reviewing variations from the pro forma OATT and reject APPA's proposal to adopt a higher burden of proof.

138. The two-tiered compliance process adopted above will allow transmission providers with previously-approved variations an opportunity to show that their existing deviations continue to be consistent with or superior to the pro forma OATT as modified in the Final Rule. However, the Commission recognizes that it may cause disruption for some transmission providers that wish to continue to rely on previously-approved variations during the compliance process. The Commission therefore offers an optional implementation process for non-ISO/RTO transmission providers seeking approval of previously- approved variations.

139. Transmission providers that have not been approved as ISOs or RTOs and whose transmission facilities are not under the control of an ISO or RTO may submit an FPA section 205 filing, within 30 days after the publication of the Final Rule in the Federal Register, seeking a determination that a previously-approved variation from the Order No. 888 pro forma OATT that has been substantively affected by the reforms adopted in this Final Rule continues to be consistent with or superior to the revised pro forma OATT adopted here.\107\ Each applicant should request that the proposed tariff provisions be made effective as of the date of the transmission provider's section 206 compliance filing, to be submitted within 60 days after the publication of the Final Rule in the Federal Register (as provided above). As a condition of that request, however, the transmission provider should state that the Commission has 90 days following the date of submission of the filing to act under section 205. In other words, the Commission is offering this optional implementation process to applicants that allow the Commission 90 days to act on the filing. This procedure will streamline the compliance process by allowing existing variations from terms and conditions of the pro forma OATT that have been modified by the Final Rule to remain in effect until further Commission action, while also providing the Commission with adequate time to act on the filings. The subsequent section 206 compliance filing would then contain tariff sheets necessary to implement the remaining modifications required under the Final Rule, i.e., modifications related to tariff provisions that did not implicate previously-approved variations.

\107\ Transmission providers must provide citations to the Commission orders where the variation was accepted by the Commission as consistent with or superior to the pro forma OATT.

140. As the Commission acknowledged in the NOPR, certain non-rate terms and conditions, such as Attachment C (relating to the transmission provider's ATC calculation methodology) and Attachment K (relating to the transmission provider's transmission planning process) may require more than 60 days to prepare. Accordingly, we will require non-ISO/RTO transmission providers to file their Attachment C within 180 days after the publication of the Final Rule in the Federal Register and their -Attachment K (or the transmission providers' equivalent thereof) within 210 days after the publication of the Final Rule in the Federal Register. A summary of the more significant filing requirements established in this Final Rule is provided in Appendix A.\108\

\108\ For further information related to the Final Rule, such as electronic versions of the pro forma OATT showing tariff changes adopted in the Final Rule in redline/strikeout format, and further information regarding docketing of compliance filings and specific filing instructions, please visit our Web site at the following location http://www.ferc.gov/industries/electric/indus-act/oatt-reform.asp .

141. Other reforms adopted in the Final Rule will involve coordination with the North American Energy Standards Board (NAESB) to establish OASIS functionality or uniform business practices. The Commission requests that NAESB file a status report within 90 days of publication of the Final Rule in the Federal Register that contains a work plan for development of such OASIS functionality and business practices. This work plan should indicate, for each reform, what actions are necessary and an estimate of the timeframe for completing those actions. Pending resolution of these issues with NAESB, the Commission requires that each transmission provider develop its own OASIS functionality or business practice necessary to implement each such reform within 90 days of publication of the Final Rule in the Federal Register, unless a different compliance requirement is otherwise specified in this Final Rule. Upon review of this work plan, the Commission will issue an order establishing further compliance deadlines as necessary.

142. We are not persuaded to adopt a staggered compliance filing approach in this proceeding as TDU Systems suggest. However, we will align the compliance filing deadlines for ISOs and RTOs and their transmission-

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owning members in order to eliminate any potential confusion and to enhance coordination within the ISOs and RTOs. Thus, we will require public utility transmission owners whose transmission facilities are under the control of RTOs and ISOs to make any necessary tariff filings required to comply with the Final Rule within 210 days after the publication of the Final Rule in the Federal Register. 2. ISO and RTO Public Utility Transmission Providers and Transmission Owner Members of ISOs and RTOs

143. With respect to an ISO or RTO public utility transmission provider, the Commission recognized in the NOPR that such an entity may already have tariff terms and conditions that are superior to the pro forma OATT. The Commission also noted that the purpose of this rulemaking is not to redesign approved, fully-functioning RTO or ISO markets. Thus, the Commission proposed to require ISO and RTO transmission providers to submit FPA section 206 compliance filings, within 90 days after the publication of the Final Rule in the Federal Register, that contain the non-rate terms and conditions set forth in the Final Rule or that demonstrate that their existing tariff provisions are consistent with or superior to the revised provisions to the pro forma OATT. The Commission also proposed to allow ISO and RTO transmission providers, after making their FPA section 206 compliance filings, to submit filings under FPA section 205 proposing rates for the services provided for in their tariffs, as well as non-rate terms and conditions that differ from their existing tariffs and those set forth in the Final Rule if those provisions are consistent with or superior to the pro forma OATT. The Commission did not address the specific obligations of transmission owning members of ISOs and RTOs. Comments

144. Several commenters support applying the revised pro forma OATT to ISOs and RTOs and requiring ISOs and RTOs to justify any variations therefrom. MidAmerican argues that universal application of the revised pro forma OATT is important because not every ISO or RTO transmission provider has existing tariff terms and conditions that are consistent with or superior to the OATT. Old Dominion also supports the Commission's compliance proposals for ISOs and RTOs. NRECA similarly states that RTOs, ISOs and ITCs should not be automatically exempt from any aspect of the rules governing open access transmission service, including the planning requirements. APPA asserts that in their filings, RTOs should be required to show how their transmission service packages, including features such as long term transmission rights, ancillary services, and treatment of losses, are consistent with or superior to the newly revised pro forma OATT. Moreover, APPA argues, the Commission should not allow RTOs to use their avowed independence as a justification for transmission services that in fact do not meet the consistent with or superior to standard.\109\

\109\ See also CMUA Reply.

145. On the other hand, numerous commenters argue that the proposed compliance process is burdensome and could require ISOs and RTOs to have to relitigate already-approved OATT provisions. The ISOs and RTOs generally argue that, given the nature of the services they offer, many of the proposed revisions do not apply to their OATTs. Many commenters urge the Commission to adopt a more limited compliance filing process. Some commenters, for example, argue that the Commission should only require ISOs and RTOs to submit compliance filings that are limited to the specific pro forma tariff revisions set forth in the Final Rule. Duke argues that ISOs and RTOs should only be required to make a single filing that revises their OATTs in a manner that takes into account the nature of the OATT service provided by that ISO or RTO and whether a reform adopted in the Final Rule is relevant to the ISO's or RTO's OATT. EEI urges the Commission to require ISOs and RTOs to adopt only those OATT reforms that are necessary to improve the quality of transmission service that is provided by an ISO or RTO. EEI adds that those who protest an ISO's or RTO's assertion that an existing provision is consistent with or superior to the revised pro forma OATT should have the burden to demonstrate otherwise. The ISOs and RTOs similarly argue that, absent a specific demonstration that an ISO's or RTO's OATT provisions are unjust and unreasonable, the compliance filing requirements should not apply to ISOs and RTOs.

146. EEI urges the Commission to clarify that the 90-day filing should include the following materials: Revisions of tariff provisions that conform to the revisions in the pro forma OATT that are appropriate, given the ISO or RTO's market structure; statements supporting the provisions of the tariff that the ISO or RTO believes are consistent with or superior to the revised pro forma OATT; and justifications that support excluding revisions of the provisions that the ISO or RTO believes are not consistent with or superior to the revised pro forma OATT. EEI also interprets the NOPR proposal to mean that an ISO or RTO immediately may make a separate filing proposing further modifications, including revisions to the newly-effective provisions of the pro forma OATT, that are consistent with or superior to the just-filed modifications.

147. SPP urges the Commission to affirm that ISOs and RTOs will not be required to rejustify their previously-approved non-pro forma tariff provisions, but rather only the new or revised tariff provisions expressly prescribed in the Final Rule. In its reply comments, SPP notes that the terms and conditions of its OATT are interrelated and work together to achieve a system of administration that fosters open and transparent transmission service and function as an integrated whole. Therefore, SPP asserts, the modification of one provision of its OATT will impact several other provisions and the process of rejustifying one aspect of the tariff likewise will implicate other terms and conditions.

148. Indianapolis Power argues that tariff changes resulting from this rulemaking should be included only with the support of the ISO and RTO members who bear the costs and are in the best position to judge the benefits.

149. On reply, ISO/RTO Council generally argues that there is no factual or legal support for the ISO/RTO compliance procedures advocated by commenters such as APPA. ISO/RTO Council states that the OATTs of ISOs and RTOs were developed through extensive stakeholder procedures and subject to the Commission's filing, notice, comment, and approval processes under FPA section 205. ISO/RTO Council asserts that to adopt the post-hoc, open-ended review advocated by these parties would give disgruntled participants a ``second bite'' at legally effective OATT terms and would undermine the very stakeholder and regulatory processes by which ISOs and RTOs were established. MISO in particular argues that APPA's proposal ignores that ISO and RTO tariffs have already been determined to be just and reasonable and consistent with or superior to the Order No. 888 pro forma OATT, is profoundly inconsistent with the Commission's policy of encouraging RTOs as an option to ensure non-discriminatory open access transmission service, and is impracticable unless the intent is to grind RTO markets to a halt. MISO states that each RTO tariff has

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dozens, or perhaps hundreds, of Commission-approved deviations and, in its view, reopening these issues would not be in the public interest and would consume enormous resources of both the RTOs and the Commission.

150. Southern, in its reply comments, argues that ISOs and RTOs are essentially requesting to be exempted from the requirements of this proceeding. Southern states that all transmission service revisions/ reforms adopted in this proceeding should apply uniformly to all transmission providers, including ISOs and RTOs. Southern contends that ISOs and RTOs are increasingly subject to complaints alleging discriminatory treatment and asserts that the highly partisan attacks made by several RTOs against vertically-integrated utilities further calls into question whether ISOs and RTOs are not susceptible to taking discriminatory actions. In addition, Southern argues, such exemptions would likely result in seams issues.

151. Some commenters state that the Commission should identify the specific reforms it will apply to RTOs and ISOs and provide more general guidance as to how it intends to apply the consistent with or superior to standard to ISO/RTO tariff provisions. National Grid asserts that the Commission properly identified these provisions in the NOPR when the Commission concluded that there may be elements of the proposed reforms that are superior to what currently exist in some RTOs or ISOs, e.g., transparency, data exchange, or planning. MISO/PJM States identify six areas as potentially applicable to RTOs: Hourly firm transmission service; obligation to expand capacity; joint ownership; reservation priority; ancillary services; and pro forma OATT definitions. MISO/PJM States also identify eleven areas as not applicable to RTOs: Undue discrimination generally; transmission pricing; remedies, penalties and enforcement; changes in receipt and delivery points (redirects); rollover rights; rules, standards and practices governing the provision of transmission service; joint transmission planning; tariff compliance review; hoarding of transmission capacity; curtailments; and ancillary services. APPA, in its reply comments, opposes granting a blanket exemption for ISOs and RTOs from any portion of the compliance filing requirement.

152. CAISO urges the Commission to clarify how it should provide for changes in the Final Rule to transmission services that it does not provide or which are clearly incompatible with the transmission service model it employs. In their reply comments, CMUA and APPA oppose this request for clarification. CMUA argues that CAISO's failure to provide any long-term transmission service renders its transmission service markedly inferior to the firm transmission service under the pro forma OATT. CMUA maintains that, instead of affirmatively embracing its obligation to show that its transmission service offering, once supplemented with long-term transmission rights that fully comply with all seven guidelines set out in Order No. 681, will meet the ``consistent with or superior to'' standard of Order No. 888, CAISO instead asks to be exempted from any such requirement.

153. Xcel and Indicated New York Transmission Owners assert that the Commission should allow regional variations to the extent that ISOs/RTOs can demonstrate that their OATT provisions meet the objectives of the Final Rule. Xcel argues that the consistent with or superior to standard may be too narrow because some changes to the OATT made by ISOs/RTOs are not as much ``superior'' or ``consistent with,'' as they are simply necessary because the tariff is regional. Indicated New York Transmission Owners argue that the Commission should not impose a consistent with or superior to standard generally reserved for transmission providers that are not members of an ISO/RTO. Indicated New York Transmission Owners assert that, to the extent that certain improvements could or should be made to the ISO/RTO OATTs, the Final Rule should permit the necessary flexibility for each ISO/RTO to propose and adopt such changes through their stakeholder governance processes, in order to address the unique market features and circumstances of each region.

154. PJM urges the Commission to include an ``independent entity variation'' standard similar to that used in Order No. 2003, which permitted an RTO to adopt interconnection procedures that are responsive to specific regional needs. NRECA responds that the Commission should not entertain PJM's request. While PJM's requested standard may have made sense in the context of generator interconnections, NRECA contends that it is inapposite to reform of the OATT. NRECA states that ISOs and RTOs should not be allowed to keep on file tariff provisions that possess the potential to allow for undue discrimination, even if the entity publishing the tariff is ostensibly independent of market participants and even if the proposed reforms do not directly improve the ``quality of'' transmission service, since the purpose of this rulemaking is to prevent undue discrimination in the provision of transmission service.

155. To whatever extent the Commission elects to exempt RTOs and ISOs from certain aspects of the pro forma OATT, E.ON asserts that the same consideration should be given to utilities that have entered into arrangements with alternative, Commission-approved, independent transmission organizations. In their reply comments, TDU Systems oppose this proposal arguing that these alternative constructs may not meet the independence criteria of Order Nos. 888 and 2000.

156. Several commenters urge the Commission to extend the proposed 90-day deadline for ISOs and RTOs to submit their compliance filings. EEI recommends that the Commission clarify that it will grant an extension of time if the stakeholder process prevents an ISO or RTO from obtaining stakeholder approval of tariff changes within the 90-day deadline. SPP requests a minimum of 120 days for compliance. National Grid and MISO (in its reply comments) propose that the Commission establish a single deadline for ISOs/RTOs and their transmission-owning members set at six months from the date of publication of the Final Rule. Commission Determination

157. The Commission adopts the compliance procedures proposed in the NOPR, with certain revisions and clarifications. We will require ISO and RTO transmission providers to submit FPA section 206 compliance filings, within 210 days after the publication of the Final Rule in the Federal Register, that contain the non-rate terms and conditions set forth in the Final Rule or that demonstrate that their existing tariff provisions are consistent with or superior to the revised provisions of the pro forma OATT. As with non-ISO/RTO transmission providers, however, we will not require ISO and RTO transmission providers to ``rejustify'' existing provisions in their OATTs that are not affected in a substantive manner by the revisions to the pro forma OATT in the Final Rule. As we explained above, we find that such a process is unnecessary, given that we have already found these provisions to be consistent with or superior to the Order No. 888 pro forma OATT and these provisions are not substantively affected by the reforms we adopt today.

158. We also recognize, as we did in the NOPR, that some of the changes adopted in the Final Rule may not be as relevant to ISO/RTO transmission

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providers as they are to non-independent transmission providers. For example, many ISOs and RTOs use bid-based locational markets and financial rights to address transmission congestion, rather than the first-come, first-served physical rights model set forth in the pro forma OATT. As we indicated in the NOPR, nothing in this rulemaking is intended to upset the market designs used by existing ISOs and RTOs. We also recognize that ISOs and RTOs may well have adopted practices that are already consistent with or superior to the reforms adopted here. For example, ISOs and RTOs tend to have transmission planning processes that are significantly more open and transparent than the processes used by non-independent transmission providers. We encourage ISOs and RTOs to meet with their stakeholders to discuss whether any improvements are necessary to comply with the Final Rule.

159. We reject Indianapolis Power's proposal to require tariff changes resulting from this rulemaking only with the support of the ISO and RTO members who may bear the costs associated with the revision. Indianapolis Power effectively asks that we allow ISO and RTO members to veto our decisions here, which is contrary to our duty to prevent undue discrimination in the provision of transmission service.

160. Regarding CAISO's request for clarification of how it should address changes in the Final Rule to transmission services that it does not provide or which are incompatible with its service model, we reiterate that CAISO--like any other ISO or RTO--has the opportunity to demonstrate that a variation from the tariff revisions adopted in the Final Rule satisfies the consistent with or superior to standard. We do not believe that the adoption of an ``independent entity variation,'' proposed by PJM, or a regional variation standard, proposed by Xcel and Indicated New York Transmission Owners, would be appropriate. Again, the Commission finds that the reforms adopted in this Final Rule are necessary to prevent undue discrimination in the provision of transmission service and any transmission provider, including an ISO or RTO, must demonstrate that variations from the tariff modifications required here satisfy the consistent with or superior to standard.

161. As discussed above, however, we will align the compliance filing deadlines for ISOs and RTOs and their transmission-owning members and require public utility transmission owners whose transmission facilities are under the control of RTOs or ISOs to make any necessary tariff filings required to comply with the Final Rule within 210 days after the publication of the Final Rule in the Federal Register. A summary of the more significant filing requirements established in this Final Rule is provided in Appendix A.\110\

\110\ For further information related to the Final Rule, such as electronic versions of the pro forma OATT showing tariff changes adopted in the Final Rule in redline/strikeout format, and further information regarding docketing of compliance filings and specific filing instructions, please visit our Web site at the following location http://www.ferc.gov/industries/electric/indus-act/oatt-reform.asp .

3. Non-Public Utility Transmission Providers/Reciprocity

162. In Order No. 888, the Commission conditioned non-public utilities' use of public utility open access services on an agreement to offer comparable transmission services in return.\111\ The Commission found that, while it did not have the authority to require non-public utilities to make their systems generally available, it did have the ability and the obligation to ensure that open access transmission is as widely available as possible and that Order No. 888 did not result in a competitive disadvantage to public utilities.

\111\ These entities are not FPA public utilities and therefore are not subject to the Commission's jurisdiction under sections 205 and 206 of the FPA.

163. Under the reciprocity provision in section 6 of the pro forma OATT, if a public utility seeks transmission service from a non-public utility to which it provides open access transmission service, the non- public utility that owns, controls, or operates transmission facilities must provide comparable transmission service that it is capable of providing on its own system. Under the pro forma OATT, a public utility may refuse to provide open access transmission service to a non-public utility if the non-public utility refuses to reciprocate. A non-public utility may satisfy the reciprocity condition in one of three ways. First, it may provide service under a tariff that has been approved by the Commission under the voluntary ``safe harbor'' provision. A non- public utility using this alternative submits a reciprocity tariff to the Commission seeking a declaratory order that the proposed reciprocity tariff substantially conforms to, or is superior to, the pro forma OATT. The non-public utility then must offer service under its reciprocity tariff to any public utility whose transmission service the non-public utility seeks to use. Second, the non-public utility may provide service to a public utility under a bilateral agreement that satisfies its reciprocity obligation. Finally, the non-public utility may seek a waiver of the reciprocity condition from the public utility.\112\

\112\ See Order No. 888-A at 30,285-86.

164. In EPAct 2005, Congress authorized, but did not require, the Commission to order non-public utilities (or ``unregulated transmitting utilities'') to provide transmission services under a new section 211A in Part II of the FPA. This section states in part that the Commission ``may, by rule or order, require an unregulated transmitting utility to provide transmission services'' at rates that are comparable to those it charges itself and under terms and conditions (unrelated to rates) that are comparable to those it applies to itself, and that are not unduly discriminatory or preferential. The language does not limit the Commission to ordering transmission services only to the public utility from whom the non-public utility takes transmission services, but rather permits the Commission to order the non-public utility to provide ``open access'' transmission service, i.e., service to all eligible customers.

165. In the NOPR, the Commission proposed to retain the current reciprocity language in the pro forma OATT, as well as Order No. 888's three alternative provisions for satisfying the reciprocity condition, i.e.: A non-public utility that owns, controls, or operates transmission and seeks transmission service from a public utility must either satisfy its reciprocity obligation under a bilateral agreement, seek a waiver of the OATT reciprocity condition from the public utility, or file a safe harbor tariff with the Commission.\113\

\113\ For non-public utilities that choose to use the safe harbor tariff, the Commission noted in the NOPR that the existing safe harbor provisions would need to be substantially conforming or superior to the new pro forma OATT. A non-public utility that already has a safe harbor tariff would therefore be required to amend its tariff so that its provisions substantially conform or are superior to the new pro forma OATT if it wishes to continue to qualify for safe harbor treatment. As the Commission stated in Order No. 888-A, a non-public utility may limit the use of its voluntarily offered safe harbor reciprocity tariff only to those transmission providers from whom the non-public utility obtains open access service, as long as the tariff otherwise substantially conforms to the pro forma OATT. See Order No. 888-A at 30,289.

166. The Commission did not propose a generic rule to implement the new FPA section 211A.\114\ Rather, the Commission proposed to apply its provisions on a case-by-case basis, such as when a public utility seeks service

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from an unregulated transmitting utility that has not requested service under the public utility's OATT and the reciprocity obligation therefore does not apply. The Commission stated that such a customer may file an application with the Commission seeking an order compelling the unregulated transmitting utility to provide transmission service that meets the standards of FPA section 211A. The Commission further proposed to amend its regulations to make clear that an applicant in an FPA section 211A proceeding against a non-public utility that has submitted an acceptable safe harbor tariff has the burden of proof to show why service under the safe harbor tariff is not sufficient and why an FPA section 211A order should be granted. In addition, the Commission stated in the NOPR its expectation that unregulated transmission providers would participate in the proposed open and transparent regional planning processes and noted that, if there were complaints about such participation, they would also be addressed on a case-by-case basis.

\114\ The Commission noted in the NOPR that LPPC has committed to voluntary compliance with a set of guidelines for the provision of comparable service under FPA section 211A.

167. The NOPR proposed to retain the existing reciprocity policy as applied to foreign utilities doing business in the United States, which we adopted pursuant to sections 205 and 206 of the FPA. By maintaining the same reciprocity requirement for these foreign utilities as for domestic, non-public utilities, the Commission stated that it would ensure that foreign entities will continue to be treated no less favorably than domestic, non-public utilities. Comments

168. The majority of the commenters support the Commission's decisions to retain the reciprocity provision and to adopt a case-by- case approach to FPA section 211A.\115\ These commenters reason that there is no evidence of a general problem of non-public utilities failing to provide transmission service and that, for the most part, non-public utilities already provide transmission on an as-available basis under comparable terms, regardless of whether a tariff is on file with the Commission. In addition, Santa Clara and TANC state that the Commission's proposal apparently respects the nonjurisdictional status of public power.

\115\ E.g., APPA, Bonneville, LPPC, Newfoundland, NRECA, PGP, Sacramento, Salt River, Santa Clara, Santee Cooper, Seattle, TANC, TAPS, TVA, Tacoma, WAPA, CMUA Reply, East Texas Cooperatives Reply, Lassen Reply, and Public Power Council Reply.

169. LPPC reiterates its prior offer of voluntary compliance with a set of guidelines for the provision of comparable open access service, which it contends will provide a significant degree of standardization for such service. Thus, LPPC believes that generic action under section 211A is not necessary. In addition, LPPC asserts that there is no evidence on record of undue discrimination by a nonjurisdictional entity that would justify the Commission reversing the NOPR decision to act on a case-by-case basis under FPA section 211A.\116\

\116\ See also Public Power Council Reply and Sacramento Reply.

170. On the other hand, several commenters urge the Commission to implement FPA section 211A on a generic basis.\117\ AWEA argues that reciprocity tariffs do not subject the nonpublic utilities to Commission enforcement as would an OATT established under FPA section 211A. AWEA urges the Commission to proceed on a generic basis to ensure that nonjurisdictional utilities comply with the reformed OATT under exactly the same terms and conditions as jurisdictional utilities. On reply, however, APPA argues that the comparability standard does not mean that unregulated transmitting utilities must comply with the reformed OATT under exactly the same terms and conditions as jurisdictional entities.

\117\ E.g., AWEA, California Commission, Calpine, EEI, MidAmerican, San Diego G&E, and Xcel.

171. In its reply comments, EEI states that, while LPPC's voluntary proposal is a step in the right direction, LPPC's proposal does not go far enough to assure that reciprocal transmission service is provided in a non-discriminatory manner. EEI asserts that LPPC's proposal still gives the individual non-public utility transmission provider the discretion to decide what is or is not comparable and not unduly discriminatory. Moreover, EEI notes, LPPC does not represent the universe of non-public utility transmission providers, rather only 24 of the largest governmentally-owned transmission providers.

172. Some commenters argue that the case-by-case approach proposed in the NOPR does not satisfy the Commission's stated goal of remedying undue discrimination and its intent to provide transparent, consistent and clear rules for use of the nation's transmission grid.\118\ Calpine contends that the administrative burden of monitoring and administering customer complaints or processing applications that seek to compel unregulated transmitting utilities in different parts of the country to provide comparable service would create a ``patchwork of open and closed'' unregulated transmitting utilities, just like the patchwork of open and closed jurisdictional transmission systems the Commission sought to eliminate when it issued Order No. 888. Calpine also states that its comments on the NOI in this proceeding provide several examples of the kinds of problems it has experienced in seeking transmission service from unregulated transmitting utilities in a variety of regions and across multiple transmission systems.

\118\ E.g., Calpine, MidAmerican, and Xcel.

173. California Commission argues that FPA section 211A gives the Commission the authority to require previously nonjurisdictional entities to file tariffs with the Commission that would be subject to the due process and the ``just and reasonable'' requirements of the FPA. California Commission urges the Commission to actively explore a set of mandatory actions that the Commission may impose on nonjurisdictional entities and states that, if the Commission is reluctant to do so in this proceeding, it should initiate a new rulemaking to consider such rules. California Commission asserts that there are a number of sound policy reasons for taking generic action to address the mandate of FPA section 211A. First, it argues that Commission action would prevent the balkanization of the grid that can result if a nonjurisdictional transmission owner refuses to participate in an RTO or ISO whose service area surrounds, encompasses, or overlaps it. Second, California Commission argues that Congress has given the Commission explicit authority to require previously nonjurisdictional entities to provide transmission service on a non-preferential and non- discriminatory basis. Finally, California Commission asserts, the Commission would be able to squarely address generic seams issues created by the existence of control areas operated by previously unregulated transmission owners and the ability of such entities to ``free ride'' on the systems and open access requirements of the jurisdictional entities.

174. In its reply comments, CMUA contests California Commission's assertion that those outside CAISO operations are ``free riders.'' CMUA notes that its members post their excess transmission capacity on wesTTrans (an OASIS site serving the Western Interconnection) thus making it available to third parties, and that its members outside the CAISO also pay a

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host of CAISO fees.\119\ CMUA states that it does not contest that there are ``seams'' between organized markets and neighbors, but it asserts that this docket is not the place for this discussion and FPA section 211A is not the remedy. In its reply comments, APPA also urges the Commission to reject California Commission's proposal. APPA argues that section 211A was not intended, nor could the Commission use it, to require nonjurisdictional transmission providers to participate in an RTO and, therefore, California Commission's proposal exceeds the Commission's authority under section 211A.\120\

\119\ See also APPA Reply.

\120\ See also CMUA Reply and Santa Clara Reply.

175. EPSA, in its reply comments, disagrees with commenters who appear to believe that nonjurisdictional transmitting utilities will not have to take any steps to comply with a final order in this rulemaking. EPSA states that its understanding is that the Commission's principle of reciprocity would apply to any changes in the pro forma OATT adopted in the Final Rule. Accordingly, both jurisdictional and nonjurisdictional transmitting utilities that adopted the Order No. 888 pro forma OATT would have to make compliance filings. In addition, EPSA argues that nonjurisdictional transmitting utilities that previously received an Order No. 888 waiver or that wish to request such a waiver should have an affirmative duty to file a request for a waiver. In the event that a nonjurisdictional entity wishes to file a bilateral contract, EPSA contends that it should be required to file a ``reciprocity'' contract pursuant to FPA section 205. If a nonjurisdictional transmitting utility does not adopt a revised pro forma OATT as a ``safe harbor,'' EPSA argues the Commission's standard of review should be whether the nonjurisdictional transmitting utility's alternative tariff is ``equal or superior to'' a revised pro forma OATT.

176. EPSA, in its reply comments, supports implementing the rate provisions of FPA section 211A in a proceeding separate from this particular proceeding. EPSA states that such a proceeding could take a generic approach, in that nonjurisdictional transmitting utilities could be required to set transmission rates for third-party transmission services that are computed using rate determinants that are comparable to the determinants that the non-public utility uses to calculate transmission rates for its native load.

177. With regard to specific reciprocity obligations, LPPC argues that the Commission should revise section 6 of the pro forma OATT to reflect the comparability standards now contained in FPA section 211A. LPPC states that, with the implementation of FPA section 211A, it is appropriate to revise the pro forma OATT language in order to reflect the unregulated utility's obligation ``to provide transmission service comparable to the service the customer provides itself'' as the ``quid pro quo'' for receiving reciprocal service. LPPC also argues that, with respect to the existing safe harbor option, the Commission should revise its test for evaluating a safe harbor OATT from one which asks whether the proposal is equivalent or superior to the pro forma OATT, to one which asks whether the service provided under the proposed OATT is comparable to the service that the unregulated utility provides itself.

178. EPSA replies that LPPC's suggestion to revise the language of section 6 ironically would require nonjurisdictional transmitting utilities to offer third party customers transmission services that are comparable to network transmission service, which is a higher quality of transmission service than the revised OATT and which is unlikely to be supported by nonjurisdictional transmitting utilities. EPSA states that it believes that FPA section 211A requires a nonjurisdictional transmitting utility to provide transmission service (at its interfaces with jurisdictional public utilities and internal sources) that is comparable to the service it is taking at interfaces or internal sources. EPSA therefore argues that the appropriate standard for determining whether a nonjurisdictional transmitting utility's tariff is comparable is whether the nonjurisdictional utility's tariff is ``equal or superior'' to the revised pro forma OATT.

179. LPPC also argues that the two categorical exemptions from FPA section 211A articulated in FPA section 211A(c)(3) (based on size and the value of the unregulated system to the integrated grid) should not be exclusive. Rather, LPPC contends that the two exemptions should guide the Commission in considering similar requests for exemption. For example, LPPC argues that relatively small utilities, which nevertheless exceed an express threshold, should be permitted to demonstrate that their systems are simply too small, and that their facilities are not sufficiently strategic, to call for full inclusion in the FPA section 211A regime. Similarly, LPPC states that, in certain public systems, only some discrete portions of the system would fairly be considered part of the integrated system. In these cases as well, LPPC argues, it would make sense for the Commission to entertain requests for partial waiver.

180. If the Commission does not reconsider its proposal not to act generically under FPA section 211A, EEI contends that there are other actions the Commission should take. In order to facilitate full compliance with the reciprocity obligation, EEI urges the Commission at least to clarify and strengthen the obligations of non-public utility transmission providers under the reciprocity provision,\121\ exercise oversight and monitor their compliance with the reciprocity obligation, and require them to provide greater transparency of the transmission services and the terms and conditions of service they offer so that those seeking transmission service under the reciprocity provision are able to determine whether they are complying with their reciprocity obligation.

\121\ Xcel and MidAmerican support EEI's proposal on this issue.

181. With respect to the reciprocity provision in the pro forma OATT, EEI requests that the Commission update it by including reference to transmission service by ISOs and RTOs. EEI asks that the reciprocity provision be modified to provide that, if an ISO or RTO is the transmission provider, the reciprocity obligation is owed to all members of the ISO or RTO. EEI notes, however, that even this action would not require non-public utility transmission providers to provide transmission services to other entities who are eligible customers under the ISO or RTO OATT and who are not transmission providers, such as independent generators. EEI asserts that non-public utility transmission providers may discriminate against certain transmission customers unless the reciprocity obligation is expanded. Sempra Global also asks the Commission to clarify that the right to seek transmission service from an unregulated transmitting utility pursuant to FPA section 211A is available to any entity that qualifies as an eligible customer under the Commission's pro forma OATT.

182. EEI acknowledges that the Commission declined in Order No. 888-A to expand the reciprocity provision beyond the specific transmission provider from which the transmission customer takes service on the ground that requiring ``non-public utilities to offer transmission service to entities other than public utility transmission providers increases the chances that they could lose tax-exempt status.'' \122\ However, EEI states, in 2002, the

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Department of the Treasury adopted final regulations that in effect provide that providing open access transmission does not constitute private use.\123\ Therefore, EEI argues, this reason for limiting the services provided under the reciprocity obligation is no longer applicable.\124\

\122\ Citing Order No. 888-A at 30,287.

\123\ Treas. Reg. Sec. 1.141-7(g).

\124\ EEI asserts that the Commission also has the authority to make this change under FPA section 211A, which provides that the Commission may not require a State or municipality to take action under that section that would violate a private utility bond rule. If a non-public utility transmission provider is concerned about the impact on the tax-exempt status of its bonds, EEI suggests that it could seek a waiver from the Commission.

183. Moreover, EEI argues, as originally established in Order Nos. 888 and 888-A, the Commission stated that it was ``conditioning the use of public utility open access tariffs, by all customers including non- public utilities, on an agreement to offer comparable (not unduly discriminatory services) in return.'' \125\ However, EEI states, the reciprocity provision of the pro forma OATT refers to ``similar terms and conditions'' but does not make clear what they should be ``similar'' to. EEI argues that the term ``similar'' does not necessarily encompass the requirement that is part of comparability that the services provided be ``not unduly discriminatory'' as Order Nos. 888 and 888-A require. EEI proposes that the pro forma OATT be amended to refer to ``comparable terms and conditions'' rather than ``similar'' to align it with Order Nos. 888 and 888-A. Finally, EEI also states that the Commission should also reaffirm that the reciprocity obligation is binding on Canadian utilities.

\125\ Citing Order No. 888-A at 30,285.

184. On reply, APPA urges the Commission to reject EEI's proposed expansion of the reciprocity provision. APPA notes that EEI's proposed application of the reforms to all non-public utility transmission providers would potentially include a broader universe of public power entities than those subject to FPA section 211A. Moreover, APPA argues, many of the goals that EEI claims it wishes to accomplish would be accomplished even if the Commission takes no action.

185. In its reply comments, the Canadian Electricity Association urges the Commission to reject EEI's proposal to strengthen the reciprocity obligation so as to require the offering of transmission service to all eligible customers. The Canadian Electricity Association argues that the effect of EEI's proposal would be to enable a generator generating power in Canada to obtain access on a Canadian utility's transmission system, which is not the situation under the current reciprocity requirement. Consequently, the Canadian Electricity Association asserts, EEI's proposal would allow the Commission to fully impose open access requirements in Canada and would violate the principles of comity and undermine Canadian jurisdictional sovereignty.

186. The Canadian Electricity Association also repeats its earlier arguments made in response to the NOI that, to the extent the Commission adopts the comparability standard in FPA section 211A for non-public utilities, the Commission must apply the same changes to Canadian utilities.

187. EEI also urges the Commission to take certain steps to increase transparency and accountability in complying with the reciprocity requirement.\126\ For example, EEI states, the Commission could include on its Web site a list of all non-public utility transmission providers that have Commission-approved safe harbor reciprocity tariffs. According to EEI, such a list of entities would facilitate use of their transmission systems, provide transparency, and provide recognition to these entities for their voluntary efforts in accomplishing these goals.\127\

\126\ According to EEI, the new authority granted to the Commission under EPAct 2005 section 1281 (new FPA section 220) (Electricity Market Transparency Rules), which applies to all ``market participants,'' provides another basis for requiring greater transparency under the pro forma OATT by non-public utility transmission providers. EEI argues that the Commission could rely on this new authority to require greater transparency in transmission service provided under the reciprocity obligation.

\127\ EEI notes that, in the NOPR, the Commission referenced voluntary guidelines being developed by members of the LPPC. EEI believes this is a step in the right direction and looks forward to the opportunity to provide input on the proposed guidelines. In EEI's view, however, if any LPPC member wishes to use these guidelines as a safe harbor tariff, it must meet the safe harbor standard that the terms of service must be ``substantially conforming or superior to'' the revised OATT. The reciprocity obligation requires that the terms and conditions of service be comparable to those that the non-public utility transmission provider applies to itself and not be unduly discriminatory.

188. EEI requests that the Commission also establish minimal transparency requirements for non-public utility transmission providers.\128\ EEI asserts that the Commission has ample authority under FPA section 211A and under the reciprocity provision of the pro forma tariff to apply this information reporting requirement to those large non-public utility transmission providers that are not exempted by section 211A(c).\129\

\128\ EEI states that this informational filing should include information such as: whether or not they have a reciprocity or other tariff and how it can be obtained, whether they have an OASIS and location URL, whether they have standards of conduct and where they are posted, whether they have posted business practices, their contact for regional transmission planning, and their ATC methodology.

\129\ Section 211A authorizes the Commission to require certain unregulated transmitting utilities to provide transmission services at rates that are comparable to those that the unregulated transmitting utilities charges itself and on terms and conditions (not related to rates) that are comparable to those under which the unregulated transmitting utility provides transmission services to itself and that are not unduly discriminatory or preferential.

189. On reply, several commenters oppose EEI's transparency proposal. Among other things, they argue that EEI's proposal is unnecessary and duplicative of information that is already publicly available--e.g., the non-public utility's Web site, the Commission's Web site, or in some instances a regional entity's Web site (such as the wesTTrans OASIS).\130\ APPA further notes that LPPC has proposed that the terms and conditions in non-public utility transmission provider's tariffs would be publicly available on the individual utility's or a regional entity's Web site. In addition, NRECA asserts that, absent waivers, any non-public utility transmission provider that has adopted a ``safe-harbor'' tariff has adopted all of the OATT, OASIS, and Standards of Conduct requirements that apply to public utilities. NRECA and TANC both assert that the Commission does not have similar informational filing requirements for public utilities. Furthermore, TANC argues that it would be a waste of Commission resources to compile a list of all non-public utility transmission providers that have Commission-approved safe harbor tariffs. TANC also argues that to provide such an information filing would be unduly burdensome and a waste of nonjurisdictional utility transmission provider time and limited resources.

\130\ E.g., APPA Reply, CMUA Reply, LPPC Reply, Lassen Reply, NRECA Reply, Sacramento Reply, and TANC Reply.

Commission Determination

190. The Commission retains the reciprocity language in the Order No. 888 pro forma OATT, but updates it to include references to ISOs and RTOs, as suggested by EEI. We also modify the reciprocity provision to provide that, if an ISO or RTO is the transmission provider, the reciprocity obligation is owed to all members of that ISO or RTO. We concur with EEI's assessment that such modifications will more accurately reflect the current state of the industry. However, we will not adopt EEI's proposal to extend the reciprocity obligation to all eligible customers or

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LPPC's proposal to revise the pro forma OATT language regarding comparability. We are not persuaded that either proposal is necessary at this time to prevent undue discrimination absent a complaint.

191. We will also retain Order No. 888's three alternative provisions for satisfying the reciprocity condition, i.e.: A non-public utility that owns, controls, or operates transmission and seeks transmission service from a public utility must either satisfy its reciprocity obligation under a bilateral agreement, seek a waiver of the OATT reciprocity condition from the public utility, or file a safe harbor tariff with the Commission. Thus, for non-public utilities that choose to use the safe harbor tariff, its provisions must be substantially conforming or superior to the revised pro forma OATT in this Final Rule. A non-public utility that already has a safe harbor tariff must amend its tariff so that its provisions substantially conform or are superior to the revised pro forma OATT if it wishes to continue to qualify for safe harbor treatment. As the Commission stated in Order No. 888-A, a non-public utility may limit the use of its voluntarily offered safe harbor reciprocity tariff only to those transmission providers from whom the non-public utility obtains open access service, as long as the tariff otherwise substantially conforms to the pro forma OATT.\131\ We reiterate that these reciprocity requirements apply equally to all non-public utility transmission providers, including those located in foreign countries.

\131\ See Order No. 888-A at 30,289.

192. As the Commission proposed in the NOPR, we will not adopt a generic rule to implement the new FPA section 211A. Rather, we will apply its provisions on a case-by-case basis, such as when a public utility seeks service from an unregulated transmitting utility that has not requested service under the public utility's OATT and the reciprocity obligation therefore does not apply. A potential customer may file an application with the Commission seeking an order compelling the unregulated transmitting utility to provide transmission service that meets the standards of FPA section 211A. We adopt the NOPR proposal to amend our regulations to make clear that an applicant in an FPA section 211A proceeding against a non-public utility that has submitted an acceptable safe harbor tariff shall have the burden of proof to show why service under the safe harbor tariff is not sufficient and why an FPA section 211A order should be granted.\132\ Further, as we indicate below, we restate our expectation that unregulated transmission providers will participate in the open and transparent regional planning processes ordered below and note that, if there are complaints about such participation or the lack thereof, we will address them on a case-by-case basis.

\132\ See revised 18 CFR 35.28(e)(1)(ii).

V. Reforms of the OATT

A. Consistency and Transparency of ATC Calculations

193. In the NOPR, the Commission proposed to take action under FPA section 206 to remedy undue discrimination in the provision of transmission service. The Commission recognized that while Order Nos. 888 and 889 require transmission providers to offer and post any available transfer capability (ATC) on their OASIS, and file the methodology they use to calculate ATC as Attachment C to their OATTs, the industry has not developed a consistent methodology for evaluating ATC nor have transmission providers adequately made their ATC calculation methodology transparent. This inconsistency and lack of transparency creates the potential for undue discrimination in the provision of open access transmission service.

194. In the NOPR, the Commission proposed to address this potential for undue discrimination by requiring industry-wide consistency and transparency of all components of the ATC calculation methodology and certain definitions, data, and modeling assumptions. The Commission proposed to provide guidance regarding aspects of ATC calculations that should be more consistent and proposed to direct public utilities, working through NERC \133\ and NAESB, to revise reliability standards and business practices that are relevant to ATC calculations. The Commission also proposed to require increased detail in Attachment C of each transmission provider's OATT and proposed amending the OASIS regulations to require increased transparency. Although commenters challenged aspects of this proposed remedy, no commenters challenged the underlying finding that ATC reform is necessary to remedy undue discrimination in the provision of transmission service.

\133\ All references to NERC in the context of developing reliability standards are to NERC as the Electric Reliability Organization (ERO).

195. The Commission also indicated that the lack of consistent, industry-wide ATC calculation standards poses a threat to the reliable operation of the bulk-power system, particularly because a transmission provider may not know of its neighbors' system conditions affecting its own ATC values. As a result of this reliability impact, the Commission observed that the proposed ATC reforms are also supported by FPA section 215(d)(5), through which the Commission has the authority to direct the ERO to submit a reliability standard that the Commission considers appropriate to implement FPA section 215.

196. In light of these concerns, we direct public utilities, working through NERC reliability standards and NAESB business practices development processes, to produce workable solutions to complex and contentious issues surrounding improving the consistency and transparency of ATC calculations. We are directing our guidance to public utilities and require that they implement our direction by working with NERC to develop reliability standards that accomplish the ATC reforms required in this rulemaking. We will coordinate our directives here with the ATC-related reliability standards that are pending in Docket No. RM06-16-000.\134\ The specifics of our findings with respect to ATC reform are discussed below.

\134\ We note that many of the ATC-related reliability standards filed in Docket No. RM06-16-000 were not addressed by the NOPR in that proceeding, pending the submittal of additional information. See Mandatory Reliability Standards for the Bulk-Power System, 71 FR 64770 (Nov. 3, 2006), FERC Stats. & Regs. ] 32,608 at Appendix A (2006) (Reliability Standards NOPR).

1. Consistency

197. In order to address the potential for remaining undue discrimination in the determination of ATC, the Commission proposed to require industry-wide consistency of certain definitions, data, and modeling assumptions of the ATC calculation. a. Necessary Degree of Consistency NOPR Proposal

198. In the NOPR, the Commission recognized that transmission providers use several basic types of ATC calculation methodologies (with various permutations), and did not propose to require a single ATC calculation methodology to be applied by all transmission providers. However, the Commission proposed to achieve greater consistency in ATC calculations by directing the development of consistent definitions of the ATC components,\135\ as well as consistent data inputs, modeling assumptions, and data

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exchange and coordination protocols. The Commission also required each transmission provider using an Available Flowgate Capacity (AFC) methodology to explain its definition of AFC, its calculation methodology and assumptions, and its process for converting AFC into ATC.

\135\ The ATC components are total transfer capability (TTC), existing transmission commitments (ETC), capacity benefit margin (CBM), and transmission reserve margin (TRM).

Comments

199. While the majority of commenters \136\ support the NOPR's proposal to increase consistency in the calculation of ATC, several caution the Commission to allow flexibility \137\ in order to capture differences in system operations,\138\ usage, market operations,\139\ and topology. Many assert that industry-wide standardization of the ATC calculation might not be possible and suggest that the Commission consider interconnection-wide,\140\ regional,\141\ or even sub-regional standardization. NARUC urges the Commission to facilitate State commission participation in efforts to reform ATC methodologies and calculations on a regional or sub-regional basis. Conversely, several commenters suggest that, if the Commission considers allowing use of different ATC calculations, it must impose a heavy burden on any entity seeking to justify a departure from the interconnection-wide or regional ATC standard.\142\

\136\ E.g., Alcoa, Alliance, Ameren, Arkansas Commission, Arkansas Municipal, AWEA, Duke, E.ON, EEI, ELCON, EPSA, Exelon, LDWP, MidAmerican, NRECA, NPPD, NERC, Occidental, Powerex, PJM, PPL, Progress Energy, Project for Sustainable FERC Energy Policy, Santee Cooper, Southern, Suez Energy NA, SPP, TAPS, TVA, TDU Systems, TranServ, Tacoma, TANC, WECC, WestConnect, and Xcel.

\137\ E.g. Allegheny, Entergy, Indianapolis Power, North Carolina Agencies, and NARUC.

\138\ E.g. Bonneville, Northwest IOUs, and NorthWestern.

\139\ E.g. CAISO.

\140\ E.g. Ameren and Tacoma.

\141\ E.g. APPA, Barrick Reply, Duke, EEI, Imperial, International Transmission, LDWP, NARUC, Nevada Companies, New York Commission, NRECA, MidAmerican, Occidental Reply, Pinnacle, PNM- TNMP, Public Power Council, CREPC, Salt River, Seattle, South Carolina E&G Reply, SPP Reply, Utah Municipals, and WPS Companies Reply.

\142\ E.g. TDU Systems and East Texas Cooperatives Reply.

200. Constellation proposes that the Final Rule establish a rebuttable presumption that the basic ATC calculation formula \143\ set forth in NERC's current ATC definition be identical within a region and that each element of the calculation have the same meaning for all transmission providers. Williams requests on reply that the Commission establish an industry-wide standard for the calculation of ATC and emphasizes that a consistent and transparent approach to evaluating ATC and ATC/AFC modeling assumptions is a prerequisite to the elimination of the broad discretion afforded transmission providers and, with it, the subtle discrimination practiced against customers.

\143\ E.g., ATC = TTC - (ETC + CBM + TRM).

201. Southern suggests that the basic ATC calculation should be defined for both firm and non-firm ATC calculations and also proposes that the following basic formulas be used: ATC (firm) = TTC - Firm Commitments or ETC - TRM - CBM; and ATC (non-firm) = TTC - Firm and Nonfirm Commitments + Postbacks of Redirected and Unscheduled Service - TRM - CBM. In addition, TDU Systems requests that the Commission require standardization of methods for calculating AFC and require NERC to create a formal definition of AFC.

202. PNM-TNMP and Bonneville express concerns with imposing an industry-wide standardized ATC methodology, arguing that there are too many variables in the way systems are operated. In its reply comments, PNM-TNMP adds that NERC's ATC calculation method should take into consideration the need for regional variation, and focus on consistency in definitions and data inputs. WestConnect participants caution that the replacement of the contract path ATC approach used in the Western Electricity Coordinating Council (WECC) with a flowgate methodology could seriously disrupt transmission service in the Western Interconnection.

203. PGP states that, although regional and sub-regional consistency is a good idea, there is no need for the Commission to require ``consistent'' ATC methodologies; rather, the emphasis should be on transparency of the methodologies, inputs, calculations and outputs. Other commenters agree that the Commission should not require overall standardization of ATC calculations, but instead permit regional differences with respect to certain aspects of the calculation of ATC.\144\ EEI argues that standardization of ATC methodologies would require transmission systems to adopt a ``lowest common denominator'' standard in order to ensure that system reliability is not compromised, which would result in a reduction in ATC. EEI suggests that the Commission should direct NERC to develop ATC calculation standards that incorporate regional variations in order to maximize confidence in standards and system use, and maintain reliability. In its reply comments, Exelon disagrees with EEI and states that there are no regional differences within the individual interconnections that would justify differences in the application of ATC calculations.

\144\ E.g., EEI Reply, NARUC Reply, and Powerex Reply.

204. Exelon states that ATC definitions must be consistent so that the various ATC components such as TRM have the identical meaning for all industry participants. In addition, Exelon argues that each ATC component (ETC, TRM, and CBM) must be used in the same manner for all purposes (e.g., granting transmission service to third parties or for the transmission provider's own network load).

205. At the October 12 Technical Conference, NERC recognized that the goal of achieving consistency may not mean that a single ATC methodology is required.\145\ NERC explained that consistency can be achieved with a limited number of methodologies if the requirements of those methodologies are properly coordinated and communicated. NERC stated that the Standard Drafting Team modifying the modeling, data, and analysis (MOD) standards\146\ relevant to ATC is developing a standard applicable to three ATC calculation methodologies: the rated system path methodology (contract path), the network response methodology (network ATC), and the network response flowgate methodology (network AFC). NERC and the other panelists agreed that the two network methodologies are very similar in technique. NERC argued that the ultimate goal of ATC-related reforms should be to standardize definitions. The entire panel agreed that definitions must be consistent and a panelist representing Constellation asserted that broad differences in the core definitions of the ATC calculation are neither rational nor explainable.\147\

\145\ Transcript of October 12 Technical Conference at 125-150.

\146\ MOD standards refers to Modeling, Data, and Analysis Reliability Standards.

\147\ Transcript of October 12 Technical Conference at 149-160.

206. New Mexico Attorney General recommends that the Commission allow a utility to waive the requirement to make certain elements of ATC more consistent if the utility can show that it is making adequate progress towards developing consistent and transparent ATC calculations at the sub-regional level. Commission Determination

207. The Commission adopts the NOPR proposal to require industry- wide

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consistency of all ATC components and certain definitions, data, and modeling assumptions. The Commission also will require each transmission provider to include in Attachment C to its OATT detailed descriptions for calculating both firm and non-firm ATC, consistent with the requirements of this Final Rule. The purpose of increasing the consistency and transparency of ATC calculations is to reduce the potential for undue discrimination in the provision of transmission service, specifically by reducing the opportunity for transmission providers to exercise excessive discretion. We find that the amount of discretion in the existing ATC calculation methodologies gives transmission providers the ability and opportunity to unduly discriminate against third parties. In order to minimize this discretion, the Final Rule requires that all ATC components (i.e., TTC, ETC, CBM, and TRM) and certain data inputs, data exchange, and assumptions be consistent and that the number of industry-wide ATC calculation formulas be few in number, transparent and produce equivalent results. The Commission finds that these reforms will facilitate development of a more coherent and uniform determination of ATC.

208. We reject requests to establish a single methodology for calculating ATC, however, for several reasons. It is not our intent to require transmission providers to incur the expense of developing and adopting a new one-size-fits-all software package to calculate ATC. We also see little benefit in requiring a ``lowest common denominator'' ATC calculator. While a uniform methodology may result in all transmission providers calculating ATC in an identical manner, it would also likely lead to software implementation costs in excess of the resulting benefits. More importantly, we find that the potential for discrimination does not lie primarily in the choice of an ATC calculation methodology, but rather in the consistent application of its components.

209. All ATC calculation methodologies derive ATC by modeling the system to establish TTC, expressed in terms of contract paths or flowgates, and reducing that figure by existing transmission commitments (i.e., ETC), a margin that recognizes uncertainties with transfer capability (i.e., TRM), and a margin that allows for meeting generation reliability criteria (i.e., CBM). These calculation methodologies are developed based on physical characteristics of the transmission provider's transmission system, historical modeling practices, and processes developed for collection of input data related to transmission provider's own system conditions as well as relevant data that model neighboring systems' conditions. We therefore find that it is not the methodologies for calculating ATC themselves that create the opportunity for undue discrimination. Instead, we find that the potential for undue discrimination stems from two main sources:

(1) Variability in the calculation of the components that are used to determine ATC and (2) the lack of a detailed description of the ATC calculation methodology and the underlying assumptions used by the transmission provider.\148\ The combination of a lack of consistency of the components of the ATC calculation coupled with the lack of transparency leaves customers and regulators unable to verify ATC calculations and may allow transmission providers to calculate ATC in different ways for different customers.

210. Accordingly, we conclude that industry-wide consistency of all ATC components (TTC, ETC, CBM, and TRM) and certain data inputs and exchange, modeling assumptions, calculation frequency, and coordination of data relevant for the calculation of ATC will reduce the opportunities for the exercise of discretion that may lead to undue discrimination against unaffiliated transmission customers. The Commission understands that NERC currently is developing standards for three ATC calculation methodologies (contract or rating path ATC, network ATC, and network AFC).\149\ If all of the ATC components and certain data inputs and assumptions are consistent, the three ATC calculation methodologies being finalized by NERC through the reliability standards development process will produce predictable and sufficiently accurate, consistent, equivalent, and replicable results. It is therefore not necessary to require a single industry-wide ATC calculation methodology. The Commission instead concludes that use of the ATC calculation methodologies included in reliability standards currently being developed by NERC is acceptable.

\148\ For example, utilities A and B would agree that ATC is derived by reducing TTC by the sum of ETC, CBM and TRM, but utility A may define ETC to include set-asides for contingencies while utility B may not.

\149\ See Transcript of October 12, 2006 Technical conference at 125. Thee three methodologies are different computational processes to determine a transmission system's ATC. The first, contract path, examines TTC for every A-to-B path on the system in concert with all others, reduces ATC by path for ETC, TRM, and CBM, as appropriate, and produces ATC for each path. The second method, net work ATC, uses a simulator to look not at each path, but each transmission element (line, substation, etc.,), and rule first contingency simulations to establish ATC on a network basis. The third method, network AFC, uses a simulator to examine critical flowgates over a wider area, then requires a second step to convert AFC values to particular path ATC values.

211. As TDU Systems note, there is neither a definition of AFC in NERC's Glossary nor an existing reliability standard that discusses the AFC method. In order to achieve consistency in each component of the ATC calculation (discussed below), we direct public utilities, working through NERC, to develop an AFC definition and requirements used to identify a particular set of transmission facilities as a flowgate. However, we remind transmission providers that our regulations require the posting of ATC values associated with a particular path, not AFC values associated with a flowgate. Transmission providers using an AFC methodology must therefore convert flowgate (AFC) values into path (ATC) values for OASIS posting. In order to have consistent posting of the ATC, TTC, CBM, and TRM values on OASIS, we direct public utilities, working through NERC, to develop in the MOD-001 standard a rule to convert AFC into ATC values to be used by transmission providers that currently use the flowgate methodology.

212. The Commission also believes that further clarification is necessary regarding the calculation algorithms for firm and non-firm ATC.\150\ Currently, NERC has no standards for calculating non-firm ATC. We find that the same potential for discrimination exists for non- firm transmission service as for firm service and that greater uniformity in both firm and non-firm ATC calculations will substantially reduce the remaining potential for undue discrimination. Therefore, we direct public utilities, working through NERC, to modify related ATC standards by implementing the following principles for firm and non-firm ATC calculations: (1) For firm ATC calculations, the transmission provider shall account only for firm commitments; and (2) for non-firm ATC calculations, the

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transmission provider shall account for both firm and non-firm commitments, postbacks of redirected services, unscheduled service, and counterflows. We understand that these principles are currently followed by most transmission providers and believe they should be clearly set forth in the ATC-related reliability standards. As described below, each transmission provider's Attachment C must include a detailed formula for both firm and non-firm ATC, consistent with the modified ATC-related reliability standards.

\150\ The NERC ATC definition does not differentiate firm and non-firm ATC from a high level generic ATC definition: ``A measure of the transfer capability remaining in the physical transmission network for further commercial activity over and above already committed uses. It is defined as Total Transfer Capability less existing transmission commitments (including retail customer service), less a Capacity Benefit Margin, less a Transmission Reliability Margin.'' See North American Electric Reliability Corporation, Glossary of Terms Used in Reliability Standards (February 7, 2006).

213. We deny New Mexico Attorney General's request to grant waiver of the ATC consistency requirements to utilities that can show that they are making adequate progress toward developing consistent and transparent ATC calculations at the sub-regional level. While we certainly encourage regional consistency with respect to the ATC calculation methodology, we are not requiring consistency; therefore a waiver is not necessary. As discussed in more detail below, any request for waiver from these ATC calculation requirements must take place through the NERC reliability standards development process as a request for a regional difference, since the ATC requirements will be determined through the NERC reliability standards. b. Process To Achieve Consistency NOPR Proposal

214. In the NOPR, the Commission expressed confidence that the existing NERC and NAESB processes were well-suited to achieving greater consistency in ATC calculations. The Commission therefore proposed to require public utilities, working through NERC and NAESB, to revise the reliability standards and business practices relating to ATC, consistent with the guidance provided in the Final Rule, within 180 days after the publication of the Final Rule in the Federal Register. Comments

215. Many commenters support the Commission's proposal directing NERC and NAESB to develop reliability standards and business practices addressing ATC.\151\ In addition, several commenters urge the Commission to be more precise in differentiating between policy and business standards, and urge the Commission to provide more guidance to NERC and/or NAESB.\152\ NRECA suggests that the Commission require NERC and NAESB to file the results of their processes with the Commission, give all interested parties an opportunity to comment on the proposals, and exercise its independent authority to review, and if necessary, remand the issues or proposals back to NERC and NAESB.

\151\ E.g., Allegheny, APPA, Arkansas Commission, Bonneville, CAISO, Constellation, E.ON, EEI, ELCON, Entergy, Exelon, FirstEnergy, LPPC, MidAmerican, New York Commission, NERC, Northeast Utilities, Project for Sustainable FERC Energy Policy, PNM-TNMP, Santa Clara, Southern, Tacoma, TransServ, and Utah Municipals.

\152\ E.g., EPSA and Williams.

216. Occidental states on reply that it does not oppose NERC having a role in developing the basic requirements and standards for ATC. However, Occidental also urges the Commission to adopt a process similar to that employed in developing the Standards for Business Practices and Communication Protocols for Public Utilities, which were incorporated by reference into the pro forma OATT.\153\ There, the Commission allowed NAESB's Wholesale Electric Quadrant to develop, with widespread industry input, business practice standards that the Commission then reviewed, adopted and required public utilities to include in their OATTs by reference.\154\ Occidental claims that this process would ensure industry input in the development of the methodology for ATC calculations, as well as Commission review and approval of the methodology.

\153\ Citing Standards for Business Practices and Communication Protocols for Pub. Utils., Order No. 676, 71 FR 26199 (May 4, 2006), FERC Stats. & Regs. ] 31,216 (2006), order on reh'g, Order No. 676- A, 116 FERC ] 61,255 (2006).

\154\ Citing id. at P 20.

217. Several commenters raise concerns that six months may not be sufficient time to develop ATC-related reliability standards and business practices.\155\ Exelon, MidAmerican and NARUC propose that the Commission grant NERC one year from the date of the Final Rule to develop the necessary reliability standards. NARUC agrees with one year, but requests flexibility to assure that the NERC and NAESB processes can be adequately completed. NERC also states that it expects the standards development process, already underway, to be finalized with standards submitted to the Commission prior to the summer of 2007. LPPC recommends that, within six months of the issuance of the Final Rule, NERC be required to submit a progress report addressing the status and a work plan for conclusion within the ensuing six months. NRECA proposes that the Commission closely monitor the NERC and NAESB process. Some commenters strongly oppose a flexible deadline, and urge the Commission to establish a firm deadline that must be met.\156\

\155\ E.g., Constellation, Duke, EEI, Exelon, LPPC, MidAmerican, NARUC, Northwest IOUs, Public Power Council, CREPC, Southern, TDU Systems, and WestConnect.

\156\ E.g., Utah Municipals and Entegra.

218. At the October 12 Technical Conference, NERC informed participants that a great deal of progress has been made since the proposed standards developed by the NERC Standard Committee in February 2006 were generated to address the recommendations made by the Long- Term AFC/ATC Task Force.\157\ However, NERC indicates that a significant amount of work remains before the standard revisions are considered complete. Since NERC would like to finalize its revised standards for submittal to the Commission for the summer of 2007, NERC has established an aggressive schedule of meetings for drafting which will be coordinated with NAESB.

\157\ Citing Long-Term AFC/ATC Task Force Final Report (Revised April 14, 2005), available at http://www.nerc.com/~filez/ltatf.html.

219. PJM outlines several guidelines it suggests the Commission should give to NERC and NAESB regarding the standards development process and recommends that Commission staff participate in the standards development process. Williams and EPSA likewise request that the Commission provide clear guidance to NAESB to assure efficiency and timeliness of the process.

220. Some commenters prefer engagement of a fully independent organization to develop standards and practices related to ATC.\158\ EPSA strongly urges the Commission to require all transmission providers outside of RTO areas to contract with an independent entity to develop and/or monitor ATC calculations. Although TDU Systems agree with EPSA that vertically-integrated transmission providers that are not subject to the independent oversight of an ISO/RTO retain inherent incentives to discriminate against competitors, they contend that the benefit of independent oversight of ATC calculations must be weighed against the cost of that oversight. Alcoa suggests engaging the Institute of Electrical and Electronics Engineers (IEEE) instead of the Commission's proposal to use NERC and NAESB. APPA opposes that position. New York Commission proposes that regional reliability organizations, rather than NERC, complete this task and that the ATC calculators be closely coordinated by

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ISOs and RTOs.\159\ PJM contends on reply that New York Commission's proposal for coordination of ATC between ISOs and RTOs has been fulfilled at least between PJM and its neighbors, arguing that New York Commission's proposal is unnecessary and would add a layer of bureaucracy and cost. TAPS expresses concern with the Commission proposal to use NERC and encourages the Commission to be precise in its direction to NERC to accomplish the needed objective.

\158\ E.g., Alcoa, Fayetteville, and MISO.

\159\ If ISOs and RTOs cannot perform the coordination function, New York Commission suggests the establishment of a Transmission Oversight Center to oversee the calculation of ATC within and between ISOs and RTOs.

Commission Determination

221. The Commission directs public utilities, working through NERC and NAESB, to modify the ATC-related reliability standards and business practices in accordance with specific direction provided in this Final Rule. As we explain above, the development of a more coherent and uniform determination of ATC across a region will help limit the potential for undue discrimination in the calculation of ATC. The Commission concludes that the NERC reliability standards development process and the NAESB business practices development process are the appropriate forums for developing this consistency.

222. NERC has been certified as the ERO and, as such, has been found to have the ability to develop reliability standards through processes with reasonable notice and opportunity for public comment. NERC's processes are open and provide due process as well as a balance of interests, while assuring independence from users and owners and operators of the bulk-power system. Moreover, NAESB has a long history of developing standard business practices for the electric industry, on which the Commission has relied in various contexts. While other entities may bring certain benefits, commenters have not demonstrated the superiority of IEEE, a regional reliability organization, or a particular RTO over NERC and NAESB. Once components of ATC are made consistent and ATC calculation methodologies are made transparent, opportunities for discretion that may lead to undue discrimination in the calculation of ATC will be sufficiently eliminated to invalidate the need for the creation of independent entities to oversee that calculation. To the extent that, even following the adoption of these reforms, customers have complaints regarding the calculations performed by individual transmission owners, they can be addressed on a case-by- case basis.

223. With respect to a timeline for completion, the Commission concurs with NERC that a significant amount of work remains to be done on ATC-related reliability standards development. We also agree with the many commenters who state that the NOPR's proposed six-month timeline is too short for such a complex assignment. Although NERC projects that it may be able to complete the process by the summer of 2007 (which is approximately six months from the date of the Final Rule), we believe NERC should have additional flexibility with respect to its timeline. Accordingly, we direct public utilities, working through NERC, to modify the ATC-related reliability standards within 270 days after the publication of the Final Rule in the Federal Register. We also direct public utilities to work through NAESB to develop business practices that complement NERC's new reliability standards within 360 days after the publication of the Final Rule in the Federal Register. Finally, we direct NERC and NAESB to file, within 90 days of publication of the Final Rule in the Federal Register, a joint status report on standards and business practices development and a work plan for completion of this task within the timeframe established above.\160\

\160\ NAESB's work plan for developing business practices related to other reforms adopted in this Final Rule should be filed separately, as requested in Section IV.C.1.

c. Applicability to ISOs, RTOs, and Non-Public Utility Transmission Providers NOPR Proposal

224. The Commission did not specifically address the application of the ATC-related reforms proposed in the NOPR to ISOs and RTOs or non- public utility transmission providers. Comments

225. ISOs and RTOs believe that the Commission should not require wholesale revisions of RTO and ISO tariffs, even on such issues as ATC standards.\161\ They caution that many regional grid operators' tariffs contain nonconforming provisions that were the product of extensive debate, litigation and settlements. In addition, some commenters point out that concern about ATC calculations is a non-issue in many ISO/RTO regions because transmission services in those regions are not based on physical transmission reservations.\162\

\161\ E.g., PJM and MISO Transmission Owners, SPP Reply.

\162\ E.g., ISO/RTO Council, ISO New England, and Pennsylvania Commission.

226. MISO argues that AFC calculation methodologies should be established via the RTO stakeholder process, not NERC. In its reply comments, Exelon expresses disagreement with MISO and states that there must be one standard for ATC calculations, not several methods based on the desires of different sets of stakeholders. Several commenters also believe that ISOs/RTOs should not be exempt from the requirements for consistent and transparent ATC calculations.\163\

\163\ E.g., NRECA and TDU Systems.

227. EEI asks the Commission to require all municipal and other non-public utility transmission providers to adhere to any requirement for consistent and transparent ATC/AFC calculation. In its view, applying the ATC-related reforms to these nonjurisdictional entities would recognize the interconnected nature of the transmission grid. EEI argues that greater transparency and consistency in the provision of transmission service would be frustrated if all transmission providers do not have to comply. Other commenters reply that EEI's concerns are unfounded and describe an example in the WECC region, where the methodologies and practices regarding ATC calculations are developed by representatives from all affected transmission providers, utilities, and market participants, including nonjurisdictional entities.\164\

\164\ E.g., Lassen and Public Power Council.

228. LPPC contends that the NERC reliability standards related to ATC calculation will already be applicable to both public and non- public utilities. LPPC argues that NERC standards, when final, will be filed with the Commission, become part of the ERO's mandatory reliability standards and will be fully applicable to otherwise nonjurisdictional entities. As a result, the ATC standards will be applicable to and enforceable upon all transmission owners, whether or not the transmission owner has an OATT. Commission Determination

229. We discuss the applicability of the Final Rule to ISOs and RTOs in section IV.C.2 above. With respect to the application of the ATC requirements of this Final Rule to municipal and other non-public utility transmission providers, we likewise note that the applicability of the rule generally to such entities is addressed in section

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IV.C.3. We note here, however, that such entities will be required to comply with reliability standards developed under FPA section 215. As LPPC acknowledges, once these reliability standards are approved they will become part of the ERO's mandatory reliability standards and, thus, will be applicable to and enforceable upon all transmission owners, whether or not the transmission owner has adopted the OATT. d. Alternatives to ATC Consistency Comments

230. Some commenters contend that the NOPR is focused too narrowly on simply improving the consistency and transparency of ATC determinations and suggest that a focus on balancing (or dispatch) services and how those are priced would allow the Commission to avoid the pitfalls inherent in the ATC approach.\165\ In their view, such an approach would eliminate much of the difference between how third parties are treated in RTO versus non-RTO systems. Constellation encourages the Commission to consider requiring transmission providers to implement all-inclusive, security constrained economic dispatch processes. In reply comments, Chandley-Hogan argue that the Commission's ATC-related proposals in the NOPR confuse how transmission service is actually provided in most of the United States and, as a result, the Commission's analysis of perceived problems in the calculation of ATC is flawed, inconsistent with network realities and the laws of physics, and incompatible with reliable operations.

\165\ E.g., Chandley-Hogan, EPSA, PJM, San Diego G&E, and Transparent Dispatch Advocates Reply.

231. Contrary to the above claims, some commenters find that ATC provides a functionally useful measure of available capacity and has certain advantages over alternative models.\166\ These commenters argue that the factual record does not support conclusions that bid-based, marginal cost dispatch by a third party is inherently more efficient or inherently more likely to remedy undue-discrimination than the OATT model, and cannot overcome the considerable real world obstacles to pure economic redispatch, including overlapping and dynamic constraints, and the physical realities in the Western Interconnection that often limit the pool of resources that can be redispatched to solve constraints. LPPC contends that the principal advantage of ATC is the certainty that it provides for available capacity, suggesting that the contract path paradigm facilitates long-term bilateral contracting.

\166\ E.g., APPA, CMUA, CPA, Duke, EEI, Entergy, LPPC, Public Power Council, Sacramento, and WestConnect Reply.

Commission Determination

232. In this rulemaking, the Commission is requiring consistency in the determination of ATC with the purpose of improving a customer's ability to receive transmission service on a non-discriminatory basis. These reforms are fully consistent with operational reality, and we decline to mandate the security constrained economic dispatch alternative proposed by Chandley-Hogan. Chandley-Hogan argue that it would be unduly discriminatory to exclude third-party generators from an efficient dispatch to serve native load and therefore a centralized, bid-based market is required. We agree that a centralized bid-based market can benefit customers and, over a large region, can manage congestion efficiently. We do not believe, however, that mandating that result--essentially requiring that Day 2 RTOs be adopted in every region of the country--is necessary to remedy undue discrimination in the provision of transmission service. The concern raised by Chandley- Hogan is not related solely to the nondiscriminatory use of the transmission system. It also implicates the purchase decisions of transmission providers on behalf of their native load customers. These decisions are regulated primarily by the states and we decline to take generic action in this rulemaking to reform the processes by which those purchases are made. e. ATC Components

233. The next several sections address components of ATC that must be made consistent to remove the potential for undue discrimination, namely TTC/TFC, ETC, CBM, and TRM. (1) Total Transfer Capability (TTC)/Total Flowgate Capability (TFC) NOPR Proposal

234. The Commission proposed to direct public utilities, working through NERC, to develop consistent practices for calculating total transfer/flowgate capability (TTC/TFC). Although the NERC reliability regions have historically calculated transfer capability using different approaches, the Commission expressed its view that guidelines for a common approach to calculating transfer capability are achievable. The Commission also stated that the criteria used for identifying flowgates and determining TFC could be more consistent. Comments

235. Entergy supports the development of consistent practices for determining transfer capability while maintaining flexibility to recognize regional and system-specific differences. APPA agrees that the calculation of TTC/TFC is, for the most part, a regional calculation. APPA states that the Western Interconnection and ERCOT use their own methods, which are generally applied system-wide. APPA believes that more standardization and coordination of TTC/TFC among transmission providers in the Eastern Interconnection, where two primary methods are used to calculate TTC or TFC, would be desirable because of reported loop-flow problems in the Eastern Interconnection.

236. In order to increase transfer capability from existing facilities, AWEA proposes that the Commission direct NERC, as part of developing consistent ATC standards, to investigate the impact of implementing dynamic line ratings in TTC/TFC calculations and propose protocols to effectuate such a program. In response to AWEA's proposal, commenters state that if the Commission decides to provide guidance to NERC with regard to dynamic line ratings, the Commission should encourage NERC to develop standards with regard to dynamic line ratings in the operating horizon, but not in the planning horizon.\167\

\167\ E.g., MAPP and MidAmerican.

Commission Determination

237. The Commission adopts the NOPR proposal and directs public utilities, working through NERC, to develop consistent practices for calculating TTC/TFC. We direct public utilities, working through NERC, to address, through the reliability standards process, any differences in developing TTC/TFC for transmission provided under the pro forma OATT and for transfer capability for native load and reliability assessment studies.

238. We acknowledge that reliability regions have historically calculated transfer capability using different approaches, and we agree that regional differences should be respected.\168\ However, as already discussed above regarding ATC, the TTC requirements will be determined by the NERC reliability standards and any request for a regional difference from the reliability standards must take place through the NERC process.

\168\ For example, WECC has a documented open process for establishing TTC for the Western Interconnection.

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239. With respect to AWEA's proposal regarding implementing dynamic line ratings in TTC/TFC calculations, the Commission finds that this proposal is outside the scope of this rulemaking as it does not appear to relate to undue discrimination in transmission service and, in any event, would best be addressed in the first instance through the NERC reliability standards development process, addressing reliability standards that regulate facility ratings. If AWEA desires to pursue this proposal, it should propose an appropriate dynamic line rating standard within the ERO's reliability standards development process. (2) Existing Transmission Commitments (ETC) NOPR Proposal

240. In the NOPR, the Commission expressed its view that the lack of consistency in modeling of existing transmission commitments (ETC) resulted in excessive discretion in determining how much capacity a transmission provider sets aside for native load, including its network customers. The Commission therefore proposed the development of a consistent methodology for determining the capacity needed and set aside for native load usage. The Commission also proposed that accounting for transmission reservations in an ATC/AFC calculation be more consistent. The Commission further proposed that public utilities, working through NERC, establish and specifically identify the reservations to be used in determining ETC. Comments

241. Entegra and PGP support increasing consistency in determining ETC. APPA agrees that it would be helpful to standardize the method of accounting for ETC on an interconnection-wide basis. APPA states, however, that flexibility might be required among the interconnections. TDU Systems requests that the Commission define with specificity the types of transmission service requests or scheduled transmission transactions that should be included in ETC and agrees with the Commission that inclusion of all requests for transmission service in ETC is likely to overstate usage of the system, thus understating ATC. It suggests that the Commission develop a bright line method for calculating ETC. NERC notes that its proposed reliability standards would define ETC and require appropriate documentation. NERC adds, however, that the components included in ETC appear to be candidates for business practices rather than reliability standards.

242. Williams proposes that ETC be the subject of an expanded definition and that native load growth projections be based on verifiable data provided by an independent source. It also states that transmission providers should be required to update ATC based on each confirmed transmission service reservation (point-to-point or network, firm or non-firm). Commission Determination

243. To achieve greater consistency in ETC calculations and further reduce the potential for undue discrimination, the Commission adopts the NOPR proposal and directs public utilities, working through NERC and NAESB, to develop a consistent approach for determining the amount of transfer capability a transmission provider may set aside for its native load and other committed uses. We expect that NERC will address ETC through the MOD-001 reliability standard rather than through a separate reliability standard.\169\ By using MOD-001, the ETC calculation can be adjusted to be applicable to each of the three ATC methodologies under development by NERC.

\169\ The purpose of MOD-001 is to promote the consistent and uniform application of transfer capability calculations among the transmission system users.

244. In order to provide specific direction to public utilities and NERC, we determine that ETC should be defined to include committed uses of the transmission system, including (1) Native load commitments (including network service), (2) grandfathered transmission rights, (3) appropriate point-to-point reservations,\170\ (4) rollover rights associated with long-term firm service, and (5) other uses identified through the NERC process. ETC should not be used to set aside transfer capability for any type of planning or contingency reserve, which are to be addressed through CBM and TRM.\171\ In addition, in the short- term ATC calculation, all reserved but unused transfer capability (non- scheduled) shall be released as non-firm ATC.

\170\ By ``appropriate,'' we mean that reservations accounted for under ETC depend on the firmness and duration of the reservation. The specific characteristics should be developed in the reliability standard.

\171\ TRM also includes such things as loop flow and parallel path flow.

245. We agree with TDU Systems that inclusion of all requests for transmission service in ETC would likely overstate usage of the system and understate ATC. We therefore find that reservations that have the same point of receipt (POR) (generator) but different point of delivery (POD) (load), for the same time frame, should not be modeled in the ETC calculation simultaneously if their combined reserved transmission capacity exceeds the generator's nameplate capacity at POR. This will prevent overly unrealistic utilization of transmission capacity associated with power output from a generator identified as a POR. We direct public utilities, working through NERC, to develop requirements in MOD-001 that lay out clear instructions on how these reservations should be accounted. One approach that could be used is examining historical patterns of actual reservation use during a particular season, month, or time of day.

246. We agree with NERC that some elements of ETC are candidates for business practices rather than reliability standards. Accordingly, we direct public utilities, working through NAESB, to develop business practices necessary for full implementation of the developed MOD-001 reliability standard.

247. We decline to adopt Williams's proposal to require that native load growth be based on the verifiable data provided by an independent source. Through increased consistency and transparency of ATC determinations, including requirements for posting additional data, third parties will be able to verify the accuracy of ETC, helping to eliminate opportunities for undue discrimination. (3) Capacity Benefit Margin (CBM) NOPR Proposal

248. In the NOPR, the Commission proposed three options to address the CBM component of ATC: (1) Have NERC develop clear standards for how the CBM value should be determined, allocated across transmission paths, and used; (2) charge an entity for which transfer capability has been set aside to meet generation reliability criteria a separate rate for this service; or (3) eliminate CBM and require an entity reserving ATC to meet generation reserve (currently through CBM) to designate network resources on the other side of the interface and make an associated transmission service reservation. Comments

249. Numerous commenters support the Commission's proposed option one, requiring NERC to develop clear standards for how the CBM value should be determined, allocated across

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transmission paths, and used.\172\ They believe that CBM ensures the ability to import needed power to support system conditions. TVA argues that option two would be costly and may cause some systems to forego CBM, thereby jeopardizing service to native load customers. PJM states that option two is irrelevant in PJM since PJM ``totals'' reservations and decides when CBM can be used. Supporters of option one criticize option three, elimination of CBM, as costly and a threat to transmission system reliability. Southern, Progress Energy, and PJM emphasize that, without CBM, the LSEs would need to increase their reserve margin by contracting for additional generation capacity, costing millions of dollars. In addition, Ameren and TVA believe that CBM elimination will increase the likelihood of widespread blackouts in emergency conditions.

\172\ E.g., Allegheny, Ameren, EEI, Duke, NRECA, TVA, APPA, Bonneville, EPSA, FirstEnergy, Indianapolis Power, MidAmerican, Pinnacle, PJM, PGP, PNM-TNMP, Public Power Council, Sacramento, Seattle, South Carolina E&G, TANC, TDU Systems, and Wisconsin Electric.

250. At the October 12 Technical Conference, Exelon supported option two proposing a charge for CBM. Exelon contended that, in a rate-making context, there would be an increase in the divisor of the rate by the amount of CBM set-aside which would lower the point-to- point charge. Consequently, those not benefiting from the CBM set-aside effectively would be paying a lower charge.

251. Constellation and Morgan Stanley support the elimination of CBM and argue that CBM and TRM are often used interchangeably and result in duplicative transmission set-asides. They also argue that there is no compelling need for CBM in the current liquid market environment. In addition, Morgan Stanley states that LSEs affiliated with the transmission provider should not be allowed to use CBM for long-term planning purposes as an excuse to avoid undertaking needed resource additions or to conceal the true cost of their load serving functions. Furthermore, the Commission should not be distracted by assertions that such long-term arrangements are necessary for ``reliability,'' when in fact they are simply a way to protect the economic interests of a particular entity.

252. Duke replies that Constellation mistakenly believes that CBM is currently only available to a transmission provider's native load when, in fact, for those transmission providers that establish CBM, it should be established for the load of all LSEs in the control area. Duke contends that not all transmission providers set aside capacity through CBM for their native load; to the extent that a transmission provider does not set aside CBM, there should be no obligation to allow other LSEs to do so. Duke proposes that the Commission should continue to permit such flexibility.

253. NERC takes no position on CBM, expecting that the issue can be settled through the NERC and NAESB Procedure for Joint Standards Development and Coordination and through other open forums.

254. TAPS suggests that the Commission ensure that all LSEs have both access to CBM to meet their reserve-sharing needs and meaningful input into how much CBM is reserved. To do so, TAPS recommends the creation of a reserve-sharing group made up of the transmission provider and LSEs it serves. It argues that this would remove reservation decisions from the sole discretion of the vertically- integrated transmission provider and instead have them made by the transmission provider/LSE reserve-sharing group, subject to dispute resolution at the Commission. All LSEs would be invited to participate in the studies as well as review the results and assumptions. Moreover, once a regional planning process is established, as proposed in the NOPR, TAPS recommends that the regional planning group be required to approve the CBM reservation as well.

255. Williams suggests that a transmission provider must designate network resources and reserve firm transfer capability on both sides of the control area transmission interface in order to reserve CBM. Duke replies that, although some commenters prefer eliminating CBM and replacing it with additional designated network resources, CBM is the preferable option because it is less costly. Duke further argues that the choice is between setting aside both additional transmission and generation capacity to deal with emergencies (the additional designated network resource approach) versus setting aside only transmission (the CBM approach). Having to procure additional designated network resources to keep in reserve reduces one of the main benefits of interconnected operations. Duke argues that eliminating CBM would drive up costs for network customers, as they would have to procure additional generation and transmission resources. EEI adds that such a proposal may result in increased LSE reserve requirements, over- building of generation supply, and a reduction, rather than an increase, in ATC. Commission Determination

256. The Commission concludes that it is appropriate to allow LSEs to retain the option of setting aside transfer capability in the form of CBM to maintain their generation reliability requirement. We agree with commenters that, without CBM, LSEs would have to increase their generation reserve margins by contracting for generation capacity, which may result in higher costs without additional reliability benefits. We require, however, the development of standards for how CBM is determined, allocated across transmission paths, and used in order to limit misuse of transfer capability set aside as CBM. Transmission providers also must reflect the set-aside of transfer capability as CBM in the development of the rate for point-to-point transmission service to ensure comparable treatment for point-to-point to customers.

257. The Commission therefore adopts a combination of the NOPR options one and two, and declines to adopt option three. First, we require public utilities, working through NERC and NAESB, to develop clear standards for how the CBM value shall be determined, allocated across transmission paths, and used. We understand that NERC has already begun the process of modifying several of the CBM-related reliability standards and that the drafting process is a joint project with NAESB. Second, we require transmission providers to reflect the set-aside of transfer capability as CBM in the development of the rate for point-to-point transmission service.

258. We note that there is broad concern that eliminating CBM (option three) would impose extraordinary costs for meeting generation reliability criteria, which then may lead utilities to reduce their generation reliability requirement to avoid the cost increase. We believe that the reforms reflected in combining options one and two are sufficient to remedy undue discrimination and that the adverse effects associated with option three are neither warranted nor required. We reject Morgan Stanley's call for CBM elimination on the grounds that CBM is acting as a disincentive to undertake needed generation resource additions. It would be inappropriate for the Commission to restrict the ability of an LSE to determine how best to meet its generation reliability criteria.

259. To ensure CBM is used for its intended purpose, CBM shall only be used to allow an LSE to meet its generation reliability criteria. Consistent with Duke's statement, we clarify that

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each LSE within a transmission provider's control area has the right to request the transmission provider to set aside transfer capability as CBM for the LSE to meet its historical, State, RTO, or regional generation reliability criteria requirement such as reserve margin, loss of load probability (LOLP), the loss of largest units, etc.

260. We direct public utilities, working through NERC, to develop clear requirements for allocating CBM over transmission paths and flowgates. While we do not mandate a particular methodology for allocating CBM to paths and flowgates, one approach could be based on the location of the outside resources or spot market hubs that an LSE has historically relied on during emergencies resulting from an energy deficiency.

261. We concur with TAPS' proposal that all LSEs should have access to CBM and meaningful input into how much transfer capability is set aside as CBM. In the transparency section below, we provide detailed requirements regarding availability of documentation used to determine the amount of transfer capability to be set aside as CBM and the posting of CBM values and narratives. Access to this documentation will enable LSEs to validate how much transfer capability is set aside as CBM on each system and provide them with information to question whether the set-aside is consistent with the reliability standards and this Final Rule.

262. Concerning TAPS' proposal to remove the reservation decision from the sole discretion of transmission providers, we determine that LSEs should be permitted to call for use of CBM, if they do so pursuant to conditions established in the reliability standards development process. We direct public utilities working through NERC to modify the CBM-related standards to specify the generation deficiency conditions during which an LSE will be allowed to use the transfer capability reserved as CBM. In addition, we direct that transmission set aside as CBM shall be zero in non-firm ATC calculations. Finally, we order public utilities to work with NAESB to develop an OASIS mechanism that will allow for auditing of CBM usage.

263. We also require transmission providers to design their transmission charges to ensure that the class of customers not benefiting from the CBM set-aside, i.e., point-to-point customers, do not pay a transmission charge that includes the cost of the CBM set- aside. To do this, transmission providers are required to submit redesigned transmission charges that reflect the CBM set-aside through a limited issue FPA section 205 rate filing as part of its initial ATC- related compliance filing. These filings, which may be submitted within 120 days after the publication of the Final Rule in the Federal Register, may be limited to the rate design change only, i.e., they will not require the submission of cost of service data or a revision to the transmission provider's revenue requirement.

264. With respect to TAPS' proposal that all LSEs should be allowed to use CBM to meet their reserve-sharing needs, we believe that TRM is the appropriate category for that purpose, not CBM. We reject TAPS' proposal to use CBM for the LSE's reserve-sharing needs, but instead make TRM available for the incremental power flows resulting from reserve sharing, as explained next.

265. As we are rejecting option three, which would have required the reservation of transfer capability rather than using CBM, we also reject Williams' proposal to require the reservation of transfer capability on both sides of an interface for CBM. (4) Transmission Reserve Margin (TRM) NOPR Proposal

266. Finally, the Commission proposed the development of reliability standards MOD-008 and MOD-009 \173\that specify the uncertainties that TRM could be used to accommodate, which could include (1) Load forecast and load distribution error, (2) variations in facility loadings, (3) uncertainty in transmission system topology, (4) loop flow impact, (5) variations in generation dispatch, including intermittent resources, (6) automatic sharing of reserves, and (7) other uncertainties identified through the NERC reliability standards development process.

\173\ The MOD-008 and MOD-009 reliability standards document regional TRM methodologies and procedures for verifying TRM values.

Comments

267. Most commenters agree that the existing definitions for TRM require clarification.\174\ Commenters also agree that NERC should be required to develop clear standards for the determination of TRM, including specifying the criteria used in the determination of TRM.\175\ PNM-TNMP supports the Commission's proposal, pointing out that the implementation of the current NERC standards definition for TRM and CBM could result in its double-counting, which must be eliminated. APPA members in the Western Interconnection suggest that regional variations be permitted. They also note that the modeling methods used by WECC and its sub-regions may differ from those used in the Eastern Interconnection. For example, they contend that uncertainties associated with transmission maintenance schedules that are driven by hydro-production curves will seasonally affect TRM set- asides on certain transfer paths. PJM believes that the TRM methodology should be consistent at the regional reliability organization level. PJM also contends that TRM should be coordinated, exchanged and respected on external flowgates and that the concept of a maximum TRM, by percentage, should be adopted in the NERC standards.

\174\ E.g., Allegheny, APPA, EEI, EPSA, Exelon, LPPC, MidAmerican, NRECA, Northwest IOUs, NorthWestern, Occidental, Pinnacle, Powerex, PNM-TNMP, PPL, PJM, PPM, and WestConnect.

\175\ Exelon recommends that the following factors should be the same for the planning process and ATC/AFC process to achieve consistency: base case flows, reservation impacts, TRM and CBM forecasted to occur simultaneously; counterflows; positive impacts resulting from reservations and generation dispatch; TRM for the same scenarios; and CBM.

268. Consistent with its position on CBM, TAPS proposes that TRM set-asides should be conditioned on inclusive reserve-sharing arrangements, with the reservations determined by the reserve-sharing group, subject to dispute resolution before the Commission (and, eventually, approval by joint planning groups).

269. PNM-TNMP suggests that the Commission consider definitions to include the following clarification taken from WECC procedures on ATC: ``If the limitation on the use of TRM to 59 minutes would force a Transmission Provider to set aside unnecessary CBM on the same path as the TRM, that Transmission Provider may utilize the TRM beyond the 59 minutes.'' \176\ PNM-TNMP states that this would allow the transmission provider to maximize the ATC by not needlessly setting aside twice the amount of transmission (TRM and CBM) than is necessary for reliability.

\176\ Citing WECC Rocky Mountain Operating and Planning Group, Determination of Available Transfer Capability within the Western Interconnection, June 2001, page 9, http://www.wecc.biz/modules.php?op=modload&name=Downloads&file=index&req=getit&lid=1035 .

270. Nevada Companies argue that no new standards are required for TRM and that any further action would be burdensome. They explain that NERC has a well-established definition that does not require further clarification. In their view, all that is required is a complete statement, to be posted on OASIS, regarding the transmission provider's application of TRM. NERC

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comments that the existing reliability standards for TRM will be revised to require clear documentation of the calculation of TRM. It also adds that the revised standard will make various TRM components mandatory to achieve more consistency across methodologies.

271. Santee Cooper urges the Commission to ensure that service to native load and transmission system reliability will not be compromised as the Commission seeks greater levels of consistency in the calculation of ATC. It states that the Commission also must be cognizant of the importance of TRM in the provision of service to native load. Commission Determination

272. The Commission adopts the NOPR proposal and requires public utilities, working through NERC, to complete the ongoing process of modifying TRM standards MOD-008 and MOD-009. We understand that the standard drafting process is underway as a joint project with NAESB.

273. The Commission also adopts the NOPR proposal to establish standards specifying the appropriate uses of TRM to guide NERC and NAESB in the drafting process. Transmission providers may set aside TRM for (1) Load forecast and load distribution error, (2) variations in facility loadings, (3) uncertainty in transmission system topology, (4) loop flow impact, (5) variations in generation dispatch, (6) automatic sharing of reserves, and (7) other uncertainties as identified through the NERC reliability standards development process. Because load, facility loading and other uncertainties constantly deviate, we will not require that TRM set aside capacity be set at zero in the non-firm ATC calculation. In other words, we will not require transfer capability that is set aside as TRM to be sold on a non-firm basis. We find that clear specification in this Final Rule of the permitted purposes for which entities may reserve CBM and TRM will virtually eliminate double-counting of TRM and CBM.

274. We will not adopt PNM-TNMP's proposal regarding use of set aside transfer capability as TRM beyond 59 minutes, rather than converting it to CBM. Our proposal is to separate transfer capability set asides as either CBM or TRM without regard to duration of use of the set aside. Therefore, such a clarification is not necessary.

275. In addition, we direct public utilities, working through NERC, to establish an appropriate maximum TRM. One acceptable method may be to use a percentage of ratings reduction, i.e., model the system assuming all facility ratings are reduced by a specific percentage. This is a relatively simple method and, if adopted as the reliability standard's method, should not restrict a transmission provider from using a more sophisticated method that may allow for greater ATC without reducing overall reliability.

276. Because of the operational characteristics of the uncertainties that are to be accommodated using TRM, and their aggregate impact on reliable operation, we require each transmission provider to calculate, and allocate on the paths and flowgates, the aggregate TRM value for all LSEs within its area. We support NERC's plan to revise existing reliability standards for TRM to require clear documentation of the TRM calculation, as we expect the TRM value to be supported and fully transparent. In addition, we require each transmission provider to make available all underlying documentation, including work papers and load flow base cases, used to determine TRM, to any transmission customer and LSE within its control area, subject to a confidentiality agreement,\177\ if necessary. We agree with Santee Cooper's comments that the Commission must ensure that service to native load and system reliability are not compromised. We believe that our requirement for public utilities to work through NERC satisfies such concerns.

\177\ The agreement may appropriately restrict the sharing of sensitive information with customer personnel that are involved only in transmission functions, as opposed to merchant functions.

277. With respect to the proposal to permit regional variations in the TRM calculation methodology, we reiterate our position stated above that any request for regional difference from the applicable reliability standards must take place through the NERC reliability standards development process. With respect to TAPS' proposal regarding reserve sharing groups, we clarify that, to the extent transfer capability is needed for transmission of shared reserves, this is included under TRM. However, as noted previously in the CBM discussion, we are not mandating the use of reserve sharing groups. f. Modeling, Assumptions and Input Data NOPR Proposal

278. The Commission's proposal with regard to modeling, assumptions and data inputs was based on a principle that there should be consistency among transmission providers and between what the transmission provider does for its operation and expansion planning for native load and what it does in determining short and long-term ATC for all uses. The Commission stated its view that consistency is necessary to ensure non-discriminatory treatment by eliminating a transmission provider's ability to use discretion to the disadvantage of competitors. The Commission proposed three specific areas for reform.

279. First, the Commission proposed to require public utilities, working through NERC, to modify the ATC-related standards to incorporate a requirement for periodic validation and modification of models to ensure that they are up to date.\178\ The Commission stated that the models should be updated and benchmarked to actual events.

\178\ The Commission noted that this would include review of load flow base cases, short circuit data, transient and dynamic stability simulation data, contingency (files should contain information on special protection schemes and remedial action plans) subsystem and monitoring files, and production cost models.

280. Second, the Commission proposed that, to the maximum extent practicable, the same data must be used by the transmission provider to determine short- and long-term ATC as those used in system operation and planning studies, respectively.

281. Third, the Commission proposed that public utilities, working through NERC, develop assumptions for use in ATC determinations and that the assumptions remain consistent among transmission providers to the maximum extent practicable. The Commission indicated that short- and long-term ATC calculations should be developed using consistent assumptions regarding representative load levels, generation dispatch, transmission reservations and counterflows, in addition to any other modeling assumptions identified by NERC. The Commission further proposed that there should be a consistent approach to the modeling of load levels, a method established for determining which generators should be modeled in service (including guidance on how independent generators should be considered), consistency in the simulation of power flows from points of receipt to delivery when sources are unknown, and consistency in the manner in which ATC/AFC reservations are accounted for. The Commission stated that the model for long-term ATC should include, to the maximum extent practicable, the same assumptions regarding new transmission and generation facilities additions and retirements as those used in planning for expansion.

282. The Commission noted that the proposal is not intended to change the manner in which native load is served

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and sought comment on whether (and, if so, how) this proposal would affect service to native load customers. Comments

283. Commenters generally discuss consistency of data, assumptions and modeling together so we in turn do the same. Many commenters support the proposals for consistency in data, assumptions and/or modeling.\179\ Others support flexibility or regional variation.\180\ A few commenters oppose specific aspects of the overall proposal.\181\

\179\ E.g., APPA, Arkansas Commission, Constellation, Entegra, Exelon, EPSA, ISO/RTO Council, LDWP, MidAmerican, Municipals, NRECA, CREPC, Sacramento, Santee Cooper, Suez Energy NA, TAPS, TDU Systems, WestConnect, and Williams.

\180\ E.g., Bonneville. Santee Cooper, and Entergy.

\181\ E.g., PJM, EPSA, and Ameren.

284. TDU Systems and Sacramento express support for the Commission's proposal to require public utilities, working through NERC, to develop modeling assumptions for use in calculating ATC that are consistent with those used to plan the operation and expansion of the transmission system. Xcel, however, would have the Commission go further. Xcel recommends that the Commission enhance its proposal by establishing a date certain for transmission providers in the Western Interconnection to be required to account for impacts of loop flows when processing transmission service requests and calculating ATC. Xcel suggests that NERC be directed to develop standards for evaluation of counterflows on ATC. EPSA offers examples of specific data inputs that, in its view, should also be standardized among all transmission providers, which include: Load levels and distribution studies; transmission outages; generation outages; and generation dispatch. Ameren submits that any modeling of base generation dispatch must model generators, including merchant generators, as they are expected to run.

285. Williams asks the Commission to require consistency between transmission planning horizon and procurement terms, and transparency around the long-term transmission planning assumptions. Williams states that third-party bids to a request for proposals are evaluated with transmission costs that may already be included in long-term transmission plans. Thus, argues Williams, procurement and long-term planning assumptions are intertwined. In reply, Entergy acknowledges and agrees that the models used for planning, operations and service request evaluations should generally be based on similar data and procedures, but argues that due to changes in system configuration, facilities included in transmission plans are often not needed at all and thus are not constructed. Therefore, Entergy proposes that the Commission allow NERC to determine the circumstances under which differences between models would be appropriate.

286. Southern asks for clarification on what the Commission intends by proposing that modeling assumptions be consistent in the context of TTC assessments. Southern explains that, as the Commission has recognized, the inevitable changes in system conditions between different time horizons (e.g., real-time and planning and operations) would render this approach unreliable because load levels, dispatch arrangements, reservations, and outages cannot be the same over significantly different time horizons.

287. Supporting regional differences, Bonneville contends that calculating ATC for a hydroelectric system requires different inputs and modeling assumptions than are appropriate for thermal-based systems. Bonneville explains that non-power constraints placed on hydroelectric projects that were built for multiple uses are a major concern on the Bonneville system. Consequently, hydro operators are more limited in their ability to use generation redispatch as a tool to meet long-term firm load obligations. Similarly, Santee Cooper cautions that over-standardization may result in certain parameters being misstated or inappropriately constrained, resulting in inaccurate reservations of capacity for native load purposes and a potentially detrimental effect on the reliability of service. It recommends that the Commission direct NERC to allow deviations from the standard modeling assumptions where the need can be supported, with the caveat that a utility's modeling assumptions must be transparent and available for scrutiny. Seattle contends that modeling assumptions should be developed at the sub-regional level, consistent among adjacent transmission providers. TVA suggests that the transmission providers be allowed to retain flexibility to conduct risk analyses and reflect those in their modeling assumptions.

288. Other commenters argue that modeling assumption standardization should not be performed by NERC and, instead, should be delegated to the regional reliability organizations or RTOs, as they possess a superior knowledge of the physical grid within their boundaries.\182\ PJM states that such issues are best left to the joint stakeholder processes and the resulting joint and common market initiatives.

\182\ E.g., Sacramento, Manitoba Hydro, Nevada Companies, and TANC.

289. In response to the Commission's inquiry as to how standardizing the modeling assumptions and data would affect native load, commenters generally state that standardization of ATC modeling assumptions would increase comparability of service to LSEs and enhance the ATC methodology and its nondiscriminatory application to grid utilization.\183\

\183\ E.g., Sacramento.

Commission Determination

290. The Commission directs public utilities, working through NERC, to modify the reliability standards MOD-010 through MOD-025 \184\ to incorporate a requirement for the periodic review and modification of models for (1) Load flow base cases with contingency, subsystem, and monitoring files, (2) short circuit data, and (3) transient and dynamic stability simulation data, in order to ensure that they are up to date. This means that the models should be updated and benchmarked to actual events. We find that this requirement is essential in order to have an accurate simulation of the performance of the grid and from which to comparably calculate ATC, therefore increasing transparency and decreasing the potential for undue discrimination by transmission providers.

\184\ The MOD-010 through MOD-025 reliability standards establish data requirements, reporting procedures, and system model development and validation for use in the reliability analysis of the interconnected transmission systems.

291. We note that commenters generally were very supportive of the Commission's proposals for review and update of models and for consistency of assumptions and data inputs. We received no adverse comments concerning our general proposal to require public utilities, working through NERC, to modify the ATC-related standards to incorporate a requirement for the periodic review and modification of models to ensure that they are up to date. Moreover, the need to improve the quality of system modeling was one of the U.S.-Canada Power System Task Force recommendations.\185\

\185\ Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations.

292. The Commission also adopts the NOPR proposal to require transmission providers to use data and modeling assumptions for the short- and long-term ATC calculations that are consistent with that used for the

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planning of operations and system expansion, respectively, to the maximum extent practicable. This includes, for example: (1) Load levels, (2) generation dispatch, (3) transmission and generation facilities maintenance schedules, (4) contingency outages, (5) topology, (6) transmission reservations, (7) assumptions regarding transmission and generation facilities additions and retirements, and (8) counterflows. We find that requiring consistency in the data and modeling assumptions used for ATC calculations will remedy the potential for undue discrimination by eliminating discretion and ensuring comparability in the manner in which a transmission provider operates and plans its system to serve native load and the manner in which it calculates ATC for service to third parties. The Commission directs public utilities, working through NERC, to modify ATC standards to achieve this consistency.

293. With regard to EPSA's request for the standardization of additional data inputs, we believe they are already captured in the Commission's proposal as adopted in this Final Rule. Xcel asks the Commission to require consistency in the determination of counterflows in the calculation of ATC. Counterflows are included in the list of assumptions that public utilities, working through NERC, are required to make consistent. We believe that counterflows, if treated inconsistently, can adversely affect reliability and competition, depending on how they are accounted for. Accordingly, we reiterate that public utilities, working through NERC and NAESB, are directed to develop an approach for accounting for counterflows, in the relevant ATC standards and business practices. We find unnecessary Xcel's request that we require a date certain for specific issues in the Western Interconnection to be addressed. Above we require public utilities, working through NERC, to modify the ATC standards within 270 days after the publication of the Final Rule in the Federal Register.

294. With regard to Williams' request that the Commission require consistency between transmission planning horizons and procurement terms, we believe that such an express requirement is neither appropriate nor necessary. The manner in which transmission providers procure power for native load customers is generally outside the scope of this rulemaking. This notwithstanding, we note that by this Final Rule, Williams and other affected market participants will have an opportunity to participate in a transmission provider's coordinated, regional planning process. This will provide a vehicle for interested parties to gain access to planning-related information and to have their own plans for transmission evaluated at the same time the transmission provider plans for its needs. Coupled with the modifications to the ATC-related reliability standards that require the same data and assumptions to be used for calculating long-term ATC as in system planning, these reforms are adequate to address Williams' concern. To the extent there are changes on the system, these should be captured in the regional transmission planning process and in the determination of ATC. We therefore reject Entergy's proposal to allow NERC to determine the circumstances under which differences between models would be appropriate in order to ensure comparable service for all transmission customers.

295. We offer the following clarifications. In response to Southern, we clarify that we require consistent use of assumptions underlying operational planning for short-term ATC and expansion planning for long-term ATC calculation. We also clarify that there must be a consistent basis or approach to determining load levels. For example, one approach may be for transmission providers to calculate load levels using an on- and off-peak model for each month when evaluating yearly service requests and calculating yearly ATC. The same (peak- and off-peak) or alternative approaches may be used for monthly, weekly, daily and hourly ATC calculations. Regardless of the ultimate choice of approach, it is imperative that all transmission providers use the same approach to modeling load levels to enable the meaningful exchange of data among transmission providers. Accordingly, we direct public utilities, working through NERC, to develop consistent requirements for modeling load levels in MOD-001 for the services offered under the pro forma OATT.

296. With respect to modeling of generation dispatch, we direct public utilities, working through NERC, to develop requirements in NERC's MOD-001 reliability standard specifying how transmission providers shall determine which generators should be modeled in service, including guidance on how independent generation should be considered. We agree with Ameren that any modeling of base generation dispatch must model generators, including merchant generators, as they are expected to run. Accordingly, we direct public utilities, working through NERC, to revise reliability standard MOD-001 by specifying that base generation dispatch will model (1) All designated network resources and other resources that are committed or have the legal obligation to run, as they are expected to run and (2) uncommitted resources that are deliverable within the control area, economically dispatched as necessary to meet balancing requirements.

297. Regarding transmission reservations modeling, we direct public utilities, working through NERC, to develop requirements in reliability standard MOD-001 that specify (1) A consistent approach on how to simulate reservations from points of receipt to points of delivery when sources and sinks are unknown and (2) how to model existing reservations.

298. In response to commenter requests in favor of flexibility and regional differences, we again require that any waivers from the approved NERC reliability standards must take place through the NERC reliability standards process as a request for regional difference. Also, we disagree with commenters who argue that modeling assumptions should be delegated to regional reliability organizations. The goal of this rulemaking is to increase consistency in ATC calculations and that is best accomplished through NERC, which has established processes to address requests for regional differences from the reliability standard requirements. We conclude that the NERC process is appropriate as it is open to all industry participants and, therefore, is a suitable arena for establishment of common standards for modeling assumptions. g. ATC Calculation Frequency NOPR Proposal

299. The Commission proposed the development of standards requiring that the ATC calculation be performed with consistent frequency among transmission providers. Specifically, the Commission proposed that transmitting public utilities, working through NERC and NAESB, develop standards requiring that the calculation be performed by all transmission providers on a consistent time interval and in a manner that closely reflects the actual topology of the system, e.g., generation and transmission outages, load forecast, interchange schedules, transmission reservations, facility ratings, and other necessary data. The Commission also supported uniform updating of ATC values and its components (e.g., TTC, ETC, CBM, and TRM). Comments

300. Alcoa and Powerex emphasize the critical need for ATC to be calculated more frequently for

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constrained facilities. On constrained paths, where transmission equipment is stressed to its limits, Alcoa recommends that ATC be calculated on an hourly or real-time basis and be adjusted for temperature extremes. Seattle comments that ATC should be updated on a ``by exception'' basis, i.e., when significant model changes or confirmations of service requests occur. While supporting the Commission proposal, TAPS cautions against updating ATC/AFC too frequently, as this may play into the hands of those who use reservation computer programs. Commission Determination

301. The Commission adopts the NOPR proposal and requires the development of reliability standards that ensure ATC is calculated at consistent intervals among transmission providers. The Commission thus directs public utilities, working through NERC and NAESB, to revise reliability standard MOD-001 to require ATC to be recalculated by all transmission providers on a consistent time interval and in a manner that closely reflects the actual topology of the system, e.g., generation and transmission outages, load forecast, interchange schedules, transmission reservations, facility ratings, and other necessary data. This process must also consider whether ATC should be calculated more frequently for constrained facilities. ATC-related requirements for OASIS posting are discussed below. h. Data Exchange NOPR Proposal

302. The Commission proposed the development through NERC of standard protocols that would enable and require the exchange of data and coordination among transmission providers. The Commission proposed that the following data, at a minimum, be exchanged among transmission providers for the purposes of ATC modeling: (1) Load levels; (2) transmission planned and contingency outages; (3) generation planned and contingency outages; (4) base generation dispatch; (5) existing transmission reservations, including counterflows; (6) ATC recalculation frequency and times; and (7) source/sink modeling identification. The Commission expressed its view that significant improvements in the communication, coordination, and exchange of data across all transmission providers in an interconnection are needed to produce accurate determinations of ATC. The Commission sought comment as to how much data sharing is workable, whether there are additional data that should be provided, whether access to such data should be limited to transmission providers, and if there are existing forums by which these or similar data are already shared. Comments

303. Most commenters support the Commission's proposal to establish rules for data exchange, but express a preference for confidential data exchange.\186\ NERC states that proposed changes to its existing modeling standards would require transmission providers to coordinate the calculation of TTC/ATC/AFC with others. TVA emphasizes that it has already incorporated these principles into its operating processes by executing agreements that provide for data exchange and coordination with neighboring transmission systems.

\186\ E.g., Allegheny, Ameren, Arkansas Municipal, Bonneville, Constellation, CAISO, Entergy, Exelon, FirstEnergy, LPPC, MidAmerican, Santee Cooper, Seattle, and TAPS.

304. PJM suggests that the data exchange protocols be developed as minimum requirements and not interfere with existing protocols that PJM has with neighboring control areas under agreements such as the MISO/ PJM JOA.\187\ Similarly, SPP states that it also has developed seams coordination agreements with adjoining transmission providers \188\ that fully meet and, in some cases exceed, the Commission's objective of fostering greater data exchanges between transmission providers.

\187\ Under the PJM/MISO Joint Operating Agreement (JOA) and other operating agreements modeled on that agreement, parties have developed comprehensive data exchange protocols to facilitate coordination and consistent AFC calculations. Much of this data is supplied through industry standard sources such as NERC SDX and NERC eTags.

\188\ SPP has developed seams agreements to exchange ATC data and coordinate congestion with non-RTO neighbors such as the Southwest Power Administration. Further, SPP exchanges ATC/AFC data and coordinates planning, reserve sharing, outage coordination, and transmission service administration under a transmission coordination agreement with Associated Electric Cooperative, Inc. (AECI), an individual transmission provider situated on SPP's border that is not a member of SPP or any other RTO.

305. MISO is concerned that the NOPR does not address transparency and regional coordination issues arising at the seams between RTO and non-RTO regions, particularly with respect to ATC calculations. In MISO's view, the Commission-approved joint operating agreements between various ISOs and RTOs contain cutting edge ATC calculation methodologies, while no comparable common protocols have evolved with non-RTO utilities. In its reply comments, Exelon agrees with MISO that the various joint operating agreements are not consistent. Exelon proposes that the NERC standards specify requirements for coordination and the type of data that must be exchanged and used for accurate ATC calculations. Exelon contends that having uniform standards for coordination developed by NERC will enhance efficiency throughout the industry, particularly between and among RTO and non-RTO areas. MidAmerican reiterates that ATC coordination remains an issue for RTOs and that any improvements in ATC coordination resulting from this proceeding must apply to the OATTs of RTOs and non-RTOs alike.

306. NAESB states that coordination and data exchange may require business practices for existing transmission reservations, including counterflows, ATC calculation frequency, and source/sink modeling identification. Some commenters request that the Commission clarify that only information necessary for purposes of ATC modeling needs to be exchanged.\189\ In particular, they propose that proprietary generation or market information data that might harm their competitive position should not be publicly disseminated since that would not enhance the ability of transmission providers to accurately calculate ATC.

\189\ E.g., Allegheny, Constellation, and Indianapolis Power.

307. While acknowledging these confidentiality and commercial sensitivity concerns, other commenters recommend that the availability of shared data not be limited to transmission providers.\190\ For example, TAPS explains that transmission dependent utilities need an opportunity to access the data periodically as a check on the process. To address confidentiality or standards of conduct concerns, TAPS proposes that transmission dependent utilities' access to data could be achieved through an employee barred from disclosing information to marketing staff or a third party independent consultant retained by the transmission dependent utility. However, APPA and Seattle urge the Commission to eliminate artificial and institutional barriers to the exchange of data and information.

\190\ E.g., APPA, Bonneville, TAPS, and Seattle.

308. APPA and Seattle also contend that, even if data were openly available, the vast quantities of hourly data points are difficult to manage, process and analyze using existing methods. To address this issue, APPA recommends

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that the Commission encourage ongoing efforts to obtain greater resolution of system-model State variables, contractual uses and probabilistic ranges and to refine data management and analytical methods.

309. New York Commission suggests having an overarching entity, such as a Transmission Oversight Center, that is responsible for calculating and coordinating ATC between various ISOs/RTOs could overcome this lack of data. Commission Determination

310. The Commission adopts the NOPR proposal and directs public utilities, working through NERC, to revise the related MOD reliability standards to require the exchange of data and coordination among transmission providers and, working through NAESB, to develop complementary business practices. The following data shall, at a minimum, be exchanged among transmission providers for the purposes of ATC modeling: (1) Load levels; (2) transmission planned and contingency outages; (3) generation planned and contingency outages; (4) base generation dispatch; (5) existing transmission reservations, including counterflows; (6) ATC recalculation frequency and times; and (7) source/sink modeling identification. The Commission concludes that the exchange of such data is necessary to support the reforms requiring consistency in the determination of ATC adopted in this Final Rule. As explained above, transmission providers are required to coordinate the calculation of TTC/TFC and ATC/AFC with others and this requires a standard means of exchanging data.

311. While there is a near consensus among commenters that significant improvements in the communication, coordination, and exchange of data across all transmission providers are needed to produce accurate determinations of ATC, we acknowledge the concerns of ISO/RTOs that new data exchange protocols may interfere with the existing protocols and seams coordination agreements. Although we will not provide a blanket exemption for ISOs and RTOs from meeting or exceeding the data exchange requirements of this Final Rule, they may, as explained in section IV.C.2, demonstrate in relevant filings that their existing data exchange protocols are consistent with or superior to those that are developed in the NERC and NAESB processes.\191\

\191\ We are not requiring that every transmission provider follow identical protocols. Rather, all transmission providers must meet the relevant NERC reliability standards and NAESB business practices, and each entity will be subject to reliability standards compliance audits through which they will have to demonstrate that they meet or exceed the reliability standards.

312. With respect to concerns regarding the exchange of data that may be a subject of confidentiality and commercially sensitive, we only require information necessary for purposes of ATC modeling to be exchanged. As suggested by some commenters, proprietary generation or market information data that might harm a competitive position should not be publicly disseminated, since that would not enhance the ability of transmission providers to accurately calculate ATC. If any of the data are subject to confidentiality and are commercially sensitive, they must be disclosed in accordance with a confidentiality agreement. 2. Transparency a. OATT Transparency (1) Attachment C NOPR Proposal

313. In the NOPR, the Commission proposed to require each transmission provider to include in Attachment C of its OATT more descriptive information concerning its ATC/AFC calculation methodology. Specifically, the Commission proposed to require the transmission provider to state its specific mathematical algorithm used to calculate firm and non-firm ATC/AFC for its scheduling horizon, operating horizon, and planning horizon. The Commission also proposed to require transmission providers to provide a process flow diagram that illustrates the various steps through which ATC/AFC is calculated. In addition, the Commission proposed to require transmission providers to provide definitions and explain in detail how TTC, ETC, AFC, TRM, and CBM are calculated for both operating and planning horizons. Comments

314. Most commenters support the Commission's overall proposal on transparency in ATC calculations.\192\ Numerous commenters support the Commission's proposal to require detailed information in Attachment C regarding the transmission provider's ATC/AFC calculation methodology.\193\ Barrick agrees in its reply comments that a thorough explanation of how ATC is calculated should be made readily available either in the transmission provider's OATT or on its OASIS, thereby improving transparency and making it less difficult for customers to determine whether the calculations are unduly discriminatory. Old Dominion calls for greater transparency in the details of calculating ATC, even as applied to RTOs such as PJM because of the relevance of ATC at the borders of an RTO/ISO and the market impact of inconsistencies in definitions, data, modeling assumptions and frequency of ATC calculations. NERC states that the revised NERC reliability standards will address transparency.

\192\ E.g., Alberta Intervenors, AWEA, Bonneville, CAISO, Constellation, Duke, East Texas Cooperatives, ELCON, Entergy, Entegra, EPSA, E.ON, Exelon, MidAmerican, Morgan Stanley, Municipals, Nevada Companies, NPPD, PGP, PJM, Powerex, CREPC, Santee Cooper, TVA, TAPS, and TDU Systems.

\193\ E.g., Arkansas Municipal, Arkansas Commission, CAISO, Constellation, ELCON, Entergy, ISO New England, Morgan Stanley, NARUC, Nevada Companies, Occidental, PJM, Powerex, Project for Sustainable FERC Energy Policy, Santee Cooper, and Suez Energy NA.

315. NARUC contends that understanding ATC calculation methodologies and having access to the underlying data is essential to a range of critical State commission functions and, therefore, greater transparency of ATC information will significantly enhance State commissions' abilities to fulfill their statutory obligations. On reply, North Carolina Agencies agree with NARUC and state that efforts aimed at increased transparency of ATC calculations should help uncover any actual discriminatory behavior by transmission providers, provide a clearer standard against which to evaluate claims of unduly discriminatory activities, and facilitate regional planning efforts. Entegra states on reply that transmission providers should be required to post narratives explaining changes in models and factors underlying ATC and AFC values, which would be invaluable to the Commission and customers in identifying problems that may warrant enforcement actions.

316. While APPA generally supports the Commission's proposal, some of APPA's members along with other commenters express concern that including all the information might be too burdensome and result in numerous tariff changes.\194\ Some APPA members in the West also express concerns about the competitive implications of

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providing such confidential and sensitive information.

\194\ E.g., EEI, PNM-TNMP, Sacramento, Seattle, and Southern.

317. EEI also notes that providing additional detailed information in Attachment C would be duplicative and may result in confusion due to inconsistencies between the wording of the NERC and NAESB ATC documents and each transmission provider's Attachment C. To avoid uncertainty, EEI recommends that the Commission require transmission providers to comply with the requirements of Attachment C by referencing NERC reliability standards or business practices that provide the information that is called for in the Attachment. MidAmerican believes that additional information concerning calculating ATC and its components would best be retained in the transmission provider's business practices rather than Attachment C. In its reply comments, Powerex suggests an alternative of permitting transmission providers to provide a general reference to NERC, WECC, or NAESB standards and fully outline core definitions, processes, data and assumptions when deviating from such standards.

318. Southern contends that the transparency concerns expressed in the NOPR are driven more by the complexity and volume of the data involved rather than a lack of information. Southern suggests that sufficient information is readily available and the best course of action by the Commission would be to focus on documenting transfer capability methodologies available to transmission customers. NRECA replies that many commenters provided input into why more transparency is needed and repeats the example provided in its NOI comments of a cooperative that spent many months in discussions with a public utility transmission provider in an effort to understand ATC-related information posted on OASIS.

319. Pinnacle contends that the Commission's proposal for detailed information in Attachment C is only relevant in flow-based systems, pointing out that in the Western Interconnection, the scheduling horizon, and the operating horizon are the same and thus reporting such information is not necessary. APPA and Bonneville believe that adding such detail in Attachment C may only result in incremental changes and suggest that better regional coordination would provide greater transparency.

320. Though ISO New England believes this proposal would not create an undue burden, it urges the Commission to allow for variety in the illustration of the process flow diagram. Regarding the proposal to require a ``detailed explanation'' of the calculation of ATC, TTC, ETC, and TRM components, ISO New England argues that the relevant inputs can change on a daily basis because ATC for Pooled Transmission Facilities (PTF) in New England is a function of market conditions, as opposed to an administratively-derived calculation. In ISO New England's view, the level of detail required should reflect the operation of competitive markets. MISO is concerned that the NOPR does not address transparency and regional coordination issues arising at the seams between market and non-market areas, particularly with respect to ATC calculations.

321. MidAmerican strongly urges the Commission to ensure that non- public utility transmission providers adhere to the transparency requirements, since in the Pacific Northwest many of the ``backbone'' transmission lines are co-owned by jurisdictional and nonjurisdictional entities. A jurisdictional co-owner may be limited in its ability to determine such parameters as TRM and CBM because it may not be the line operator. LPPC, in its reply comments, believes it is unnecessary and redundant to require non-public utility transmission providers to adopt the ATC requirements of the pro forma OATT, because the Commission recognizes in the NOPR that NERC and NAESB are currently drafting standards for ATC, which when final will be filed with the Commission and become part of the ERO's mandatory reliability standards and fully applicable to otherwise nonjurisdictional entities.

322. Suez Energy NA contends that it is essential that the Commission include an explanation of each component of the ATC calculation in Attachment C to ensure that the transmission provider incorporates NERC standards appropriately and to ensure proper enforcement in the event that an audit shows that the transmission provider has employed other methods of calculating ATC. Suez Energy NA also notes that the mathematical algorithms and process flow diagrams should be provided to users of the transmission system, independent monitors, transmission coordinators and regulators, even if a confidentiality agreement is required. APPA suggests that the Commission and regional reliability organizations conduct additional audits to ensure that these posted practices and procedures are in fact being followed, and that the data used are verifiable. Commission Determination

323. The Commission adopts the NOPR proposal to increase transparency regarding ATC calculations by requiring each transmission provider to set forth its ATC calculation methodology in its OATT. Each transmission provider must, at a minimum, include the following information in Attachment C to its OATT. It must clearly identify which of the NERC-approved methodologies it employs (e.g., contract path, network ATC, or network AFC). It also must provide a detailed description of the specific mathematical algorithm the transmission provider uses to calculate firm and non-firm ATC for the scheduling horizon (same day and real-time), operating horizon (day ahead and pre- schedule), and planning horizon (beyond the operating horizon). In addition, transmission providers must include a process flow diagram that describes the various steps that it takes in performing the ATC calculation. Furthermore, transmission providers must set forth a definition of each ATC component (i.e., TTC, ETC, TRM, and CBM) and a detailed explanation of how each one is derived in both the operating and planning horizons. Requiring transmission providers to file a statement of their ATC calculation methodology along with a process flow diagram and more detailed definitions of ATC components in Attachment C of the OATT will provide greater transparency to transmission customers and assist in identifying any discrepancies that may arise in ATC determinations. These new requirements will assist in alleviating any appearance of discrimination in the determination of ATC.

324. The Commission acknowledges NARUC's comments that understanding ATC methodologies and the underlying data also will enhance State regulators' ability to meet their regulatory obligations. More transparent ATC calculations are critical to coordinated regional transmission planning that ultimately will improve transmission access for customers and enhance grid reliability. Transparent ATC calculations facilitate the ability of market participants and regulators to detect discrimination.

325. We do not believe our requirement to include additional information in Attachment C will be overly burdensome or lead to an excessive level of future tariff revisions. Attachment C must provide an accurate documentation of processes and procedures related to the calculation of ATC, not the actual mathematical algorithms themselves, which should be

[[Page 12309]]

posted on the transmission provider's Web site. These processes define service availability and, as such, must be part of the transmission provider's OATT. It is entirely appropriate that, because revisions to such processes impact transmission availability, they should be filed for Commission approval and included in a transmission provider's OATT. We also require transmission providers to file a revised Attachment C to incorporate any changes in NERC's and NAESB's revised reliability standards and business practices related to ATC calculations, as requested by the Commission in this Final Rule. This filing should be made within 60 days of completion of the NERC and NAESB processes. As we expect transmission providers to rarely change their ATC calculation methodologies, we do not believe this requirement will trigger an unacceptable level of tariff filings modifying the Attachment C description of the ATC components and processes.

326. We agree with ISO New England that the process flow diagram requirement may be met with a variety of illustrations, so long as it is of sufficient detail to provide the transmission customer with a reasonable understanding of the transmission provider's ATC calculation processes. The process flow diagram should support the other Attachment C requirements. As noted above, we agree with Suez Energy NA that mathematical algorithms and process flow diagrams should be made available. We do not find that a confidentiality agreement is generically warranted; however, we note that, a transmission provider may require a confidentiality agreement for CEII materials, consistent with our CEII requirements, or may otherwise protect the confidentiality of proprietary customer information.

327. We also require transmission providers to document their processes for coordinating ATC calculations with their neighboring systems. This requirement is particularly important with respect to seams between market and non-market areas, as identified by MISO, and with respect to the request of other commenters to increase regional coordination regarding ATC calculation. While this Final Rule does not address all seams issues between market and non-market areas, it does take important steps towards that end by improving data exchange between transmission providers and providing increased transparency with respect to ATC calculation.

328. We reject proposals to address the transparency of ATC methodology by merely referencing business practices and reliability standards developed by NERC, NAESB, and WECC.\195\ ATC calculations have a direct and tangible effect on the granting of open access transmission service.\196\ As such, an accurate and detailed statement of the methodology and its components that defines how the transmission provider determines ATC belongs in the transmission provider's OATT as the means of holding the transmission provider accountable for following non-discriminatory procedures for granting service, not in business practices kept by the transmission provider.\197\ However, as noted above, the actual mathematical algorithms should be posted on the transmission provider's web site, with the link noted in the transmission provider's Attachment C.

\195\ WECC has on file a Reliability Management System agreement under which transmission providers agreed, through contracts, to follow WSCC reliability criteria. Western Systems Coordinating Council, 87 FERC ] 61,060 (1999).

\196\ The Commission recognized in Order No. 889 that the methodology for calculating ATC and TTC belongs in the tariff. Order No. 889 at 31,607. At the time, the industry represented that it was engaged in efforts to develop uniform methods of determining ATC. The Commission encouraged such industry efforts and required that the tariff include the methodology, which was to be based on current industry practices, standards and criteria.

\197\ For the same reason, the Commission disagrees with the assertions of Southern and EEI that more information in Attachment C would be duplicative because some ATC-related information is already available elsewhere.

329. We also reject Pinnacle's assertion that more detailed information in Attachment C would only apply to flow-based systems. Regardless of what type of ATC calculation methodology is employed, transparency in ATC calculations is critical to avoid undue discrimination when allocating transmission capacity under the pro forma OATT.

330. In response to MidAmerican's comments regarding the applicability of the ATC-related reforms to non-public utilities, we again refer to section IV.C.3 where we discuss this issue generally. We note here, however, that the ERO's reliability standards currently in development before the Commission will be applicable to all users, owners and operators of the bulk electric grid, which includes non- public utilities.

331. We do not believe ATC-specific tariff audits are necessary to order at this time. The Commission will continue to provide oversight of all tariff-related activities through its enforcement program. Moreover, ATC requirements will be part of the mandatory and enforceable reliability standards and, as such, will be subject to compliance audits through that process. (2) CBM Practices NOPR Proposal

332. In the CBM Order, the Commission required transmission providers to post a specific narrative explanation of their CBM practices.\198\ In addition, the Commission directed transmission providers to post their procedures for allowing access to CBM during emergencies. The Commission further stated in the CBM Order that, if a utility's practice was not to set aside transfer capability as CBM, it should reflect that in Attachment C.

\198\ Capacity Benefit Margin in Computing Available Transmission Capacity, 88 FERC ] 61,099 (1999) (CBM Order).

333. In the NOPR, the Commission proposed to require transmission providers to include this CBM narrative in Attachment C of their OATTs. In addition, the Commission proposed that transmission providers explain their definition of CBM, list the databases used in their CBM calculations, and prove that there is no double-counting of contingency outages when performing CBM calculations. Comments

334. Seattle and Suez Energy NA support this proposal. Seattle states that CBM information should be specified in Attachment C in order to provide clear guidance for the specific information that is posted on OASIS. Seattle and APPA suggest that CBM should be verifiable and subject to audit by independent parties such as regional reliability organizations.

335. EEI suggests that the Commission revise Attachment C, section 3(f) to replace the word ``prove'' with the word ``demonstrate'' in the requirement that the transmission provider ``prove'' that it does not double count contingency outages when calculating CBM, TTC and TRM. EEI notes that the term ``prove'' implies a determination on the merits after evaluation of competing arguments and evidence. A transmission provider should be able to satisfy its obligations by ``demonstrating'' the absence of a double count. Any customer that wishes to challenge the demonstration can do so, at which time the issue of ``proof'' would arise.

336. With regards to ``double counting,'' TVA references TRM and agrees that additional explanations regarding the calculation of TRM, including methods used to avoid double counting contingency events, should improve transparency in providing open access transmission service. TVA points out that this is being addressed by a NERC standards drafting team.

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Commission Determination

337. The Commission adopts the NOPR proposal requiring additional information in the transmission provider's OATT Attachment C regarding its determination of CBM. Transmission providers must provide in Attachment C a narrative description detailing their CBM practices. In addition, a transmission provider must explain its definition of CBM and list the databases used to derive its value. These new requirements will provide transmission customers transparency into the CBM component of ATC and help discourage the potential for undue discrimination in the calculation and use of CBM.

338. We adopt EEI's proposal that the Commission revise Attachment C, section 3(f) to replace the word ``prove'' with the word ``demonstrate.'' The word ``demonstrate'' more accurately describes the showing we expect the transmission provider to make. We agree that the word ``prove'' implies a standard of proof that we did not intend to impose. We also acknowledge TVA's comments that the NERC standards drafting team is developing standards that should address ``double counting'' in ATC calculations in general. However, we require that the information in Attachment C be sufficient to demonstrate that a transmission provider is not double counting CBM in its ATC calculation.

339. Finally, the Commission rejects the proposal by Suez Energy NA, APPA, and Seattle to establish formal audits of CBM set asides. Requirements for CBM will be part of the mandatory and enforceable reliability standards and, as such, will be subject to compliance audits through that process. Moreover, the Commission provides oversight of all tariff-related activities through its enforcement program. b. OASIS (1) ATC/TTC Posting Requirements NOPR Proposal

340. The Commission's existing regulations require certain ATC- related information to be posted on each transmission provider's OASIS and other information to be provided on request. To ensure that relevant information is available on a timely basis to all market participants, the Commission proposed in the NOPR to amend its regulations to allow potential customers greater access to information that will enable them to obtain service on a non-discriminatory basis from any transmission provider.

341. The Commission noted in the NOPR that existing regulations require ATC and TTC calculations to be performed according to consistently applied methodologies referenced in the transmission provider's OATT and current industry practices, standards and criteria. The Commission proposed that these calculations be based on the ERO reliability standards.

342. The Commission further proposed to maintain the requirement that transmission providers provide, on request, all data used to calculate ATC and TTC for any constrained paths. Transmission providers also would remain required, on request, to make publicly available any system planning studies or specific network impact studies performed for customers and to post a list of such studies on OASIS. Comments

343. Several commenters support the proposal to post ATC-related information on OASIS.\199\ TDU Systems supports each of the Commission's proposals with respect to providing easier access to data underlying ATC calculations and greater transparency to the process. Sacramento states that posting on OASIS will ensure proper public access, but will avoid the need for Commission approval of an OATT change.

\199\ E.g., APPA, Constellation, FirstEnergy, Indianapolis Power, Sacramento, Suez Energy NA, TAPS, and TDU Systems.

344. Constellation strongly supports the need for additional transparency, stating that providing transmission customers with meaningful insight into the current ``black box'' determination of ATC will help minimize the mystery underlying many transmission provider responses to service requests. According to Constellation, further transparency will assist customers in predicting the outcome of transmission service requests and facilitate increased commercial activity. Constellation suggests that the Commission require transmission providers to provide transmission customers, on request, with specific details related to modeling data, modeling support information, modeling benchmarking and forecasting data, and transmission service request audit data. It requests that the information be in a form and format usable by the transmission customers and that the Commission take steps to ensure that transmission customers understand how ATC is calculated and the data inputs are used to affect those calculations.

345. Great Northern likewise requests that the Commission enhance the requirement to provide all data on request, specifically on constrained paths, by requiring a posted tabulation of annual and monthly ATC calculation details. Great Northern suggests including TTC, network load for each transmission customer, capacity reserved for each network resource, each point-to-point transmission service reservation, CBM and other deductions from TTC.

346. APPA members support the posting of ATC information, as it will assist in using ATC more efficiently, and they support the posting of system planning studies and specific network impact studies that the transmission provider performs for its own merchant function, as well as studies performed for customers. In addition, APPA suggests the posting of facilities studies at the time they become available, assuming that this can be done consistent with CEII concerns. TAPS goes further by urging the Commission to close gaps in the current OASIS requirements by requiring posting of all studies performed for transmission owners' own transmission network resource designations and other uses of the system, including facilities studies as well as system impact studies, ensuring posted study lists are updated contemporaneously with the availability of new studies, and requiring retention of studies for a minimum of five years.

347. Nevada Companies and TVA support cost effective measures that increase transparency in transmission operations and, unless the requirement becomes unduly time consuming or burdensome, in general support more disclosure rather than less. Commission Determination

348. The Commission adopts the proposal in the NOPR to continue to require transmission providers to comply with existing ATC-related posting obligations as supplemented by this Final Rule. The Commission will continue to require transmission providers, on request, to make available all data used to calculate ATC and TTC for any constrained paths and any system planning studies or specific network impact studies performed for customers. Transmission providers must also continue to post a list of such studies on OASIS.

349. In addition, we agree with the requests of APPA and TAPS to require the additional posting of, at a minimum, a listing of all system impact studies, facilities studies, and studies performed for the transmission provider's own network resources and affiliated transmission customers, to be made available upon request. We note that appropriate procedures to accommodate CEII concerns should be developed to

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ensure eligible entities with a legitimate interest in transmission study data can receive access to it. Also, we adopt TAPS' suggestion that the studies be made available for five years to make the requirement consistent with data retention requirements pertaining to denial of service requests.

350. The Commission rejects Constellation's and Great Northern's proposals to require transmission providers to provide upon request or regularly post additional information beyond that required in the regulations and this Final Rule. The transmission provider is already required to make available, upon request and in electronic format, all information related to the calculation of ATC and TTC for any constrained path. Accordingly, we see little benefit to require transmission providers to provide upon request or regularly post additional information suggested by these commenters. (2) CBM/TRM Posting Requirements NOPR Proposal

351. The Commission's OASIS regulations currently require transmission providers to calculate and post ATC and TTC for each posted path, but make no requirement for CBM and TRM postings. In the CBM Order, however, the Commission required transmission providers, with respect to each path for which the utility already posts ATC, to post (and update) the CBM figure for that path. The Commission also required transmission providers to make any transfer capability set aside for CBM available on a non-firm basis and to post this availability on OASIS. In the NOPR, the Commission proposed to incorporate these CBM posting requirements into its regulations. The Commission also proposed that transmission providers post (and update) the TRM values for the paths on which the transmission provider already posts ATC, TTC, and CBM. Comments

352. Several commenters strongly support the Commission's proposal to require transmission providers to post TRM and CBM.\200\ APPA and EPSA agree that the posting of TRM for near term transmission services would provide greater assurance that ATC calculations are being performed according to established procedures. Since transmission providers already have this information, FirstEnergy states that it does not appear to be unduly burdensome for them to post such information. Bonneville indicates that it currently posts TRM values in its Business Practices Forum, which is useful for examining curtailment events, supporting transmission planning objectives, and validating posted ATC values.

\200\ E.g., Powerex, PJM, PPL, Seattle, and Pinnacle.

353. EPSA also recommends that the Commission provide guidance on standards that should be developed to require each transmission provider to notify the Commission in writing and post a notice on its OASIS within 24 hours of a transmission provider's use of CBM to import emergency power. EPSA also requests that the amount of CBM reserved for each interface be posted on OASIS. Commission Determination

354. The Commission adopts the CBM posting requirements proposed in the NOPR. In doing so, we amend our OASIS regulations to incorporate the directives established in the CBM Order. Accordingly, we require transmission providers to post (and update) the CBM amount for each path. In addition, the Commission requires transmission providers to make any transfer capability set aside for CBM but unused for such purpose available on a non-firm basis and to post this availability on OASIS. Furthermore, the Commission requires transmission providers to post (and update) the TRM values for the paths on which the transmission provider already posts ATC, TTC, and CBM.

355. We reject EPSA's request to require transmission providers to notify the Commission in writing and post a notice on OASIS within 24 hours of a transmission provider's use of CBM to import emergency power and transfer capability set aside as CBM at each of the transmission provider's interfaces. The additional transparency of CBM-related information provided in this Final Rule, along with the reforms related to consistency of CBM, will cause sufficient information to be made available to customers concerning the use of CBM. The use and allocation of CBM and TRM will be more transparent to transmission customers, thus reducing the potential for undue discrimination. (3) Periodic Reevaluation of the CBM Set-Aside NOPR Proposal

356. In the CBM Order, the Commission stated that the level of ATC set aside for CBM can and should be reevaluated periodically to take into account more certain information (such as assumptions that may not have, in fact, materialized).\201\ The Commission therefore directed transmission providers to periodically reevaluate their generation reliability needs so as to make known the availability of CBM and to post on OASIS their practices in this regard.\202\ In the NOPR, the Commission proposed to incorporate these requirements in the Commission's regulations and to obligate transmission providers to reevaluate the CBM set-aside at least quarterly.

\201\ CBM Order at 61,237.

\202\ Id.

Comments

357. Some commenters support quarterly reevaluation of CBM set- asides.\203\ TAPS agrees with the need for full transparency of CBM reservations and practices and states that, because CBM values may differ from season to season, CBM values should be separately calculated for at least each quarter. However, TAPS does not find that it is necessary or appropriate for the CBM values to be reevaluated quarterly, given the effort involved in collecting the data and performing the modeling analysis. Rather, CBM studies should be performed at least every other year, supplemented with ``off-year studies'' when appropriate.

\203\ E.g., EPSA, Sacremento, Santa Clara, Suez Energy NA, and TDU Systems.

Commission Determination

358. The Commission incorporates into its regulations the requirement in the CBM Order for a transmission provider to periodically reevaluate its transfer capability set-aside for CBM. With respect to TAPS' concerns over the effort involved in the re-evaluation process, we will require CBM studies to be performed at least every year. This requirement is consistent with the CBM Order, in which the Commission stated that the level of ATC set aside for CBM should be reevaluated periodically to take into account more certain information (such as assumptions that may not have, in fact, materialized).\204\ While changes requiring a reevaluation of CBM are longer-term in nature (e.g., installation of a new generator or a long-term outage), quarterly may be too frequent, though two years may be too long and may prevent a portion of the CBM set-aside from being released as ATC. Moreover, annual reevaluation is consistent with the current NERC standard being developed in MOD-005.\205\ The requirement to evaluate CBM at least every year also is consistent with the CBM Order in that

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the Commission directed transmission providers to periodically reevaluate their generation reliability needs so as to make known the need for CBM and to post on OASIS their practices in this regard.

\204\ CBM Order at 61,237.

\205\ The MOD-005 reliability standard establishes the procedure for verifying CBM values.

(4) ATC/TTC Narrative Explanation NOPR Proposal

359. In the NOPR, the Commission proposed to largely retain existing posting requirements for unconstrained posted paths, but to amend the regulations relating to data posted for constrained posted paths. Existing regulations require ATC and TTC on constrained paths to be updated when (1) Transactions are reserved, (2) service ends, or (3) whenever the TTC estimate for the path changes by more than 10 percent.\206\ In the NOPR, the Commission proposed to supplement the existing regulations by requiring the transmission provider to post a brief, but specific, narrative explanation of the reason for the change at the time a change in monthly and yearly ATC values on a constrained path is posted. The Commission sought comment on whether the posting of this new information would provide adequate transparency to the customer on a frequent enough basis without imposing an undue burden on the transmission provider. The Commission also sought comment on whether a similar narrative should be required when ATC remains unchanged at a value of zero for some specified period of time.

\206\ See 18 CFR 37.6(b)(3)(i)(C).

Comments

360. Some commenters support the Commission's proposal to require transmission providers to post more detailed explanations about changes in ATC values on their OASIS sites.\207\ NAESB, TranServ, and Williams request that the Commission clarify the regulatory requirements for posting of updated ATC values such as the level of standardization, frequency and time of postings, and other requirements. CAISO believes that ATC should be updated on a daily basis.

\207\ E.g., Arkansas Commission, CAISO, Constellation, East Texas Cooperatives, Exelon, FirstEnergy, LPPC, Morgan Stanley, NRECA, Pinnacle, Powerex, Santa Clara, and Suez Energy NA.

361. Powerex and Nevada Companies propose that additional disclosures be posted, such as data on grandfathered contracts, time- specific data relevant to transmission constraints and ATC rights on posted paths, and remaining customer rights under a reservation-based network service system.

362. A few commenters caution that some of the data that the Commission is requiring to be posted by transmission providers is market-sensitive and, if posted on a real-time basis, could be used by third parties to obtain an unfair competitive advantage.\208\ These commenters propose that the transmission providers should be allowed a brief period of delay (e.g., one week) before posting data. Indianapolis Power also advocates a delay due to the burden on transmission providers of the new posting.

\208\ E.g., Ameren, ISO New England, Southern, and NRECA.

363. Several commenters oppose the Commission's proposal to require that transmission providers post narratives on OASIS outlining reasons why monthly and yearly ATC values on constrained paths change.\209\ These commenters contend that this will cause undue burden on transmission providers without providing customers with any significant or new information. They also argue that the proposal is impractical and will not result in providing transmission customers with meaningful information regarding transmission service options.

\209\ E.g., Ameren, EEI, Entergy, MISO, Pinnacle, PJM, PNM-TNMP, Southern, TranServ, and TVA.

364. If such a requirement is adopted, MISO recommends that a threshold higher than a 10 percent change in ATC be established and that the Commission clarify what the term ``specific explanation'' means in this context. PJM states that it already exceeds the Commission's proposed requirement. However, if strictly applied, this proposal would be unduly burdensome on PJM because it would require PJM to post a narrative each hour. PJM asks that the Commission not apply unnecessary and costly posting requirements on independent RTOs and ISOs.

365. EEI and Southern are concerned that monthly ATC may change in response to every reservation of hourly transmission service because a reservation of hourly firm service on a constrained path may reduce the availability of monthly firm service. EEI contends that, if transmission providers are required to post changes in TTC instead of ATC, they would not be required to post a new narrative every time a reservation is made, thus reducing the overall burden on transmission providers. EEI additionally states that the reasons for changes in TTC and ATC values often are complex and involve the interaction of multiple variables in the model that produces the TTC and ATC values and a specific change in TTC or ATC cannot easily be traced to a specific change in the inputs. Alternatively, EEI suggests that transmission providers could post the major changes in the inputs to the TTC modeling software that are made in connection with each updated TTC posting without ascribing specific inputs to specific changes in TTC and ATC values on specific lines.

366. Several commenters are supportive of the proposed requirement that transmission providers provide a narrative explanation when ATC values remain at zero.\210\ APPA suggests that if a particular interface shows an ATC of zero for a specified period, the transmission provider should provide a narrative explanation of why this is the case and how its plans to address this problem. It also suggests that this information should be employed in the transmission planning process. East Texas Cooperatives, in reply comments, state that the narrative can provide useful information to the transmission customers and State and Federal regulators regarding specific conditions regarding ATC coordination.

\210\ E.g., APPA, East Texas Cooperatives, Suez Energy NA, and TAPS.

367. In supplemental comments, NAESB states that the Commission should specify whether it is sufficient for the explanation of changes in ATC or TTC values to be limited to broad generalized statements or whether the posted information should include such information as the specific events which gave rise to the change, the new values for ATC at all points on the network, the impact of the change on transmission customers, and a detailed snapshot of the conditions on the system at all flowgates or constrained elements when the change occurred.\211\

\211\ November 2, 2006, Addendum to the Testimony of Ronald M. Mucci on behalf of the North American Energy Standards Board, Preventing Undue Discrimination and Preference in Transmission Service, Docket Nos. RM05-25-000 and RM05-17-000, October 12 Technical Conference, pp. 2-3.

368. Southern states that posting a narrative when ATC remains at zero is unwarranted and unnecessary, as it simply indicates that the market has responded to market signals of ATC availability and purchased all available capacity. Commission Determination

369. The Commission adopts the NOPR proposal, with the modifications discussed below, to require that the transmission provider post a brief, but specific, narrative explanation of the reason for a change in monthly and yearly ATC values on a constrained path. Rather than requiring a narrative

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when a monthly or yearly ATC value changes as a result of transactions being reserved, service ending, or the TTC estimate for the path changing by more than 10 percent, we will require a narrative when a monthly or yearly ATC value changes only as a result of a 10 percent change in TTC. This will reduce the number of ATC changes for which a narrative will be required and address concerns that the new requirement unduly burdens transmission providers. Any remaining burden is justified by the benefit to transmission customers of receiving timely information regarding changes in TTC that result in changes to ATC. In addition, we adopt NAESB's suggestion that posted information include the (1) Specific events which gave rise to the change and (2) new values for ATC on that path (as opposed to all points on the network).

370. We reject calls for delays prior to posting data. While commenters allege the possibility of granting others a competitive advantage through the release of ``market-sensitive'' data, they have proffered no evidence to support the allegation of potential harm.

371. We do require, as suggested in the NOPR, a narrative with regard to monthly or yearly ATC values when ATC remains unchanged at a value of zero for a significant period, and will set that period at six months or longer. This information will be valuable to customers and regulators in assessing the ability of a transmission provider's facilities to meet existing service requests. The information also will provide assurance to customers that the transmission provider is diligent in regularly evaluating ATC on all paths, monitoring persistent constraints and addressing them in its planning processes.

372. Finally, we reject CAISO's suggestion that ATC be updated daily on a transmission provider's OASIS site, because CAISO offered no justification for the proposal. (5) Denial of Service/Records Retention NOPR Proposal

373. In the NOPR, the Commission proposed to maintain the requirement that a transmission provider post the reason for a denial of a request for service. The Commission also proposed to amend this provision to require a transmission provider to maintain and make available information supporting the reason for the denial. The Commission further proposed to extend the time period for which transmission providers must maintain transmission service information for audit. Currently, regulations require that audit data be retained and made available upon request for download for three years from the date when they are first posted. The Commission proposed to change the period from three to five years. Comments

374. Many commenters support posting of the reasons for denying service and the 5-year retention proposal.\212\ TAPS supports the proposal but suggests several modifications. First, it suggests that the Commission clarify the requirement to post the reasons for denying service is triggered not only by denial of the entirety of a transmission request, but to any disposition that falls short of a full unconditional grant of the service (with rollover rights if applicable). Second, TAPS recommends that the regulatory text of proposed section 37.6(e)(2)(ii) be modified to make the supporting data available, upon request, to any eligible customer rather than just to the customers who were denied service. Third, it asks that the Commission expand its OASIS regulations to require the transmission provider to maintain and make available on request the information supporting the disposition (positive, negative, or in between) of its own network resource designations and other usage needs. East Texas Cooperatives suggest that the Commission also require that transmission providers distinguish between denials of requests for firm and non-firm transmission service.

\212\ E.g., APPA, Arkansas Commission, Arkansas Municipal, Duke, East Texas Cooperatives, MISO, ISO New England, Williams, Nevada Companies, PPL, Sacremento, Sant Clara, Suez Energy NA, and TDU Systems.

375. Some commenters urge the Commission to clearly define the scope of any transmission service request information subject to the proposed five-year record retention requirement to ensure that no undue administrative burden is placed on transmission providers.\213\ TVA questions the need to extend the time period for an additional two years. TVA states that the benefits of extension are not commensurate with the increased costs, since it is unaware of any problems that have arisen with the current three-year timeline. Seattle argues on reply that the Commission should retain the NOPR posting requirements in the Final Rule because information on actual transmission congestion can be helpful instead of sole reliance on simulation models.

\213\ E.g., MidAmerican, PacifiCorp, PNM-TNMP, and PJM.

Commission Determination

376. As proposed in the NOPR, the Commission maintains the requirement that a transmission provider post the reason for a denial of service and extends from three years to five years the period for which transmission providers must maintain data providing reasons for denial of service. In general, commenters support the requirement for posting denial of service information and the increase in retention time to five years, indicating that such information can be helpful to customers in their awareness of actual transmission congestion, rather than relying on simulation models.

377. We also adopt TAPS' suggestion to expand the regulations to include availability of information supporting the disposition of a transmission provider's own network resource designations and to make such information available to any eligible customer rather than just to that customer denied service. In addition, we clarify that a partial denial of service triggers the requirements as well. Such information is consistent with the new regulations established by this Final Rule and will help ensure that customers receive transmission service that is not unduly discriminatory. The development of a log of service denials, full or partial, will establish an ongoing record of service requests and transmission provider responses demonstrating the transmission provider's provision of nondiscriminatory open access service. Furthermore, repeated denials of service over a particular path or flowgate will provide an indication of congestion that can be used in the transmission planning process. In addition, we agree with East Texas Cooperatives that postings of denials of service should indicate whether the requested service was firm or non-firm. (6) Designation and Termination of Network Resources NOPR Proposal

378. In the NOPR, the Commission proposed to require the transmission provider and network customers to use the transmission provider's OASIS to request designation of a new network resource and to terminate the designation of a network resource. This information would be posted on OASIS for 90 days and be available for audit for a five-year period. Transmission customers therefore would be able to query such requests to designate and

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terminate a network resource.\214\ The Commission also proposed to require the transmission provider to post on its OASIS a list of its current designated network resources and all network customers' current designated network resources. The list would include the resource name, geographic and electrical location and amount of capacity of the designated network resource.

\214\ See 18 CFR 37.6(a)(6).

Comments

379. Several commenters support the Commission's proposal to require transmission providers and network customers to use the transmission provider's OASIS to request or terminate designation of resources, though some indicated that the required network resource information is currently available via OASIS.\215\ PJM supports the proposal, provided that the electrical location is based on an industry standard format and any standard adopted by NERC takes into consideration possible confidentiality issues when posting the geographic location of designated network resources.

\215\ E.g., APPA, Exelon, PJM, TAPS, TranServ, and TDU Systems.

380. APPA suggests that reservations related to future load growth also should be posted so that it is clear to all industry participants what transmission capacity transmission providers are reserving for load growth purposes. Williams submits that the list of current designated resources needs to indicate whether they are for native load or network customers, or whether they are for meeting forecasted loads and system emergencies.

381. TranServ supports the Commission's proposal and indicates that NAESB is the appropriate forum for development of standards necessary to support posting the designation and termination of network resources. TranServ cautions that implementation will require a sufficient period of time after the practices and standards are developed and suggests that changes to OASIS should be timed to avoid peak summer and winter seasons.

382. Exelon requests that the Commission clarify that transmission providers and network customers making firm off-system sales may terminate designation of network resources solely for the term of such sale and not for other periods of time. During this period of termination, the firm capacity is posted and made available to other customers.

383. Great Northern supports the proposal and requests clarification that, when a network resource is ``undesignated,'' ATC will not be set aside in anticipation that it might be designated again as a network resource in the future. Great Northern requests that the Commission confirm that new requests to designate network resources, regardless of the prior designation of those resources, are placed at the end of the transmission service queue.

384. Sacramento states that the posting requirements for network resources are an unnecessary burden and instead recommends that the transmission provider should be required to identify resources it is transmitting to native load when it denies a request for transmission service from a third party. Commission Determination

385. The Commission adopts the NOPR proposal and requires transmission providers and network customers to use OASIS to request designation of new network resources and to terminate designation of network resources.\216\ This information shall be posted on OASIS for 90 days and available for audit for a five-year period. Transmission customers thus shall be able to query requests to designate and terminate a network resource. This requirement adds valuable transparency without undue burden, since it is nothing more than maintaining a database of designation requests made and responded to electronically. The Commission orders public utilities, working through NAESB, to develop appropriate templates for OASIS.

\216\ See paragraph 1477, where further detail on using OASIS to request designation of network resources is provided.

386. The requests for clarifications by Exelon and Great Northern will not be addressed in this section. These requests are not related to OASIS postings, but involve changes in tariff language. They are addressed in section V.D.6 of this Final Rule. (7) Posting of Unused Transfer Capability NOPR Proposal

387. In the NOPR, the Commission reminded transmission providers that transfer capability associated with transmission reservations that is not scheduled in real time should be included in non-firm ATC and posted on OASIS. Comments

388. Entegra, TANC, and TDU Systems emphasize the need for the posting of unused transfer capability. TDU Systems state that the requirement to post on OASIS all transfer capability associated with transmission reservations not scheduled in real time furthers not only the Commission's goals with respect to comparability and transparency of ATC calculations, but also the Commission's goals in freeing up access to transmission capacity for transmission customers. Commission Determination

389. We affirm our statement in the NOPR proposal acknowledging that transfer capability associated with transmission reservations that are not scheduled in real time is required to be made available as non- firm, and posted on OASIS. (8) Other OASIS Issues Comments

390. MidAmerican, PacifiCorp and Pinnacle contend that the development of the OASIS posting requirements is technical in nature and should be addressed by the NERC and NAESB processes.

391. NRECA recommends that the Commission require public utility transmission providers to make OASIS data available in a useable, machine-readable and manipulable format to transmission customers (so they can be better prepared to make decisions about their transmission needs) and to the Commission (so that it can monitor the provision of transmission service). Similarly, Powerex states that posted data must be in sufficient detail to permit third parties to independently review and verify ATC postings and treatment of transmission service requests.

392. Utah Municipals suggest that OASIS sites be as uniform and compatible as possible and reasonably user-friendly, and that certificate fees for access to non-public sites be evaluated for legitimacy. Arkansas Commission and Seattle also express concern over the OASIS access requirements established by most transmission providers, which require viewers to purchase certificates or licenses for the particular computers from which OASIS access is sought.

393. Williams suggests that all transmission service-related business practices and local procedures, including the exercise of discretion or waiver or granting of exception, be posted on the transmission provider's OASIS. It also suggests that real-time data and import/export limits by constrained area should be posted on OASIS, along with line outages

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

[[pp. 12315-12364]] Preventing Undue Discrimination and Preference in Transmission Service

[[Continued from page 12314]]

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(planned and unplanned), estimated return to service dates and de-rates of a line. Commission Determination

394. In response to NRECA and other commenters regarding the availability and format of data available on OASIS, we note that current regulations already require that OASIS data be made available in a useable, machine-readable user friendly format to transmission customers. The improvements required in the Final Rule will enhance the level of detail posted on OASIS and, in turn, transmission customers' ability to verify the transmission provider's treatment of transmission requests. Thus, to the extent NRECA or others desire greater consistency in data formats, they should propose such revisions through the NERC and NAESB processes.

395. Regarding comments received expressing concern about the use of certificates for OASIS access, we believe that the use of such certificates can be appropriate. However, the Commission reminds transmission providers that the cost of OASIS access, whether by registration, certificate or other form of license, should be limited to a nominal charge, e.g., no more than $100. This nominal fee provides funding for OASIS maintenance while assuring that all transmission customers and potential customers will not be denied access because of excessive fees.

396. With respect to Williams' request for additional OASIS postings, we agree that such additional data would be useful to transmission customers and is already posted on some ISO and RTO Web sites and, to a lesser extent, on the NERC web site (TLR data). Therefore, we require that all transmission service-related business practices and local procedures, including waivers, should be posted on or made available through OASIS. With respect to real-time data and import/export limits by constrained area, estimated return-to-service dates and line de-ratings, we are confident that most of this data is already required by this Final Rule and shall be provided whenever TTC and ATC changes in value trigger the posting of a narrative explanation of the causes of those changes. Moreover, the Final Rule requires a broad data exchange among transmission providers, including information on line outages and other data relating to ATC calculations. Accordingly, we will not require additional OASIS postings for this data. (9) CEII NOPR Proposal

397. Critical Energy Infrastructure Information (CEII) is information concerning proposed or existing critical infrastructure (physical and virtual) that (1) Relates to the production, generation, transportation, transmission or distribution of energy, (2) could be useful to a person in planning an attack on critical infrastructure, (3) is exempt from mandatory disclosure under the Freedom of Information Act, 5 U.S.C. 552, and (4) does not simply give the location of the critical infrastructure.\217\ Access to such transmission related information has been restricted by the Commission's CEII regulations.\218 \

\217\ See Critical Energy Infrastructure Information, Order No. 683, 71 FR 58273 (Oct. 3, 2006), FERC Stats. & Regs. ] 31,228 at P 66 (2006), reh'g pending. We note that the Commission is proposing to change the definition of CEII in a proceeding in Docket No. RM06- 23-000. See Critical Energy Infrastructure Information, Notice of Proposed Rulemaking, 71 FR 58325 (Oct. 3, 2006), FERC Stats. & Regs. ] 32,607 (2006).

\218\ See 18 CFR 388.112-113.

398. In the NOPR, the Commission recognized that the use of the existing CEII processes could undermine their goal of providing increased transparency to information necessary to evaluate the use of the transmission system. As a result, the Commission requested comment on procedures that could be adopted by transmission providers to streamline the resolution of CEII concerns and allow timely disclosure of information from the transmission providers to interested parties. Comments

399. APPA and other commenters argue that the additional information disclosure requirements proposed in the NOPR raise substantial CEII concerns, and request the Commission to refine its CEII procedures to allow those with legitimate need for the information to obtain it on a timely basis.\219\ Bonneville would like to permit public access for stakeholders to review principles and methods used in ATC calculations, but only permit limited access, subject to background checks and non-disclosure agreements, to modeling data that may compromise infrastructure security. APPA suggests establishing a process for advance qualification for receipt of such information by those industry participants with rights to review information on the customer side of OASIS, without giving blanket public access. TDU Systems urge the Commission to adopt a streamlined process to ensure timely resolution of ATC calculation disputes and to adopt measures that ensure that CEII claims do not unduly restrict information.

\219\ E.g., MidAmerican, Sacramento, Southern, and TVA.

400. EEI and Southern caution that the release of a transmission provider's explanation of methodologies, practices, and procedures in Attachment C may not give rise to CEII concerns, but that other information such as energy infrastructure data, models and assessments do raise security and confidentiality concerns. They propose that a transmission provider have the ability to seek confidential treatment of such information. Allegheny proposes that an independent third party or Commission staff review and explain ATC calculations to interested parties without disclosing CEII.

401. Several commenters believe that much of the information the Commission proposes to require transmission providers to provide will not pose CEII concerns.\220\ However, Entergy states that some of the information requires protection as proprietary information because its public availability over OASIS would reveal commercially sensitive information. ISO New England also points out that information relevant to the ATC calculation may be market-sensitive

\220\ E.g., Nevada Companies, East Texas Cooperatives, PJM, and TDU Systems.

402. Pinnacle believes the current CEII process is not unduly burdensome and urges the Commission to continue to apply the existing CEII procedures, which allow transmission customers with digital certificates or passwords to access publicly restricted transmission information. Commission Determination

403. The Commission acknowledges that certain data and studies required to be made public under this Final Rule may contain CEII. The Commission has a responsibility to protect this information. However, the Commission agrees with APPA, Bonneville, and TDU Systems that those with a legitimate need for CEII information must be able to obtain it on a timely basis. The Commission also shares EEI and Southern's concerns that the data, models and assessments used to calculate ATC may contain information that raises security and confidentiality concerns, and ISO New England and Entergy's concerns about commercial and market-sensitive information.

404. In order to provide transparency and avoid undue delays in providing information to those with a legitimate need for it, the Commission requires

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transmission providers to establish a standard disclosure procedure for CEII required to be disclosed by this Final Rule. We note that transmission customers already have digital certificates or passwords to access publicly restricted transmission information on OASIS. Transmission providers may set up an additional login requirement for users to view CEII sections of the OASIS, requiring users to acknowledge that they will be viewing CEII information. Transmission providers may require customers to sign a nondisclosure agreement at the time that the customer obtains access to this portion of the OASIS. Only information that meets the criteria for CEII, as defined in section 388.113 of the Commission's regulations,\221\ should be posted in this section of the OASIS. Transmission providers will be responsible for identifying CEII and facilitating access to it by appropriate entities, and the Commission will be available to resolve disputes if they arise.

\221\ 18 CFR 388.113.

(10) Additional Data Posting NOPR Proposal

405. To further reduce discretion in calculating ATC/AFC, the Commission proposed that transmission providers post on OASIS metrics related to the provision of transmission service under their OATT. In the NOPR, the Commission proposed to require the monthly posting of (1) The number of affiliate versus non-affiliate requests for transmission service that have been rejected and (2) the number of affiliate versus non-affiliate requests for transmission service that have been made. This posting would also detail the length of service request (e.g., short-term or long-term) and the type of service requested (e.g., firm point-to-point, non-firm point-to-point or network service). The Commission sought comments regarding whether it should require transmission providers to post their underlying load forecast assumptions for all ATC calculations and, on a daily basis their actual daily peak load for the prior day. Finally, the Commission asked for comment on the overall benefit of posting the proposed metrics, on potential alternative metrics, and on working through NAESB to develop standards for consistent methods of posting the new requirements on OASIS. Comments

406. PJM and other commenters support the proposal to post data showing acceptances and denials of transmission service requests of non-affiliates and affiliates.\222\ However, PJM and Ameren argue that the affiliate posting requirement should not apply to RTOs and ISOs, because they are independent, have no affiliates, and lack incentive to favor one transmission customer over another. MDEA requests clarification on how the additional posting requirements would be applied under Entergy's weekly procurement process. Entergy notes on reply that the Commission has already established metrics to measure the performance of its weekly procurement process, and the creation of further metrics are beyond the scope in a generic rulemaking. Entergy further points out that non-affiliated generating facilities that are designated as network resources to serve native load also benefit from transmission service obtained in this manner. It suggests that NAESB is the best forum for considering such issues and developing specific procedures for calculating these metrics. TranServ suggests that there are other useful metrics that NAESB should be directed to define, such as average time to evaluate requests and confirm requests, and percentage of requests denied, approved and withdrawn.

\222\ E.g., Arkansas Commission, Constellation, MidAmerican, MDEA, Morgan Stanley, Nevada Companies, NRECA, Suez Energy NA, and TranServ.

407. PJM notes its support of proposed OASIS posting reforms, but cautions that all industry groups must have an equitable and proportionate voice in NAESB if it is requested to develop standards. It also expresses concern that PJM and other RTOs have established a practice of posting a significant amount of data for participants' use in formats and applications which respective members have requested and approved through stakeholder processes.

408. APPA points out that the data on transmission denials would be useful to the Department of Energy (DOE) in reporting on congestion in its triennial congestion studies to be prepared under FPA section 216(a), and that NAESB may be able to provide standard formats for disclosure of such data. Some APPA members express a preference for NERC to develop these standards, while others stress the need for regional variation in posting requirements.

409. Ameren questions whether the posting requirement would serve the Commission's objective of identifying undue discrimination even in cases where the transmission provider is not an RTO or other independent transmission provider, because the metrics can lead to incorrect impressions. MidAmerican also states that the proposed posting would require sophisticated analysis to yield useful benefits.

410. EEI is not opposed to the proposal to post metrics on acceptance and denial of requests for transmission service, but suggests such information is already available on OASIS and that any customer or the Commission staff can develop its own metrics. Southern also states that this data is currently available.

411. Several commenters support the posting of forecast and actual daily peak loads.\223\ Ameren states that the proposed requirement would produce a useful comparison, increase transparency, and provide the ability to verify that an appropriate amount of capacity is being set aside for native load. E.ON states that RTO and ISO forecasts and actual data need to be posted with sufficient granularity to allow for meaningful comparison of control area and LSE load levels. EEI requests that the Commission clarify that its proposal to require the posting of peak loads applies to system-wide loads and not only to the native load of the transmission provider. It also seeks clarification that the differences between forecast and actual system peak loads not result in any repercussions.

\223\ E.g., Ameren, Constellation, E.ON, Nevada Companies, NRECA, Powerex, Suez Energy NA, TAPS, TDU Systems, and TranServ.

412. APPA members in the East generally favor the proposal to post the load information, but its members in the West expressed concerns about the competitive implications of providing such data. Additional commenters express concern about data confidentiality.\224\ TAPS contends that providing for data disclosure on a one-day lag basis would alleviate these commercial concerns, but it also suggests that the Commission should require the disclosure of projected load forecast information on request to a customer's non-market employees or agents.

\224\ E.g., E.ON, Entergy, LDWP, and TranServ.

Commission Determination

413. The Commission adopts the proposed requirement to post on OASIS metrics related to the provision of transmission service under the OATT. Specifically, transmission providers must post (1) The number of affiliate versus non-affiliate requests for transmission service that have been rejected and (2) the number of affiliate versus non- affiliate requests for

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transmission service that have been made. This posting must detail the length of service request (e.g., short-term or long-term) and the type of service requested (e.g., firm point-to-point, non-firm point-to- point or network service). The Commission also will require transmission providers to post their underlying load forecast assumptions for all ATC calculations and, to post on a daily basis, their actual daily peak load for the prior day. The Commission directs transmission providers to work through NAESB to develop standards for consistent methods of posting the new requirements on OASIS.

414. The Commission agrees with PJM and Ameren that affiliate posting requirements do not apply to RTOs and ISOs, since they do not have affiliates to transact with. The Commission also agrees with Entergy that the metrics established for its weekly procurement process are outside the scope of this proceeding.

415. In response to Southern's point that the information necessary to compute the metrics is already available on OASIS, while it is true that service denial information is available on OASIS for long periods, request information is not. As such, a customer would need to continuously download information from OASIS to record the data sufficient to calculate the metrics on its own. The Commission concludes that it is not unduly burdensome for transmission providers to calculate the metrics required by this Final Rule.

416. With regard to posting of load forecasts and actual daily peak load, we conclude that such postings are necessary to provide transparency for transmission customers. We agree with E.ON that RTO and ISO load data needs to be posted at a sufficient granularity to allow for meaningful comparison of control area and LSE load levels. Most RTOs and ISOs post load data for the entire footprint, but few post it on an LSE or control area basis. We therefore direct ISOs and RTOs to post load data for the entire ISO/RTO footprint and for each LSE or control area footprint within the ISO/RTO. This will not create an undue burden on ISOs and RTOs, since the load data for the entire footprint is an aggregation of load data across the LSEs or control areas in the footprint. We also agree with EEI that the peak load applies to system-wide load, including native load. We direct transmission providers to post load forecasts and actual daily peak load for both system-wide load (including native load) and native load, as this data will be useful to customers and regulators. We deny EEI's request for a guarantee that transmission providers will not be held accountable for producing a reasonable load forecast. While we do not intend to penalize transmission providers for failing to account for unforeseen circumstances, we retain our ability to investigate any allegations of manipulation of load forecasts, as this could be used as a means of inappropriately denying requested transmission service.

417. The Commission is not convinced by the views of some commenters that load data has competitive implications. The Commission notes, as PJM pointed out in its comments, that many RTOs have an established practice of posting significant amounts of load data for participants' use, and this data posting has not raised competitive concerns.

B. Coordinated, Open and Transparent Planning

1. The Need for Reform

418. Order No. 888 set forth certain minimum requirements for transmission system planning. For example, Order No. 888 and the pro forma OATT require that transmission providers plan and upgrade their transmission systems to provide comparable open access transmission service for their transmission customers. With regard to network service, section 28.2 of the pro forma OATT provides that the transmission provider ``will plan, construct, operate and maintain its Transmission System in accordance with Good Utility Practice in order to provide the Network Customer with Network Integration Transmission Service over the Transmission Provider's Transmission System.'' Section 28.2 also provides that the Transmission Provider shall, consistent with Good Utility Practice, ``endeavor to construct and place into service sufficient transfer capability to deliver the Network Customer's Network Resources to serve its Network Load on a basis comparable to the Transmission Provider's delivery of its own generating and purchased resources to its Native Load Customers.''

419. The pro forma OATT also requires that new facilities be constructed to meet the service requests of long-term firm point-to- point customers. Section 13.5 of the pro forma OATT requires the transmission provider to consider redispatch of the system to relieve any constraints that are inhibiting a transmission customer's point-to- point service if it is economical to do so; but if redispatch is not economical, the transmission provider is obligated to expand or upgrade its system. This expansion obligation on the part of the transmission provider for point-to-point service is found in section 15.4 of the pro forma OATT, which provides that, when a transmission provider cannot accommodate a request for point-to-point transmission because of insufficient capability on its system, it will ``use due diligence to expand or modify its Transmission System to provide the requested Firm Transmission Service.'' Section 15.4 goes on to provide that ``the Transmission Provider will conform to Good Utility Practice in determining the need for new facilities and in the design and construction of such facilities.'' The transmission provider's obligation to upgrade or expand its system to provide point-to-point service as detailed in section 15.4 is contingent on the transmission customer agreeing to compensate the transmission provider for such costs pursuant to the terms of section 27 (providing for cost responsibility for upgrades and/or redispatch ``to the extent consistent with Commission policy'').

420. In Order No. 888-A, the Commission encouraged utilities to engage in joint planning with other utilities and customers and to allow affected customers to participate in facilities studies to the extent practicable. The Commission also encouraged regional planning so that the needs of all participants are represented in the planning process.\225\ Order No. 888-A did not, however, require that transmission providers coordinate with either their network or point- to-point customers in transmission planning or otherwise publish the criteria, assumptions, or data underlying their transmission plans. The Commission also did not require joint planning between transmission providers and their customers or between transmission providers in a given region.\226\ The only section of the existing pro forma OATT that directly speaks to joint planning is section 30.9, which provides that a network customer must receive credit when facilities constructed by the customer are jointly planned and installed in coordination with the transmission provider.\227\

\225\ See Order No. 888-A at 30,311.

\226\ See id.

\227\ Pro forma OATT section 21.2, ``Coordination of Third-Party System Additions,'' provides for certain rights for transmission providers to coordinate construction of facilities on their systems associated with point-to-point customer requests and related construction on a third-party transmission system, but imposes no obligation on transmission providers.

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421. As the Commission stated in the NOPR, the Nation has witnessed a decline in transmission investment relative to load growth in the ten years since Order No. 888 was issued. Transmission capacity per MW of peak demand has declined in every NERC region. Transmission constraints plague most regions of the country, as reflected in the limited amounts of ATC posted in many regions, increased frequency of denied transmission requests, increasingly common transmission service interruptions or curtailments and rising congestion costs in organized markets.\228\

\228\ The number of TLRs has increased significantly since NERC started reporting annual statistics. The total number of TLRs each year has grown from under 500 in 1998 and 1999 to around 2000 over the last four years from 2002 to 2006. The number of TLR actions at the highest levels, requiring curtailment of firm transmission flows, has also grown, from under 10 before 2001 to 70 in 2006, averaging 55 per year from 2003 to 2006. Source: NERC Web site, ftp://www.nerc.com/pub/sys/all_updl/oc/scs/logs/trends.htm. In

addition, congestion costs continue to be a major issue in RTO markets. For example, congestion costs in PJM were $2.09 billion in calendar year 2005, which was a 179 percent increase over 2004. Although this increase resulted primarily from increases in PJM annual billings, the congestion costs in both years were approximately 9 percent of total PJM billings in both years and have ranged from 6 percent to 10 percent of total billings since 2000. Source: 2005 PJM State of the Markets Report, April 2006.

422. We do not believe that the existing pro forma OATT is sufficient in an era of increasing transmission congestion and the need for significant new transmission investment. We cannot rely on the self-interest of transmission providers to expand the grid in a nondiscriminatory manner. Although many transmission providers have an incentive to expand the grid to meet their State-imposed obligations to serve, they can have a disincentive to remedy transmission congestion when doing so reduces the value of their generation or otherwise stimulates new entry or greater competition in their area. For example, a transmission provider does not have an incentive to relieve local congestion that restricts the output of a competing merchant generator if doing so will make the transmission provider's own generation less competitive. A transmission provider also does not have an incentive to increase the import or export capacity of its transmission system if doing so would allow cheaper power to displace its higher cost generation or otherwise make new entry more profitable by facilitating exports.

423. As the Commission explained in Order No. 888, ``[i]t is in the economic self-interest of transmission monopolists, particularly those with high-cost generation assets, to deny transmission or to offer transmission on a basis that is inferior to that which they provide themselves.'' \229\ The court agreed on review of Order No. 888, noting in TAPS v. FERC that ``[u]tilities that own or control transmission facilities naturally wish to maximize profit. The transmission-owning utilities thus can be expected to act in their own interest to maintain their monopoly and to use that position to retain or expand the market share for their own generated electricity, even if they do so at the expense of lower-cost generation companies and consumers.'' \230\ The Supreme Court in New York v. FERC similarly explained that ``public utilities retain ownership of the transmission lines that must be used by their competitors to deliver electric energy to wholesale and retail customers. The utilities' control of transmission facilities gives them the power either to refuse to deliver energy produced by competitors or to deliver competitors' power on terms and conditions less favorable than those they apply to their own transmissions.'' \231\

\229\ Order No. 888 at 31,682.

\230\ 225 F.3d at 684.

\231\ 535 U.S. at 8-9 (citation and footnotes omitted).

424. The existing pro forma OATT does not counteract these incentives in the planning area because there are no clear criteria regarding the transmission provider's planning obligation. Although the pro forma OATT contains a general obligation to plan for the needs of their network customers and to expand their systems to provide service to point-to-point customers, there is no requirement that the overall transmission planning process be open to customers, competitors, and State commissions.\232\ Rather, transmission providers may develop transmission plans with limited or no input from customers or other stakeholders. There also is no requirement that the key assumptions and data that underlie transmission plans be made available to customers.

\232\ As discussed in more detail in the NOPR, the need for reform was recognized by the Consumer Energy Council of America (CECA), a public interest energy policy organization with a 30-year history of bringing stakeholders together to find solutions to contentious energy policy issues. CECA launched its Transmission Infrastructure Forum in early 2004, which published its conclusions in January 2005 in a final report titled ``Keeping the Power Flowing: Ensuring a Strong Transmission System to Support Consumer Needs for Cost-Effectiveness, Security and Reliability'' (CECA Report). Among other things, the CECA Report concludes that regional transmission planning with consumer input early in the process is needed to ensure the development of a robust transmission system capable of meeting consumer needs reliably and at reasonable cost over time. The CECA Report stresses that regional transmission planning must address inter-regional coordination, the need for both reliability and economic upgrades to the system, and critical infrastructure to support national security and environmental concerns. See NOPR at P 207.

425. Taken together, this lack of coordination, openness, and transparency results in opportunities for undue discrimination in transmission planning. Without adequate coordination and open participation, market participants have no means to determine whether the plan developed by the transmission provider in isolation is unduly discriminatory. This means that disputes over access and discrimination occur primarily after-the-fact because there is insufficient coordination and transparency between transmission providers and their customers for purposes of planning.\233\ The Commission has a duty to prevent undue discrimination in the rates, terms, and conditions of public utility transmission service and, therefore, an obligation to remedy these transmission planning deficiencies. As we explain above, our authority to remedy undue discrimination is broad.\234\ In addition, new section 217 of the FPA requires the Commission to exercise its jurisdiction in a manner that facilitates the planning and expansion of transmission facilities to meet the reasonable needs of LSEs. A more transparent and coordinated regional planning process will further these priorities, as well as support the DOE's responsibilities under EPAct 2005 section 1221 to study transmission congestion and issue reports designating National Interest Electric Transmission Corridors and the Commission's responsibilities under EPAct 2005 section 1223.

\233\ In our discussion of enforcement issues at section V.E of this Final Rule, we note specific situations in which transmission providers have agreed to resolve staff allegations that they engaged in OATT violations involving transactions with affiliates. While these specific situations may not directly relate to discrimination in planning, they nevertheless document the continuing incentive of transmission providers to favor themselves and their affiliates in the provision of transmission service.

\234\ See Order No. 888 at 31,669 (noting that the FPA ``fairly bristles'' with concern for undue discrimination (citing AGD, 824 F.2d at 998).

NOPR Proposal

426. In order to provide for more comparable open access transmission service, limit the potential for undue discrimination and anticompetitive conduct, and satisfy its statutory responsibilities under section 217 of the FPA, the Commission proposed to amend the pro forma OATT to require coordinated, open, and transparent transmission planning on both a local and regional level. Each public utility

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transmission provider would be required to submit, as part of its compliance filing in this proceeding, a proposal for a coordinated and regional planning process that complies with the following eight planning principles: Coordination, openness, transparency, information exchange, comparability, dispute resolution, regional participation, and congestion studies. In the alternative, transmission providers could make a compliance filing in this proceeding describing their existing coordinated and regional planning processes and showing that they are consistent with or superior to that required in the Final Rule.

427. The Commission stated that it expected non-public utility transmission providers to participate in the proposed planning processes, given that effective regional planning cannot occur without the participation of all transmission providers, owners, and customers. Although the Commission encouraged the use of an independent third party to oversee or coordinate the planning process, the NOPR did not propose to require it. The Commission also strongly encouraged the participation of State commissions and other State agencies in planning activities.

428. The Commission sought comment on several aspects of the NOPR proposal. First, the Commission inquired as to the level of flexibility each transmission provider should be given in implementing any principles adopted. Second, the Commission sought comment, by way of example, on transmission planning processes that comply with the NOPR reforms in principle. Third, the Commission sought comment on whether there are other principles or requirements that should be adopted to support the construction of needed new infrastructure and otherwise ensure that all market participants are treated on a comparable basis. Specifically, the Commission inquired: (a) Whether there should be a principle or guideline to govern the recovery and allocation of costs associated with funding the regional planning requirement; (b) whether there should be a requirement that, at least for large new transmission projects, there be an open season to allow market participants to participate in joint ownership of these projects; (c) whether there should be a specific study process to identify opportunities to enhance the grid for purposes beyond maintaining reliability or reducing current congestion; and, (d) whether public utilities should be required to develop cost allocation principles to address the sharing of the costs of new transmission projects and, given that such projects can take years to construct, whether the planning process should be required to look out at least as far as the longest time it would take to build such an upgrade in the region in question. Finally, the Commission sought comment on the level of detail to be required in transmission providers' OATTs. Comments

429. Most commenters support the development of coordinated, open, and transparent planning. While differing on how they should be implemented, commenters express broad support for the eight planning principles,\235\ though all RTOs and ISOs and many investor-owned utilities believe that their planning processes already comply with the proposals in the NOPR. ISO/RTO Council, as well as individual RTOs and ISOs, advance the position that RTOs and ISOs already meet the planning requirements in the NOPR, that there has been no credible case made for reopening their already approved planning processes, and that RTOs and ISOs should be exempt from complying with the NOPR's planning principles.

\235\ The one exception is the congestion studies requirement, which is generally opposed by transmission providers and supported by customers.

430. Some transmission providers agree that RTOs already meet the principles, and others argue against commenters who maintain that RTOs ``rubber stamp'' transmission provider plans.\236\ For example, MISO asserts that it conducts an open planning process and does not ``rubber stamp'' projects. Duke concurs with MISO, stating that there are abundant opportunities for participation in the MISO planning process. Xcel also replies in support of the MISO process.

\236\ E.g., Duke, Exelon, and Xcel.

431. Several transmission customers, however, argue that current RTO processes are insufficient because, among other things, they merely accept the transmission owners' plans and only provide for after-the- fact input, thus failing to satisfy the planning principles proposed in the NOPR.\237\ Old Dominion also asserts that RTOs generally approve transmission owner identified upgrades, which give them the advantage of having their own parochial plans incorporated into the regional plan without any separate evaluation or complete stakeholder input. TAPS asserts that open planning should apply both to the RTO and the underlying transmission owners' planning efforts. In its reply, WPS opposes MISO's proposal to be exempt from the NOPR's planning requirements, arguing that the MISO process is not open and only aggregates the plans of the transmission providers.

\237\ E.g., Indicated Parties Reply, Old Dominion, NRECA, and TAPS.

432. EEI takes issue with broad statements in the NOPR that assert that transmission providers have a disincentive to remedy transmission congestion and to plan their transmission systems on a comparable basis. Other individual investor-owned utilities also assert that the record does not support the NOPR's claims that a mandatory coordinated, open, and transparent planning process is necessary to remedy undue discrimination.\238\ Many others, however, believe the NOPR correctly diagnoses the problem of discrimination.\239\

\238\ See, e.g., Duke and Southern.

\239\ See, e.g., APPA and EPSA. However, NRG and Reliant believe that the planning process outside of RTOs is fundamentally flawed and cannot be remedied by the NOPR's planning proposal.

433. Most commenters do not question the Commission's jurisdiction to address the transmission planning process generally. Southern, however, argues that the Commission has no general authority in this area and that section 217 of the FPA does not grant the Commission any additional jurisdiction to impose a regional planning requirement.\240\ FMPA counters that the Commission has FPA authority to cure undue discrimination and to ensure ``just and reasonable'' transmission rates and terms by adopting transmission planning criteria.\241\ In their replies, APPA and TAPS agree with the Commission that FPA section 217(b)(4) can be cited as legal support for transmission planning. In its reply, NRECA stresses that the transmission planning process must focus, consistent with FPA section 217(b)(4), on the reasonable long- term needs of LSEs, not all users of the system as argued by EPSA and NRG. Santee Cooper urges the Commission to be mindful of the limits of its jurisdiction in establishing study requirements that may delve into generation resource adequacy or issues related to the mix of generation. Other commenters urge the Commission not to impinge on State jurisdiction.\242\ In its reply, LPPC emphasizes that the Commission's expectation that public power entities will participate is

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sufficient and asserts that there is no reason to take further action that might test the limits of jurisdiction under FPA section 211A.\243\

\240\ Progress Energy also claims that the Commission does not have any jurisdiction to mandate regional planning.

\241\ See also TAPS Reply.

\242\ See, e.g., Nevada Companies, New Mexico Attorney General, North Carolina Commission Reply, and Southern.

\243\ Other jurisdictional arguments primarily relate to the question of joint ownership, in which some commenters argue that the Commission lacks jurisdiction to mandate joint ownership arrangements. See, e.g., Duke, EEI, National Grid, Northeast Utilities, PSEG, and Southern. FMPA and others, however, argue that the Commission does have the authority to order joint ownership. Joint ownership will be discussed more fully below.

434. WIRES endorses several planning objectives it believes to be critical to successful planning. These objectives include open and transparent planning procedures, a long-term planning horizon, broad- based inclusion of reliability, economic, efficiency and environmental considerations in planning, clear conditions under which a transmission owner will commit to build planned facilities, and provision for fair and efficient allocation of the costs of planned facilities. WIRES also emphasizes the importance of considering non-transmission alternatives, arguing that an appropriate grid plan must be based on an integrated view of all alternatives, including demand response and distributed generation. Commission Determination

435. In order to limit the opportunities for undue discrimination described above and in the NOPR, and to ensure that comparable transmission service is provided by all public utility transmission providers, including RTOs and ISOs, the Commission concludes that it is necessary to amend the existing pro forma OATT to require coordinated, open, and transparent transmission planning on both a local and regional level. We disagree with commenters arguing either that we lack jurisdiction to require coordinated transmission planning or that we have not established a basis for such a requirement. The Commission has broad authority to remedy undue discrimination by ensuring that transmission providers plan for the needs of their customers on a comparable basis.\244\ That fundamental requirement was adopted in Order No. 888 and the reforms adopted herein should ensure that it will be implemented properly. Further, we explained in detail above why undue discrimination remains a concern in the planning area and why the existing OATT is insufficient to address that concern.

\244\ See AGD, 824 F.2d at 1008 (Commission has broad discretion to promulgate generic rules to eliminate undue discrimination without ``conduct[ing] experiments in order to rely on the prediction that an unsupported stone will fall'').

436. New section 217 of the FPA further supports reform in this area, as it reflects Congress' intent that the Commission utilize its powers to facilitate the planning and expansion of the transmission system.\245\ Through EPAct 2005 sec. 1223, Congress also directed the Commission to encourage the deployment of advanced transmission technologies in infrastructure improvements, including among others optimized transmission line configurations (including multiple phased transmission lines), controllable load, distributed generation (including PV, fuel cells, and microturbines), and enhanced power device monitoring.

\245\ FPA section 217(b)(4) provides that ``[t]he Commission shall exercise the authority of the Commission under [the FPA] in a manner that facilitates the planning and expansion of transmission facilities to meet the reasonable needs of load-serving entities to satisfy the service obligations of the load-serving entities, and enables load-serving entities to secure firm transmission rights (or equivalent tradable or financial rights) on a long term basis for long term power supply arrangements made, or planned, to meet such needs.''

437. Accordingly, each public utility transmission provider is required to submit, as part of a compliance filing in this proceeding, a proposal for a coordinated and regional planning process that complies with the planning principles and other requirements in this Final Rule.\246\ In the alternative, a transmission provider (including an RTO or an ISO, as discussed below), may make a compliance filing in this proceeding describing its existing coordinated and regional planning process, including the appropriate language in its tariff, and show that this existing process is consistent with or superior to the requirements in this Final Rule. Under either of these approaches, the process must be documented as an attachment to the transmission provider's OATT.

\246\ The pro forma OATT, as modified by this Final Rule, reflects the proposed planning requirement in sections 15.4, 16.1, 17.2(x), 28.2, 29.2, 31.6. The planning process itself will be included as Attachment K to the pro forma OATT. We understand that some transmission providers may already have attachments to their OATTs labeled with the letter ``K,'' in which case transmission providers are free to label their planning process OATT attachment with the next available letter.

438. At the outset, we note that the planning obligations imposed in this Final Rule do not address or dictate which investments identified in a transmission plan should be undertaken by transmission providers. Furthermore, except for the discussion below of cost allocation for transmission investments under Principle 9, the planning obligations included in this Final Rule do not address whether or how investments identified in a transmission plan should be compensated. Through the principles described below, we establish a process through which transmission providers must coordinate with customers, neighboring transmission providers, affected State authorities, and other stakeholders in order to ensure that transmission plans are not developed in an unduly discriminatory manner.

439. As for the application of the Final Rule's coordinated planning requirement to RTOs and ISOs, which already have a Commission- approved transmission planning process on file with us, we note that the intent of our reform in this Final Rule is not to reopen prior approvals, but rather to ensure that the transmission planning process utilized by each RTO and ISO is consistent with or superior to the planning process adopted here. When the Commission approved the existing RTO and ISO transmission planning processes, they were found to be consistent with or superior to the existing pro forma OATT. Because the pro forma OATT is being reformed by this Final Rule, it is necessary for each RTO and ISO to now either reform its process or show that its planning process is consistent with or superior to the pro forma OATT, as modified by the Final Rule.

440. We also make clear that transmission owning members of ISOs and RTOs must participate in the planning processes adopted in this Final Rule. In order for an RTO's or ISO's planning process to be open and transparent, transmission customers and stakeholders must be able to participate in each underlying transmission owner's planning process. This is important because, in many cases, RTO planning processes may focus principally on regional problems and solutions, not local planning issues that may be addressed by individual transmission owners. These local planning issues, however, may be critically important to transmission customers, such as those embedded within the service areas of individual transmission owners. Consequently, the intent of the Final Rule will not be realized if only the regional planning process conducted by the RTOs and ISOs is shown to be consistent with or superior to the Final Rule. To ensure full compliance, individual transmission owners must, to the extent that they perform transmission planning within an RTO or ISO, comply with the Final Rule as well. Without such a requirement, the more regional RTO or

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ISO planning process will not comply with the requirements of the Final Rule to the extent they incorporate and rely on information prepared by underlying transmission owners that, in turn, have not complied with the Final Rule. Accordingly, as part of their compliance filings in this proceeding, RTOs and ISOs must indicate how all participating transmission owners within their footprint will comply with the planning requirements of this Final Rule. While we leave the mechanics of such compliance to each RTO and ISO, we emphasize that the RTO's or ISO's planning processes will be insufficient if its underlying transmission owners are not also obligated to engage in transmission planning that complies with Final Rule.\247\

\247\ We understand that there are some transmission owners in RTOs or ISOs that continue to have OATTs on file under which they provide service over certain transmission facilities that they did not turn over to the operational control of the RTO or ISO. Like any other transmission provider, those entities must submit a compliance filing to their OATTs that satisfies all requirements of this Final Rule, including the inclusion of an attachment governing their own planning procedures. As we explain elsewhere, the compliance filing deadline for transmission owning participants in RTOs and ISOs shall be the same as the RTO and ISO deadline, i.e., 210 days after publication of the Final Rule in the Federal Register.

441. The Commission also expects all non-public utility transmission providers to participate in the planning processes required by this Final Rule. A coordinated, open, and transparent regional planning process cannot succeed unless all transmission owners participate. We are encouraged, based on the representations of LPPC and others, that non-public utility transmission providers will fully participate in such processes. We therefore do not believe it is necessary at this time to invoke our authority under FPA section 211A, which gives us authority to require non-public utility transmission providers to provide transmission services on a comparable and not unduly discriminatory or preferential basis.\248\ If we find on the appropriate record, however, that non-public utility transmission providers are not participating in the planning processes required by this Final Rule, the Commission may exercise its authority under section 211A on a case-by-case basis. Further, we note that reciprocity dictates that non-public utility transmission providers that take advantage of open access due to improved planning should be subject to the same requirements as jurisdictional transmission providers.

\248\ FPA section 211A(b) provides, in pertinent part, that ``the Commission may, by rule or order, require an unregulated transmitting utility to provide transmission services--(1) At rates that are comparable to those that the unregulated transmitting utility charges itself; and (2) on terms and conditions (not relating to rates) that are comparable to those under which the unregulated transmitting utility provides transmission services to itself and that are not unduly discriminatory or preferential.'' The non-public utility transmission providers referred to in this Final Rule include unregulated transmitting utilities that are subject to FPA section 211A.

442. In sum, each OATT planning process attachment must incorporate the transmission planning principles and concepts in this Final Rule and must be filed with the Commission within 210 days after the publication of the Final Rule in the Federal Register. Alternatively, RTOs, ISOs, and other transmission providers that currently have planning processes they believe comply with the Final Rule may make a filing with the Commission documenting those processes in an OATT attachment and explaining how their planning processes are consistent with or superior to the planning process adopted here. Such filings must also be submitted within 210 days after the publication of the Final Rule in the Federal Register.

443. In order to assist transmission providers in complying with the Final Rule, and ensure that the planning procedures are developed with customer and stakeholder participation, the Commission will convene staff technical conferences in several broad regions around the country to discuss regional implementation and other compliance issues in advance of the compliance date. We extend an invitation to State regulatory commissions to participate in these technical conferences with our staff in order to ensure that State concerns are fully addressed. The Commission will endeavor to hold the technical conferences 90 to 120 days after the publication of the Final Rule in the Federal Register. To facilitate these conferences, each transmission provider should, within 75 days after the publication of the Final Rule in the Federal Register, post a ``strawman'' proposal for compliance with each of the planning principles adopted in the Final Rule, including a specification of the broader region in which it will conduct coordinated regional planning. This strawman may be posted on the transmission provider's OASIS, or its Web site if it does not have its own OASIS (e.g., in the case of a transmission owning member of an RTO or ISO that does not have its own OATT). We strongly urge transmission providers to consult with their stakeholders in the development of this strawman. 2. Planning Principles

444. We set forth below the planning principles that must be satisfied for a transmission provider's planning process to be considered compliant with the Final Rule. The NOPR identified eight such principles, but based on the comments received the Commission will require compliance with nine--the original eight plus a cost allocation principle, as described further below. a. Coordination

445. In the NOPR, the Commission proposed that transmission providers must meet with all of their transmission customers and interconnected neighbors to develop a transmission plan on a nondiscriminatory basis. We sought comment on specific requirements for this coordination, such as the minimum number of meetings to be required each year, the scope of the meetings, the notice requirements, the format, and any other features deemed important by commenters. Comments

446. Commenters express universal support for the general concept of coordination, but differ on how specific the requirement should be. Several commenters argue that the requirement that transmission providers ``must meet'' with customers and utilities is unrealistic.\249\ EEI requests that the Commission clarify that transmission providers will be responsible for coordinating with customers and holding meetings, but that the requirement to meet should be limited to making reasonable efforts to meet with all customers. NRECA asks on reply that the Commission make clear that the lack of full participation by some nonjurisdictional utilities that take network service under the OATT should not excuse the transmission provider's obligation to engage in transmission planning. NRECA states that inclusion in the planning process must be an opportunity for LSEs, not an obligation.

\249\ E.g., Allegheny, Duke, EEI, International Transmission, MidAmerican, NorthWestern, and SCE.

447. Other commenters express a more general concern that the Commission not be prescriptive with respect to meeting requirements.\250\ For example, most commenters generally believe the Commission should not prescribe rigid rules regarding the number of meetings that must be held

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each year. Xcel, however, suggests that a minimum of three meetings a year would be appropriate. Progress notes that coordination in North Carolina already occurs as a result of regular meetings throughout the year. Nevada Companies believe that meetings should be dependent on need and should not be programmatically established. TDU Systems recommend at least monthly meetings, but stress that meetings should be as frequent as is required to specify and perform the studies forming the basis for the plan. NCPA believes that the minimum requirements are not as important as how they can be monitored or enforced to ensure that true participation indeed occurs.

\250\ E.g., Allegheny, APPA, Bonneville, California Commission, Duke, Entergy, Imperial, International Transmission, MidAmerican, NCEMC, NC Transmission Planning Participants Reply, NorthWestern, NRECA, Pinnacle, Progress Energy, CREPC, Santee Cooper, SCE, TVA, and WAPA.

448. Seattle suggests 30 days notice for meetings and that information regarding meetings be posted at least one week in advance. Entergy finds a notice requirement reasonable, and other utilities suggest a 30-day requirement would be appropriate.\251\ Seattle also suggests e-mail notification and Salt River supports internet posting. With respect to details beyond frequency and notice, Entergy cautions the Commission against being too prescriptive.

\251\ E.g., Nevada Companies and NorthWestern.

449. On meeting scope, several commenters request that the Commission make clear that the purpose of the meeting is to focus on transmission issues and not provide a broad forum for other issues.\252\ Sacramento believes that meetings should be limited to sub-regional or regional transmission planning and not include planning to meet local transmission needs.

\252\ E.g., Entergy, Progress Energy, SCE, and Southern.

450. Other commenters stress that joint planning requires more than just meeting with customers and that all LSEs need to be integrated into the planning process so that they are actively developing transmission plans alongside transmission providers from the inception.\253\ This concept of collaborative planning is a running theme in the comments provided by several public power entities, such as NRECA, TAPS, and TDU Systems. TDU Systems argue that comparability requires that LSEs have equal weight in decision-making rather than provide de facto veto authority to transmission providers. NRECA argues in its reply that collaborative planning is required by FPA section 217(b)(4). These commenters assert that LSEs must be able to participate in the development of planning models, including the assumptions and criteria that go into these models, and in the development of the base case and change case for study purposes, particularly as to the identification and projection of loads and resources.\254\ Progress and Southern, however, argue in replies that giving customers equal weight in decision-making crosses the line from planning to control by third parties, and Southern believes this would be opposed by State regulators.

\253\ E.g., NRECA, Seminole Reply, TAPS, and TDU Systems.

\254\ This collaborative approach is also generally supported by East Texas Cooperatives, FMPA, NCEMC, NCPA, and Old Dominion. NCEMC believes that the key to ensuring true collaboration is a voting structure, like that adopted in the North Carolina Transmission Planning Collaborative, which gives all load-serving entities an equal say in planning decisions. APPA also believes that giving customers a say in the outcome (e.g., through voting) is critical.

Commission Determination

451. The Commission adopts the coordination principle proposed in the NOPR. Commenters overwhelmingly desire flexibility as to the coordination principle, and as such, we will not prescribe the requirements for coordination, such as the minimum number of meetings to be required each year, the scope of the meetings, the notice requirements, the format, and any other features. We will allow transmission providers, with the input of their customers and other stakeholders, to craft coordination requirements that work for those transmission providers and their customers and other stakeholders.

452. We emphasize that the purpose of the coordination requirement is to eliminate the potential for undue discrimination in planning by opening appropriate lines of communication between transmission providers, their transmission-providing neighbors, affected State authorities, customers, and other stakeholders. Rigid and formal meeting procedures may be one way to accomplish this goal, but there may be other ways as well. For example, a transmission provider could meet this requirement by facilitating the formation of a permanent planning committee made up of itself, its neighboring transmission providers, affected State authorities, customers, and other stakeholders. Such a planning committee could develop its own means of communication, which may or may not emphasize formal meeting procedures. We are more concerned with the substance of coordination than its form.

453. In response to the concerns of some commenters, we clarify that transmission providers are not required to meet with customers and other stakeholders that choose not to meet. Transmission providers cannot force others to meet with them. Transmission providers are, however, required to craft a process that allows for a reasonable and meaningful opportunity to meet or otherwise interact meaningfully. We also clarify that the coordination requirements imposed in this Final Rule are intended to address transmission planning issues, and are not intended to provide a forum for ancillary issues, such as specific siting concerns, which are better addressed elsewhere. As for NRECA's concern that transmission providers must plan for their nonjurisdictional network customers even if they decline to fully participate in the planning process, a transmission provider cannot be expected to effectively plan for a customer if that customer declines to engage in the planning process. Therefore, we encourage NRECA and non-public utilities to participate fully in the planning process.

454. In response to the suggestion by some commenters that we require transmission providers to allow customers to collaboratively develop transmission plans with transmission providers on a co-equal basis, we clarify that transmission planning is the tariff obligation of each transmission provider, and the pro forma OATT planning process adopted in this Final Rule is the means to see that it is carried out in a coordinated, open, and transparent manner, in order to ensure that customers are treated comparably. Therefore, the ultimate responsibility for planning remains with transmission providers. With this said, we fully intend that the planning process adopted herein provide for the timely and meaningful input and participation of customers into the development of transmission plans. This means that customers must be included at the early stages of the development of the transmission plan and not merely given an opportunity to comment on transmission plans that were developed in the first instance without their input. b. Openness

455. In the NOPR, the Commission proposed that transmission planning meetings must be open to all affected parties (including all transmission and interconnection customers and State authorities). The Commission also sought comment on whether there are any circumstances under which participation should be limited, for example, to address confidentiality concerns.

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Comments

456. Commenters generally agree on the need to meet with all affected parties, as well as the need to limit some meetings for security or confidentiality reasons. Certain commenters urge the Commission to make clear that openness does not extend to a requirement to meet with the general public and that the meetings are for ``industry and governmental representatives'' only.\255\ For example, Southern agrees that eligible transmission customers and State commissions should be allowed to participate in the meetings, but states that these meetings should not be open to the general public to help ensure that the focus is on core transmission planning and not be diverted to other issues.

\255\ E.g., APPA, EEI, Salt River, and Southern.

457. Transmission providers generally note that some meetings will need to be limited for CEII concerns or for discussion of commercially- sensitive information.\256\ Progress Energy states the Commission should be flexible regarding the composition of meetings and openness, noting that in North Carolina meetings involving CEII are limited to transmission personnel and non-marketing personnel of participating LSEs, while other meetings in the North Carolina process are open to the public. In their reply, NC Transmission Planning Participants note that they have been able to negotiate confidentiality protocols agreeable to each of them. Duke believes that restrictions on open meetings need to be in place when sensitive commercial information is being discussed, so that personnel engaged in the merchant function do not gain access to sensitive information about their competitors. Indianapolis Power recommends the Commission keep existing restrictions on access to planning meetings in place to preserve current protections on security and competitive information. TVA states that it is particularly concerned with maintaining confidentially and asks the Commission to defer to NERC and its Regional Entities, which TVA says are developing procedures for planning.

\256\ Other commenters also recognize the need to maintain confidentiality for CEII and commercially-sensitive information. E.g., Arkansas Commission, AWEA, California Commission, NCPA, NRECA, CREPC, Seattle, TDU Systems, and WAPA.

458. Commenters also raise issues regarding the application of the Commission's Standards of Conduct to those that participate in planning meetings.\257\ EEI, for example, believes that if information is disclosed during a planning meeting and is not simultaneously made public, then all planning participants--including nonjurisdictional entities--should be subject to the Commission's Standards of Conduct. APPA understands the need to ensure that non-public information obtained during planning meetings is not utilized to gain an unfair advantage in the power market; however, it believes that other means short of the application of the Standards of Conduct would suffice, such as requiring simultaneous disclosure of information as a ``safe harbor'' or the use of confidentiality agreements.\258\

459. NRECA and TDU Systems argue that meetings should be open and, joined by APPA, suggest that confidentiality issues can be managed with confidentiality agreements and other arrangements (such as password protected access to information). TAPS suggests that access to data be limited to transmission dependent utility employees not involved in marketing or to an outside consultant. California Commission stresses that any advisory subcommittees must also be open to all stakeholders.

\257\ Commenters raise issues with regard to the application of the Commission's Standards of Conduct to planning participants in their comments addressing some of the other principles as well, which will be discussed below, as well as addressed in the pending rulemaking in Docket No. RM07-1-000. See Standards of Conduct NOPR.

\258\ See also East Texas Cooperatives Reply and NRECA Reply.

Commission Determination

460. The Commission adopts the NOPR's proposal and will require that transmission planning meetings be open to all affected parties including, but not limited to, all transmission and interconnection customers, State commissions and other stakeholders. We recognize that it may be appropriate in certain circumstances, such as a particular meeting of a subregional group, to limit participation to a relevant subset of these entities. We emphasize, however, that the overall development of the transmission plan and the planning process must remain open. We agree with the concerns of some commenters that safeguards must be put in place to ensure that confidentiality and CEII concerns are adequately addressed in transmission planning activities. Accordingly, we will require that transmission providers, in consultation with affected parties, develop mechanisms, such as confidentiality agreements and password-protected access to information, in order to manage confidentiality and CEII concerns. Lastly, concerns surrounding the application of the Commission's Standards of Conduct to planning participants, and whether and how these standards should affect access to and use of information obtained in the planning process, will be discussed below. c. Transparency

461. In the NOPR, the Commission proposed that transmission providers be required to disclose to all customers and other stakeholders the basic criteria, assumptions, and data that underlie their transmission system plans. The Commission also sought comment on whether the information provided in FERC Form 715 (Form 715) is adequate and, if not, what additional detail should be provided. In addition, the Commission sought comment on the format for disclosure, including protections to address confidentiality concerns. Comments

462. Transmission providers generally agree that they should provide the basic criteria, assumptions, and data for planning, but argue that non-public utility transmission providers should also be required to provide comparable information.\259\ In general, EEI believes that information provided during the planning process should be treated as confidential and not disclosed to the general public.

\259\ E.g., CAISO, EEI, and SCE.

463. Public power entities and other commenters support transparency and also are sensitive to confidentiality concerns.\260\ NCPA believes that the failure of CAISO to release planning data is one of the biggest failings of CAISO planning process. Without access to criteria, assumptions, and data inputs, NCPA argues that customers cannot duplicate planning results, nor can they independently determine whether the assumptions are correct, whether the model is producing the right results, whether those results are being fairly applied in the choice of projects to be undertaken, or assess the impacts on their own customers. APPA suggests that transmission providers be required to reduce to writing the methodology, criteria, and processes they use to develop their transmission plans, including how they treat retail native loads, in order to ensure that standards are consistently applied.

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CREPC points out that transparency is necessary if State regulatory processes are to give deference to planning results. Sacramento asserts that it may be reasonable to allow customers and stakeholders access to the planning model or at least allow access to a comprehensive description of the model and methodology, in order to allow others to closely replicate the planning analysis. Sacramento is joined by Imperial in referencing WECC's on-going effort to increase planning transparency.

\260\ E.g., APPA, California Commission, NCPA, CREPC, Salt River, and WAPA. Old Dominion, however, does not believe that any of the data required to be disclosed is commercially-sensitive; however, it does recognize that it may be CEII, in which case it claims security can be maintained via a secure OASIS site.

464. NRECA and TDU Systems, however, do not believe that a specific disclosure principle would be necessary if LSEs were truly integrated into the planning process. In other words, they argue that if the process is truly open, then LSEs, as participants in the development of the joint plan, should already have access to the inputs and assumptions underlying the plans and, in fact, should have helped develop them.

465. EEI believes that Standards of Conduct requirements should be placed on all participants in the planning process whenever disclosure of commercially-sensitive information is needed for planning. East Texas Cooperatives argues that the Standards of Conduct should not be generically applied to public power and that such issues should be managed with confidentiality agreements and case-by-case protective orders. In its reply, NRECA also asserts that, while it is necessary to protect competitively-sensitive information, there is no basis for requiring nonjurisdictional entities to comply with the formal separation of functions requirements simply because they have received information in the planning process, as this is inconsistent with the cooperative utility business model. Rather, NRECA believes commercially-sensitive information can be handled in other established ways. APPA also suggests that Standards of Conduct issues can be managed by providing for certain ``safe harbors'' for participation, such as simultaneous disclosure of information or the use of an independent facilitator.\261\

\261\ NARUC asks the Commission to re-examine the need for its Standards of Conduct rules concerning communications between resource and transmission planners in light of the mitigation provided by the open planning processes proposed in the NOPR.

466. Commenters express a range of views on the information found in Form 715. MidAmerican believes Form 715 to be more than adequate and recommends shortening or eliminating it. Other investor-owned utilities find Form 715 to be generally sufficient.\262\ Others believe the information in Form 715, as currently supplemented by other information in the planning process, is adequate.\263\ Duke and WAPA contend that Form 715 does not contain sufficient information for transmission planning, but believe that disclosure of further details should be left to stakeholders. According to NorthWestern, Form 715 contains the basic data, but may not always provide the needed information.

\262\ E.g., Indianapolis Power, Southern, and Xcel.

\263\ E.g., Allegheny (with data from PJM) and Nevada Companies (with data from WECC).

467. ISO/RTO Council believes that Form 715 data are generally inadequate for planning studies, but urges the Commission not to attempt to develop ``standardized forms'' for these and other types of data. CAISO also cautions against adopting a standardized form for the collection of necessary information, because standardized forms do not necessarily provide the information needed by individual providers.

468. A number of other commenters believe that Form 715 information is insufficient.\264\ APPA and TAPS point out that Form 715 does not include all the information needed to perform a load flow study, including information on economic dispatch and interchange, and also that Form 715 information is out of date when filed. Seattle notes that typical sub-regional planning processes go into significantly greater detail than Form 715 and argues that Form 715 is primarily a reliability-focused report that seldom delves into economic analysis of congestion and transmission options that mitigate congestion.

\264\ E.g., APPA, California Commission, NCPA, CREPC, Seattle, TAPS, and TDU Systems. California Commission and CREPC also point out that the load forecast information presently used in planning in the Western Interconnection is likewise insufficient.

469. Several commenters contend that transparency in the planning process is of particular interest to demand resources. New Jersey Board suggests that each transmission provider's planning process analyze whether demand resources or other solutions could be considered as an alternative or a component of new transmission lines or upgrades. New Jersey Board states that this analysis should include both supply-side and demand-side measures such as load management, new building codes and energy efficiency standards, the use of distributive renewable energy systems, and renewable portfolio standards. Ohio Power Siting Board argues that an open, transparent, and inclusive regional planning process should include distributed generation, demand response, and new technology as part of the mix of available options for incremental or interim congestion relief until longer term solutions can be developed and constructed. Fayetteville notes its general support for a SEARUC joint planning proposal, which includes a principle that would require the integration of demand response in planning. WIRES likewise argues that an appropriate grid plan should be based on an integrated view of all alternatives, including demand response and distributed generation. PJM, Midwest ISO, and ISO New England emphasize that their planning processes already provide for the evaluation and integration of demand response resources.\265\ Other commenters, such as Alcoa and Steel Manufacturer's Association, suggest that demand response resources be considered as substitutes for certain ancillary services.

\265\ See also ISO/RTO Council.

470. In response to its notice convening the October 12 Technical Conference, the Commission received several comments addressing the role of demand response in planning. Participants in the technical conference generally responded that demand response programs are considered in planning, particularly in the load forecasts. Some observed that demand response has often been difficult to incorporate in long-term plans when it is not dispatchable and only available in one-year increments. Participants stressed that transmission providers must have control over a resource throughout the planning horizon if they are to rely on that resource in lieu of constructing upgrades. Some participants reported that this capability is available from several forms of demand response resources. Commission Determination

471. The Commission adopts the NOPR's proposal and will require transmission providers to disclose to all customers and other stakeholders the basic criteria, assumptions, and data that underlie their transmission system plans.\266\ In addition, transmission

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providers will be required to reduce to writing and make available the basic methodology, criteria, and processes they use to develop their transmission plans, including how they treat retail native loads, in order to ensure that standards are consistently applied. This information should enable customers, other stakeholders, or an independent third party to replicate the results of planning studies and thereby reduce the incidence of after-the-fact disputes regarding whether planning has been conducted in an unduly discriminatory fashion. We note, however, that transmission providers cannot be expected to fulfill these planning obligations unless non-public utility transmission providers that participate in the planning process make similar information available and, for the reasons set forth above, we fully expect that they will do so. We believe that the same safeguards developed as discussed above regarding the openness principle, such as confidentiality agreements and password protected access to information, will adequately protect against inappropriate disclosure of confidential information or CEII.

\266\ Much of the information should be available to those engaged in transmission planning already under reliability Standards TPL-001-0 through TPL-004-0 proposed in Docket RM06-16-000. See the Reliability Standards NOPR. These standards set out detailed requirements for annual studies to assess the performance of the transmission system and require conducting simulation studies over a five-year time horizon, with additional studies as needed for the six to ten-year horizon. The Commission proposed that planning entities conduct ``studies to bracket the range of probable outcomes,'' examining system operation under variations in demand levels, existing and planned facilities, reactive power resources, generation dispatch and transaction patterns, controllable loads and demand-side management, and other factors. Id. at P 1047. While we recognize that OATT planning is distinct from these proposed reliability planning standards, we expect that the key data underlying transmission planning will be provided in conjunction with reliability standards and thus should be available for transmission planning when those standards are finalized.

472. The Commission also requires that transmission providers make available information regarding the status of upgrades identified in their transmission plans in addition to the underlying plans and related studies. It is important that the Commission, stakeholders, neighboring transmission providers, and affected State authorities have ready access to this information in order to facilitate coordination and oversight. To the extent any such information is confidential or consists of CEII, the transmission provider can implement the safeguards suggested above.

473. In response to the concerns of some commenters regarding the disclosure of information to non-public utility transmission providers, we believe that simultaneous disclosure of transmission planning information where appropriate alleviates many of those concerns. In those instances where there is non-simultaneous disclosure of information, we find that existing reciprocity requirements ensure that information is not inappropriately shared with the non-public utility transmission provider's marketing affiliate.

474. In Order No. 888-A, the Commission clarified that, under the reciprocity condition, a non-public utility transmission provider must also comply with the OASIS and Standards of Conduct requirements or obtain waiver of them.\267\ We reiterate that non-public utility transmission providers should abide by the Standards of Conduct with regard to managing non-public transmission planning information obtained through the planning process, consistent with their reciprocity obligations. We also note that, given the planning process required by this Final Rule, it may be necessary to revisit the waivers of the Standards of Conduct granted to certain non-public utility transmission providers in the past. We will not do so, however, on a generic basis in this proceeding. All such existing waivers thus shall remain in place. Whether an existing waiver of the Standards of Conduct should be revoked will be considered on a case-by-case basis in light of the circumstances surrounding the particular transmission provider.\268\

\267\ See Order No. 888-A at 30,286.

\268\ We believe this same approach should also apply to public utilities that have obtained waivers of the Standards of Conduct.

475. In order for the Final Rule's transmission planning process to be as effective as possible, we emphasize that all transmission providers, both jurisdictional and nonjurisdictional, must be assured that the information they provide in that process will not be used inappropriately in the wholesale power market. While we decline to require a third party independent facilitator as discussed below, we do believe that utilizing an independent entity may help parties manage Standards of Conduct concerns.\269\ Finally, we wish to emphasize that the Commission recognizes that compliance with the Standards of Conduct can impose costs on small entities, but we believe that this concern must be balanced against the fact that a coordinated and open transmission planning process is critical to remedying undue discrimination and meeting our Nation's future energy needs and that an open planning process cannot be fully successful if certain entities (whether jurisdictional or nonjurisdictional) can use the information to obtain an undue advantage in power markets. We therefore intend to balance the costs of confidentiality restrictions with the importance of not allowing any entity an undue competitive advantage in addressing this issue on a case-by-case basis.

\269\ The Commission will consider whether further changes to the Standards of Conduct would facilitate the transmission planning requirement in the Standards of Conduct NOPR initiated in Docket No. RM07-1-000. See supra note 257. We also intend to address the concerns of NARUC with regard to waiving the Standards of Conduct concerning communications between resource and transmission planners in that proceeding.

476. Although we adopt the foregoing protections to ensure that particular entities do not gain an inappropriate competitive advantage over others, we believe that transmission providers should make as much transmission planning information publicly available as possible, consistent with protecting the confidentiality of customer information. Given that one of the primary objectives of the planning reforms adopted herein is to allow customers to consider future resource options, it will be necessary for market participants, including the merchant function of transmission providers, to have access to basic transmission planning information in order to consider those options. The simultaneous disclosure of transmission planning information can alleviate the Standards of Conduct concerns discussed above.\270\

\270\ Transmission providers could ensure simultaneous disclosure of information through such actions as providing all current and potential customers and other stakeholders equal access, notice, and opportunity to attend planning meetings, providing for the contemporaneous availability of meeting handouts and minutes on the transmission providers' OASIS or Internet Web sites, and requiring that an energy affiliate or marketing affiliate employee of the transmission provider may not attend a meeting unless a representative of at least one additional customer or potential customer is present. We believe such actions would typically constitute compliance with sections 358.5(a) and (b) of the Standards of Conduct, 18 CFR 358.5(a)-(b), dealing with information access and prohibited disclosure, respectively.

477. In response to commenter concerns regarding the sufficiency of planning information currently available in the Form 715, we find that Form 715, as well as Form 714, have not provided customers and others with the timely data needed to perform load flow studies and other analyses to ensure that planning is being conducted on a comparable basis. For example, while we understand that certain planning information is already provided in FERC Form No. 714 (Annual Electric Control and Planning Area Report) and FERC Form 715 (Annual Transmission Planning and Evaluation Report), we believe that with regard to transparency of data and assumptions, Forms 714 and 715 are limited in a number of ways. An important limitation is that information is not necessarily available on a consistent geographic basis. Form 715 requires selected powerflow studies by

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control area, while Form 714 requires information on control area generation and load, including hourly load on a planning area. Since these two areas do not necessarily coincide, it can be difficult to apply the data except for the single annual or seasonal system peak. Consequently, Form 715 is an insufficient basis for broad transmission planning purposes and must be supplemented by additional assumptions and data.

478. Information may also be difficult to compare or apply if a region is larger than a single control area. Where the peak periods represented in the Form 715 correspond to different time periods in different control areas, separate assumptions and information may be needed for a study encompassing multiple control areas. In addition, each control area may include different criteria for including facilities in the data and additional assumptions will be needed to resolve these issues as well. Moreover, information on the basis for key assumptions is limited. The Form 715 instructions require a description of transmission planning reliability criteria and assessment practices, but allow the transmitting utility discretion on what is reported. As a result, assumptions regarding key inputs, such as the load forecasts, are not available. Similarly, information regarding customer demand response is not available. Lastly, Form 715 requires no information explaining the basis for generator dispatch in the powerflow cases, nor is any economic information provided. For studies of system peak reliability, when all generators are expected to be running, this may not be a significant limitation. However, without some basis for dispatching the system at other times, it becomes difficult or impossible to conduct meaningful load flow studies for other planning purposes. Therefore, we will require the disclosure of criteria, assumptions, data, and other information that underlie transmission plans as described above.

479. Finally, several commenters assert that demand response resources should be considered in transmission planning.\271\ Some commenters note that certain regions currently are in the process of incorporating demand response into their transmission planning processes.\272\ Demand resources currently provide ancillary services in some regions, and this capability is in under development in some others.\273\ We therefore find that, where demand resources are capable of providing the functions assessed in a transmission planning process, and can be relied upon on a long-term basis, they should be permitted to participate in that process on a comparable basis.\274\ This is consistent with EPAct 2005 section 1223.

\271\ E.g., Ohio Power Siting Board, New Jersey Board, and WIRES.

\272\ E.g., PJM and ISO-New England.

\273\ See Staff Report: Assessment of Demand Response & Advanced Metering at 97-100 (Docket Number AD-06-2-000) (Demand Response Report), available at http://www.ferc.gov/legal/staff-reports/demand-response.pdf#xml=http://search.atomz.com/search/http://search.atomz.com/search/

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Final Rule are not intended in any way to infringe upon State authority with regard to integrated resource planning. Rather, we believe that the transparency provided under an open regional transmission planning process can provide useful information which will help states to coordinate transmission and generation siting decisions, allow consideration of regional resource adequacy requirements, facilitate consideration of demand response and load management programs at the State level, and address other factors states wish to consider.

d. Information Exchange

480. In the NOPR, the Commission proposed that network transmission customers be required to submit information on their projected loads and resources on a comparable basis (e.g., planning horizon and format) as used by transmission providers in planning for their native load. The Commission further proposed that point-to-point customers be required to submit any projections they have of a need for service over that planning horizon and at what receipt and delivery points. The Commission sought comment on whether specific requirements should be adopted for this information exchange.\275\ The Commission also stated that transmission providers must allow market participants the opportunity to review and comment on draft transmission plans.

\275\ The Commission noted in the NOPR that for network service, some of this information is already required by sections 29, 30, and 31 of the pro forma OATT, but to the extent it is not, the Commission proposed to require customers to provide additional information as necessary for the transmission provider to develop a system plan.

Comments

481. Transmission providers suggest that they should be responsible for developing a schedule and format for submission of information and the development of a draft plan that provides sufficient time for participants to review and comment before completion of a final plan.\276\ EEI emphasizes the importance of requiring comparable information from all participants in planning, including non-public utilities. EEI maintains that similarly-situated participants should have comparable information, with commercially-sensitive information available only to transmission function personnel. Duke supports the information exchange principle in general, but believes the NOPR envisions a wider exchange of information on loads and resources than is appropriate.\277\ Instead, Duke believes that planning participants should agree on how much detail will be available. WAPA similarly suggests that any criteria for information exchange should be developed by stakeholders, not the Commission.

\276\ E.g., EEI, Pinnacle, Salt River, and Xcel.

\277\ TVA states that it is unaware of any shortcomings with the existing information exchange process and that more specific requirements may limit the ability of transmission providers to meet changing needs and processes.

482. Although commenters do not generally disagree with a requirement for point-to-point customers to submit projections of their needs for service, they question the value of these projections if the customers have not actually requested service for these projected needs.\278\ Nevada Companies state that point-to-point customers should provide future use forecasts and that the forecast data transferred by all entities should be provided for the planning horizon in a uniform manner.

\278\ E.g., APPA, Duke, and Salt River.

483. Southern is concerned that the opportunity for review and comment could be construed to apply to draft interconnection, system impact, or facilities studies under the transmission provider's OATT. Southern argues that such a requirement would cause great delay and asks the Commission to clarify that the transparency requirement for review and comment on transmission plans is limited to only the transmission provider's draft of its base case transmission plan.

484. Other commenters advance a view that joint planning should consist of more than providing the transmission provider with information and then reviewing and commenting on the plans it develops; rather, customers need to be able to actively participate in the development of the planning studies and transmission plans.\279\ APPA likewise believes that earlier involvement is needed so that projected needs are fully understood and accounted for in the initial development of the plan.\280\ NCPA stresses that reviewing plans is meaningless if there is no access to data on how the plan was created, how economic evaluation was

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performed, and how and why proposed upgrades were chosen. Old Dominion suggests that planning information and data be posted no less than monthly or, where appropriate, seasonally. TDU Systems and NCEMC stress that LSEs should have access to all information at the same time since if a transmission provider performs studies without including other LSEs, it opens the door for providers to act on sensitive information before releasing it to other LSEs.

\279\ E.g., NCPA and TDU Systems.

\280\ See also Bonneville, California Commission, Imperial, NCPA, and Seattle.

485. Some commenters advance the view that distributed generation and other demand response resources should be considered in developing a transmission plan.\281\

\281\ E.g., New Jersey Board, Ohio Power Siting Board, and WIRES.

Commission Determination

486. The Commission adopts the information exchange principle as to both network and point-to-point transmission customers. Accordingly, we will require transmission providers, in consultation with their customers and other stakeholders, to develop guidelines and a schedule for the submittal of information. In order for the Final Rule's planning process to be as open and transparent as possible, the information collected by transmission providers to provide transmission service to their native load customers must be transparent and, to that end, equivalent information must be provided by transmission customers to ensure effective planning and comparability. We clarify that the information must be made available at regular intervals to be identified in advance. Information exchanged should be a continual process, the frequency of which should be addressed in the transmission provider's compliance filing required by the Final Rule. However, we expect that the frequency and planning horizon will be consistent with ERO requirements.

487. We also believe that it is appropriate to require point-to- point customers to submit any projections they have of a need for service over the planning horizon and at what receipt and delivery points. We believe that any good faith projections of a need for service, even though they may not yet be subject to a transmission reservation, may be useful in transmission planning as they may, for example, provide planners with likely scenarios for new generation development. If the point-to-point customers do not submit such projections, then the transmission provider cannot later be faulted for failing to consider planning scenarios that might have taken into account reasonable projections of future system uses that were not the subject of specific service requests. To the extent applicable, transmission customers also should provide information on existing and planned demand resources and their impacts on demand and peak demand. In addition, stakeholders should provide proposed demand response resources if they wish to have them considered in the development of the transmission plan.

488. Lastly, in response to the concerns of some commenters, we emphasize that the transmission planning required by this Final Rule is not intended, as discussed earlier, to be limited to the mere exchange of information and then review of transmission provider plans after the fact. The transmission planning required by this Final Rule is intended to provide transmission customers and other stakeholders a meaningful opportunity to engage in planning along with their transmission providers. At the same time, we emphasize that this information exchange relates to planning, not other studies performed in response to interconnection or transmission service requests. e. Comparability

489. In the NOPR, the Commission proposed that, after considering the data and comments supplied by market participants, each transmission provider develop a transmission system plan that (1) Meets the specific service requests of its transmission customers and (2) otherwise treats similarly-situated customers (e.g., network and retail native load) comparably in transmission system planning. Comments

490. Several commenters support the comparability principle,\282\ and others state that existing processes already follow this principle.\283\ EEI urges the Commission to emphasize that the ``comparability'' principle requires the transmission provider or transmission owner to treat similarly-situated participants comparably in the development of a plan, but does not require that all participants be treated equally. Pinnacle and others support comparable treatment of similarly-situated customers and request the Commission to confirm that native load protections will be recognized in the concept of comparability.\284\ New Mexico Attorney General asserts that native load and non-affiliated merchants and other wholesale customers should not be treated comparably, because utilities have a statutory obligation to serve.

\282\ E.g., California Commission, NCPA, CREPC, Salt River, Seattle, and WAPA.

\283\ E.g., Duke and Imperial.

\284\ See also MidAmerican, Progress Energy, and Xcel.

491. TDU Systems and the NRECA repeat the view that comparability cannot be achieved if the transmission provider is the only one developing the plan, which they believe this principle contemplates. They argue instead that LSEs should be allowed to participate actively in the development of the plan from the beginning and should have equal weight in decision-making. TDU Systems believes that comparability does not allow for different planning standards for certain customers, because it may leave rural electric cooperatives out of the planning loop.\285\ TAPS also argues that comparability is not enough; rather, substantive goals should be included.\286\

\285\ See also NRECA Reply and Old Dominion.

\286\ TAPS cites to its ``Balanced Principles for Transmission Planning & Expansion,'' which was attached to its NOI comments, for a description of the following substantive goals: (1) Reliability/ adequacy, (2) accommodating load growth, (3) preserving existing transmission rights, (4) access to regional competitive generation markets, (5) maintaining deliverability, (6) facilitating regional/ inter-regional power transfers, and (7) integrating new generation into the regional grid. TAPS emphasizes that the process should anticipate needs and propose solutions before serious transmission problems emerge.

492. Noting that not all transmission service requests may be granted, Southern urges the Commission to clarify that the intent of this criteria is that the transmission provider plan its system so as to be able to reliably serve all of its long-term firm commitments on its transmission system in accordance with its State and Federal legal requirements, as well as ERO Standards. With regard to RTO and ISO planning, NYAPP argues that it is not comparable for an RTO or ISO to only plan for bulk power facilities, while allowing individual transmission owners the discretion to plan for lower voltage transmission facilities.

493. Some commenters argue that demand resources should be treated comparably to other resources in transmission planning.\287\

\287\ E.g., ELCON, New Jersey Board, and WIRES.

Commission Determination

494. The Commission adopts the NOPR's proposal as to the comparability principle and will require the transmission provider, after considering the data and comments supplied by customers and other stakeholders, to develop a transmission system plan that (1) Meets the specific service requests of

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its transmission customers and (2) otherwise treats similarly-situated customers (e.g., network and retail native load) comparably in transmission system planning.\288\ Further, we agree with commenters that customer demand resources should be considered on a comparable basis to the service provided by comparable generation resources where appropriate.

\288\ As discussed above, we emphasize that the obligation imposed herein on transmission providers is meant to include transmission owners in RTOs and ISOs that no longer have their own OATTs, as well as non-public utility transmission providers required to comply with the Final Rule's planning process consistent with their reciprocity obligations.

495. We are specifically requiring a comparability principle to address concerns, such as those raised by commenters, that transmission providers continue to plan their transmission systems such that their own interests are addressed without regard to, or ahead of, the interests of their customers. Comparability requires that the interests of transmission providers and their similarly-situated customers be treated on a comparable basis. In response to the concerns expressed by several commenters, we emphasize that similarly-situated customers must be treated on a comparable basis, not that each and every transmission customer should be treated the same.\289\ f. Dispute Resolution

\289\ Additionally, in our discussion of the coordination principle above, we clarify that transmission planning is the tariff obligation of each transmission provider, and as such, ultimate responsibility for planning remains with transmission providers. Accordingly, we reject the arguments made by some commenters that comparability requires that customers have equal weight in decision- making.

496. In the NOPR, the Commission proposed that transmission providers propose a dispute resolution process, such as requiring senior executives to meet prior to the filing of any complaint and using a third party neutral. The Commission noted that the Commission's Dispute Resolution Service is available to assist transmission providers in developing a dispute resolution process. The Commission also noted that, in addition to informal dispute resolution, affected parties would have the right to file complaints with the Commission under FPA section 206. The Commission sought comment on whether any specific dispute resolution processes should be required. Comments

497. Many commenters support the proposed dispute resolution principle,\290\ while others believe existing processes, including section 12 of the pro forma OATT, are sufficient.\291\ Other commenters simply urge flexibility in the development of a dispute resolution process.\292\ However, maintaining that the Commission has no legal authority to mandate a regional planning process or dispute resolution related thereto, Progress states the Commission should be flexible and allow for a voluntary dispute resolution process.\293\

\290\ E.g., APPA, Bonneville, California Commission, Imperial, and NCPA.

\291\ E.g., East Texas Cooperatives, Salt River, Seattle, TVA and WAPA. TVA points out that since planning and its principles are just now being formed, resources would be better spent on developing platforms where interested parties could have input into the planning process, as opposed to dispute resolution.

\292\ E.g., Allegheny, Nevada Companies, Pinnacle, and Southern. Xcel, however, does not believe any dispute resolution process is required in the OATT.

\293\ See also Duke and MidAmerican.

498. Southern believes that dispute resolution should be limited to whether a provider has complied with any procedural requirements and not be utilized by parties to modify a transmission plan. APPA, however, argues that such an approach would relegate customers to an advisory role. EEI believes the Commission should include principles for dispute resolution and should allow stakeholders in the regional planning groups to craft their own procedures consistent with those principles. Reflecting concerns of some of its members, EEI cautions against mandating dispute resolution that includes binding resolution of whether, how, where, or when to construct additional transmission facilities.

499. Indianapolis Power believes there should be a dispute resolution process in place with specific steps identified, expressing reservations about the vagueness of the current MISO process. ATC argues that RTO plans should recognize which entity is ultimately accountable for building transmission, by requiring transmission customers that have a dispute with a plan first to appeal to the local transmission owner to ensure both entities fully understand what is being requested, before carrying the dispute further.

500. Consistent with its focus on integrated joint planning, TDU Systems asks that the Commission clarify that a dispute resolution process is not being required as a principle as an acknowledgement that transmission providers will retain control over the process. As long as LSEs are an integral part of the planning process, TDU Systems stress that there should be no need for an elaborate dispute resolution process. Commission Determination

501. The Commission adopts the NOPR's proposal to require transmission providers to develop a dispute resolution process to manage disputes that arise from the Final Rule's planning process.\294\ An existing dispute resolution process may be utilized, but those seeking to rely on an existing dispute resolution process must specifically address how its procedures will be used to address planning disputes. The dispute resolution process should be available to address both procedural and substantive planning issues, as the purpose for including a dispute resolution process is to provide a means for parties to resolve all disputes related to the Final Rule's planning process before turning to the Commission.

\294\ We have already addressed arguments concerning our jurisdiction to require a transmission planning process. A process for resolving disputes that arise from that planning process is a necessary incident to it.

502. We emphasize that the intent of the dispute resolution process required here is not to address issues over which the Commission does not have jurisdiction, such as a transmission provider's planning to serve its retail native load or State siting issues. As discussed above, however, we do intend that the planning process required by this Final Rule ensure comparability in planning between that conducted for a transmission provider's retail native load and its similarly-situated transmission customers and, therefore, issues relating to such comparability may be appropriate for the dispute resolution process.

503. Lastly, we encourage transmission providers, customers, and other stakeholders to utilize the Commission's Dispute Resolution Service to help develop a three step dispute resolution process, consisting of negotiation, mediation, and arbitration. Regardless of the process adopted by a transmission provider, affected parties of course would retain any rights they may have under FPA section 206 to file complaints with the Commission. g. Regional Participation

504. In addition to preparing a system plan for its own control area on an open and nondiscriminatory basis, the Commission proposed in the NOPR that each transmission provider be required to coordinate with interconnected systems to: (1) Share system plans to ensure that they are simultaneously feasible and otherwise use consistent

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assumptions and data, and (2) identify system enhancements that could relieve ``significant and recurring'' transmission congestion (defined below). The Commission emphasized that such coordination should encompass as broad a region as possible, given the interconnected nature of the transmission grid and the efficiency of addressing these issues in a single forum. The Commission also recognized that, as in the West, it may be appropriate to organize regional planning efforts on both a sub-regional and regional level. The Commission sought comment on whether there are existing institutions (such as the NERC regional councils or sub-regional planning groups) that are well- situated to perform or coordinate this function. Comments Regional Scope

505. EEI agrees that regional planning should be encouraged, but urges the Commission not to be prescriptive about the size of the regions involved. According to EEI, the Commission should define regional planning as planning that involves more than one transmission provider and allow the regions to define themselves. CAISO believes the Commission should leave the determination of the sub-regional and regional boundaries to transmission providers. NC Transmission Planning Participants assert on reply that the participants in each regional process are in the best position determine the proper scope of the planning process for their region. NRECA argues that customers and other stakeholders should be allowed to participate in the discussion that leads to the delineation of regions. NRECA asserts that regions should be large enough to minimize the potential for seams problems for LSEs in multiple control areas. At a minimum, NRECA argues that the Commission should ensure that all public utility transmission providers coordinate with their adjoining systems to ensure that the needs of LSEs with loads and resources in different systems' areas are met.

506. TDU Systems support mandatory regional planning and believe that the Commission should specify the criteria for determining regions, rather than prescribe regional boundaries. In TDU Systems' view, ``regional'' planning at a minimum means something more than planning on an individual control area basis.\295\ TDU Systems stress that the existence of sub-regional planning must not diminish the obligation to plan on a broader, more regional level. TDU Systems also believe that more than coordination is required; rather, transmission providers should be required to conduct planning on an integrated basis with, at a minimum, first-tier, adjacent interconnected systems. If a transmission provider refuses to do so, TDU Systems believe that should be considered an exercise of vertical market power and the transmission provider should lose its market-based rate authority. TDU Systems also urge the Commission to require regional planning for both reliability and economic upgrades, in order to ensure that competitive market development is not retarded by inappropriate seams at the borders of utility systems.\296\ In its reply, NRECA argues that regional participation must be mandatory, because uncoordinated, unilateral planning by transmission providers severely handicaps LSEs' assembly of competitive power suppliers for their customers.

\295\ TAPS believes joint planning should include at least two transmission providers and be no smaller than a State. TAPS suggests that the transmission providers' compliance filings identify those other providers it proposes to include in its regular regional planning process.

\296\ NRECA's comments on regional planning are consistent with those of TDU Systems.

507. PJM states that transmission providers bordering RTOs should be required to participate in the RTO planning process, but MidAmerican opposes such a requirement and believes it already happens in MISO anyway. MAPP also opposes such mandatory participation, pointing out that comparability would then require that transmission providers in RTOs participate in the planning processes of non-RTO providers on their borders as well.\297\ MAPP believes that currently-existing regions should have the opportunity to adjust their planning processes to meet the Commission's guidelines for regional transmission planning.

\297\ See also MidAmerican Reply.

508. Indianapolis Power emphasizes that the regional scope of a transmission provider's planning process should consider grid topology and historical usage to avoid regions that are too broad or unwieldy. Indianapolis Power believes that the current MISO region may be an example of a region that is too large, but nevertheless asserts that MISO should have the primary role in coordination, with regional councils in supporting roles. AWEA recommends nine planning regions that coincide with the nine regions being established for Regional Triennial Reviews in the market-based rate rulemaking in Docket No. RM04-7-000: \298\ PJM, New York, New England, Midwest, SPP, Southeast, California, Northwest, and Southwest.

\298\ See Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, Notice of Proposed Rulemaking, 71 FR 33102 (Jun. 7, 2006), FERC Stats. & Regs. ] 32,602 (2006).

509. LDWP and Salt River suggest that continued participation in existing regional and sub-regional groups should satisfy the expectation that municipally-owned transmission providers participate in open and transparent regional planning processes. Other commenters express a similar concern that the Commission not mandate any procedures that would interfere with the processes the West has already established.\299\ New Mexico Attorney General believes that those already engaged in a planning process should be allowed a waiver.

\299\ E.g., California Commission, Imperial, and Salt River.

510. NARUC urges the Commission to clarify that planning proposals should not interfere with or undermine existing regional planning efforts, such as those conducted by RTOs and in non-RTO areas.\300\ Project for Sustainable FERC Energy Policy recommends that the Commission use the Bonneville and PJM planning processes as models for evaluating transmission provider compliance. Arkansas Commission believes that the active involvement of states can be a catalyst for regional planning.

\300\ See also NC Transmission Planning Participants Reply and North Carolina Commission Reply. Also, in its reply, North Carolina Commission urges the Commission not to be overly prescriptive with respect to the details of regional transmission planning.

511. National Grid believes the principles of coordination, openness, and transparency should extend to inter-regional planning and requests clarification that this is the Commission's intent for neighboring regions in a single interconnect. Existing Institutions

512. Regarding the Commission's request for comment on whether there are existing institutions that are well-situated to coordinate regional participation, commenters express differing views regarding the identity of the regional coordinator and the size of the region over which entities should be required to coordinate. Some transmission provider commenters cite NERC regions and regional councils as well- suited for coordinating regional participation.\301\ Taking an opposite view, ISO/RTO Council maintains that RTOs and ISOs are the best models for

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regional participation, because regional reliability organizations do not have mandates or authority to ensure that adequate system expansion occurs on a coordinated basis.

\301\ E.g., Allegheny, Constellation, and Duke.

513. MISO is concerned the Commission intends to shift transmission planning responsibility from RTOs to the Regional Entities under the ERO, arguing that these entities have neither a sufficient level of independence nor a track record in transmission planning. TDU Systems suggest that RTOs, where they exist, should perform the regional planning function, although in some other instances it may be the regional reliability organizations. Although CAISO states that a larger regional entity with the authority to order expansion has some appeal, it contends there are too many hurdles to creating such an entity in the West. TAPS suggests a ``Regional Joint Planning Committee'' that is not dominated by transmission providers, which would direct the study process and be responsible for the development of uniform planning criteria, assumptions for base and changed cases, and transmission plans. Existing Regional Planning Processes The West

514. Transmission provider commenters in the West (outside California) generally recommend the Western Electricity Coordinating Council (WECC) \302\ as a successful institution and an appropriate model for designating regions and developing a plan for the interconnection.\303\ Many public power entities and others in the West also support WECC and suggest that it should be a primary focus when deciding which institution can provide independent regional review and coordination of grid planning in the West.\304\ For example, California Commission notes that WECC's Transmission Expansion Planning Policy Committee allows for the consolidated needs of all the system operators in the Western Interconnection to be considered in the planning process and considers both reliability and economic transmission planning. California Commission also stresses that the processes in the West have resulted in transmission being built. Utah Municipals, however, are critical of the WECC process, and in reply, assert that the WECC process does not allow for effective stakeholder input, but merely review of transmission plans once they are formed. Utah Municipals also believe that sub-regional groups in its area (e.g., the Southwest Transmission Expansion Plan (STEP)) are more effective and urges the Commission to focus on the effective implementation of joint plans.\305\

\302\ In general, WECC and its sub-regional groups have adopted an overall division of labor whereby WECC has undertaken facilitation of interstate, commercial transmission projects and the sub-regional groups have facilitated the planning of their member providers.

\303\ E.g., ColumbiaGrid, MidAmerican, Nevada Companies, NorthWestern, Pinnacle, and Xcel.

\304\ E.g., Anaheim, APPA, California Commission, Imperial, LDWP, NCPA, PGP, Public Power Council, CREPC, Salt River, Santa Clara, Seattle, TANC, WAPA, and Western Governors. APPA notes, however, that not all of its members that support the WECC planning process support those within California.

\305\ Public Power Council does not support expansion of WECC's role in coordinating planning beyond its current activities, as it believes WECC's strength lies in the area of reliability and not planning and, therefore, that WECC would be best served by focusing on reliability and standards enforcement, rather than as a participant (as a facilitator or otherwise) in commercial matters.

515. Other commenters support the sub-regional planning processes in the West as well, and generally believe the Commission should look to each sub-region's existing processes and institutions.\306\ For example, commenters in the Southwest and California also support the sub-regional groups located in that region (e.g., STEP and the Southwest Area Transmission Expansion Planning group (SWAT)).\307\ California Commission also supports the CAISO planning process and states that CAISO works closely with stakeholders to proactively identify needed, cost effective transmission solutions through an open, non-discriminatory process that has resulted in $1.8 billion in transmission being constructed.\308\ In its reply, NCPA emphasizes that the Commission should not equate the CAISO planning process with a California-wide process, because not all transmission providers in California are members of CAISO. However, California Commission notes that California, with the support of WECC, has begun the work of creating a California-wide sub-regional planning group that includes the large, unregulated municipal utilities that do not participate in CAISO.

\306\ WAPA points out that certain broad functions related to planning can be coordinated at the regional level, but that sub- regional planning is necessary in an expansive regional area, such as WAPA's service territory, in order to provide focus and detail.

\307\ E.g., LDWP, New Mexico Attorney General, and Salt River. LDWP also cites its involvement in the Public Power Initiative of the West, CAISO, and the Western Arizona Transmission System group.

\308\ Anaheim believes that the CAISO process does not currently proactively evaluate the adequacy of the system or itself propose projects that will enhance reliability or efficiency and is based entirely upon plans presented to it by transmission owners. It notes, however, that CAISO has proposed reforms to address these issues. See also Anaheim Reply.

Northeast

516. PJM, NYISO, and ISO New England all have transmission planning processes that have been approved by the Commission. ISO/RTO Council cites billions of dollars of transmission investment in the Northeast as an example of the success of these transmission planning processes and argues that these processes all satisfy the Commission's principles for coordinated, open, and transparent planning. PJM maintains that its Regional Transmission Expansion Planning Protocol is a successful and comprehensive regional planning paradigm. ISO New England also argues that its transmission planning meets the principles and further points to the Northeastern ISO/RTO Planning Coordination Protocol as providing coordinated planning across the entire Northeast region.

517. Utilities in the Northeast are generally supportive of the transmission planning in the Northeast RTOs. Designated NY Transmission Owners contend that the NYISO Comprehensive Reliability Planning Process is fully open, coordinated, and transparent and meets or exceeds each of the eight principles in the NOPR. PSEG believes the PJM planning process embodies the NOPR principles. Constellation cites the planning processes in PJM and the NYISO as examples of planning processes that, while not perfect, should serve as models for compliance filings by others. Old Dominion, however, expresses concern over continuing domination of transmission planning by transmission owners, but nevertheless commends PJM for recent efforts to include more stakeholder input in the planning process. National Grid is generally supportive of ISO New England's planning process. Northwest

518. Several commenters in the Northwest generally support the Northwest Power Pool and the ColumbiaGrid process (which will provide for a biennial transmission expansion plan for certain entities in the Northwest).\309\ Also, two groups in the Northwest are forming to address sub-regional planning in that region--the ColumbiaGrid group and the Northern Tier Transmission Group--but it is not

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yet clear how such groups intend to coordinate with each other.

\309\ E.g., Bonneville, ColumbiaGrid, PGP, Public Power Council, and Seattle. APPA also notes its members' support for the sub- regional processes in the Northwest.

Southeast

519. The public power commenters in the Southeast were not as supportive of the existing regional and sub-regional planning processes in their region. TVA and Santee Cooper generally support the process conducted by the Southeast Electric Reliability Council (SERC), and Santee Cooper notes that it has had a formal joint planning process with its largest wholesale customer for more than 25 years. APPA, however, notes that its members did not generally endorse existing regional entities in the Southeast. APPA states that SERC, for example, just ``rolls up'' the transmission plans of the transmission providers, and some working groups currently exclude non-transmission owners.\310\

\310\ See also TDU Systems Reply.

North Carolina

520. NCEMC points to the North Carolina Transmission Planning Collaborative (NC Transmission Planning), a joint planning process with an independent facilitator, in North Carolina. NCEMC emphasizes that more than regional coordination is required and that regional planning needs to be more than mere stakeholder review and must allow for full participation of LSEs in planning. NCEMC stresses that effective regional planning requires participation on a sufficient scale to encompass all LSEs within a natural market area in order to properly address seams issues and impacts on neighboring systems. Fayetteville does not believe NC Transmission Planning complies with the planning principles outlined in the NOPR. Midwest

521. MISO believes its current transmission planning process represents industry best practices, arguing that it is open and inclusive and provides multiple opportunities for entities to participate. MISO Transmission Owners endorse the existing MISO transmission planning process and believe that the process already provides for regional planning and an open process with stakeholder involvement. Ohio Power Siting Board, however, claims that MISO's transmission planning process should not be regarded as best practices, stating that it is not sufficiently open and transparent. It also suggests that RTOs merely ``rubber stamp'' investor-owned utility plans. Additionally, FMPA \311\ notes that MidAmerican has recently made efforts to engage in more proactive planning and has offered joint transmission investment opportunities. FMPA also points to its membership in CAPX 2020, a consortium of Upper Midwest utilities, which are jointly studying and planning for the needs of regional transmission. However, FMPA makes clear that it believes smaller customers nevertheless need a tariff requirement for planning to ensure that their needs are addressed.

\311\ We note that FMPA filed joint comments on behalf of itself and the Midwest Municipal Transmission Group.

Florida

522. While the Florida Commission believes that the planning process conducted by the Florida Reliability Coordinating Council (FRCC) is adequate, others, such as FMPA, do not.\312\ Florida Commission states that the FRCC has instituted a transparent and inclusive planning process whereby utilities, generators, and marketers participate in joint transmission planning studies and evaluate impediments to transfer capability and determine solutions to congestion in order to enhance the reliability of the FRCC system.

\312\ See also Seminole Reply.

Commission Determination

523. We adopt the NOPR's proposal to include a regional participation principle as a component of the Final Rule's transmission planning process. Accordingly, in addition to preparing a system plan for its own control area on an open and nondiscriminatory basis, each transmission provider will be required to coordinate with interconnected systems to (1) Share system plans to ensure that they are simultaneously feasible and otherwise use consistent assumptions and data and (2) identify system enhancements that could relieve congestion or integrate new resources (discussed further below).\313\

\313\ As provided for above, transmission providers will be required to file a ``strawman'' proposal for compliance with the Final Rule's planning process within 75 days after publication of the Final Rule in the Federal Register that includes, among other things, a specification of the broader region in which they propose to conduct coordinated regional planning. The Commission will then convene technical conferences in several broad regions around the country to assist the participants in developing the appropriate regional planning groups to the extent they do not already exist.

524. As discussed earlier in this Final Rule, since the advent of open access, power markets have become regional in almost every area of the country. These regional markets provide opportunities for wholesale customers to access competitive sources of supply, rather than relying exclusively on local generation, including resources owned by their local transmission provider. However, as discussed above, it is not in the economic self-interest of transmission providers to expand the grid to permit access to competing sources of supply. A transmission provider has little incentive to upgrade its transmission capacity with its interconnected neighbors if doing so would allow competing suppliers to serve the customers of the transmission provider. We therefore find, as discussed in greater detail above, that greater coordination and openness in transmission planning is required, on both a local and regional level, to remedy undue discrimination. The coordination of planning on a regional basis will also increase efficiency through the coordination of transmission upgrades that have region-wide benefits, as opposed to pursuing transmission expansion on a piecemeal basis. The specific features of the regional planning effort should take account of and accommodate, where appropriate, existing institutions, as well as physical characteristics of the region and historical practices.

525. The Commission is encouraged that a number of voluntary coordinated and regional planning efforts have been developed throughout the country, including those administered by RTOs and ISOs and in certain sub-regions of the West and Southeast. For example, each of the Commission-approved RTOs in the Northeast, Midwest, and Southwest, as well as CAISO, provide for a coordinated and regional planning process with stakeholder input from each industry segment. There are several other promising efforts to establish voluntary coordinated and regional planning efforts around the country as noted in our discussion above of existing regional planning processes.

526. The Commission fully supports these existing efforts and believes some of them are consistent in significant respects with the nature of the reforms adopted in this Final Rule. In those regions and sub-regions that already have adopted significant reforms, the Commission's planning reforms may require only modest changes, while other regions and sub-regions may need to undertake more significant changes to the way in which transmission currently is planned. The Commission will not in this Final Rule opine on the characteristics of existing regional planning processes or their consistency with the reforms we adopt today.

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Rather, each process will be addressed in the context of the relevant compliance filing. In general, however, the Commission urges participants in existing regional planning processes to closely examine whether improvements may be implemented to ensure that each regional planning process is fully consistent with the requirements of this Final Rule.

527. Finally, the Commission acknowledges the importance of identifying the appropriate size and scope of the regions over which regional planning will be performed. We agree that transmission providers, customers, affected State authorities, and other stakeholders should be involved in developing those regions. We decline to mandate the geographic scope of particular planning regions at this time. The scope of a particular planning region should be governed by the integrated nature of the regional power grid and the particular reliability and resource issues affecting individual regions and sub- regions. In very large regions, there may well be both sub-regional and regional processes. For example, in the West there are various sub- regional processes in addition to a WECC regional planning process. We believe that such an approach can work, provided that there is adequate scope to the sub-regional processes and adequate coordination between sub-regions. We expect sub-regions to coordinate as necessary to share data, information and assumptions as necessary to maintain reliability and allow customers to consider resource options that span the sub- regions.

528. In response to the commenters that indicate that regional planning already occurs today as part of the NERC planning process, we support any such processes, but reiterate that, if they are to meet the requirements of the Final Rule, they must be open and inclusive and address both reliability and economic considerations. As we discuss elsewhere in this section, customers must be allowed to request that economic upgrades be studied and, therefore, we will require transmission providers to coordinate on these issues as necessary in sub-regional or regional planning processes. To the extent the NERC processes are not considered appropriate for such economic issues, individual regions or sub-regions may develop alternative processes. h. Economic Planning Studies

529. In the NOPR, the Commission proposed to require transmission providers to prepare studies identifying ``significant and recurring'' congestion and post such studies on their OASIS. The Commission explained that the studies should analyze and report on (1) The location and magnitude of the congestion, (2) possible remedies for the elimination of the congestion, in whole or in part, (3) the associated costs of congestion, and (4) the cost associated with relieving congestion through system enhancements (or other means). The Commission sought comment on how to define ``significant and recurring'' congestion, such as by reference to generation redispatch, repeated denials of service requests, zero ATC, frequent curtailments or a combination of these factors. The Commission noted that the required congestion studies would address both ``local'' congestion (i.e., within the transmission provider's system) and congestion between control areas and sub-regions. The Commission stated that the purpose of this requirement is to ensure that affected market participants, State commissions, and the Commission understand both the costs of recurring transmission congestion and the alternatives for relieving it. The Commission sought comment on how this information should be used by transmission providers and market participants to address significant and recurring congestion. Comments Need for Congestion Studies

530. The Commission's proposal regarding congestion studies gave rise to a wide range of comments. Some commenters generally support requiring congestion studies.\314\ East Texas Cooperatives asserts that congestion studies will greatly assist in the development of transmission plans, enable planning participants to focus on key elements of the system and assist in the preparation of the congestion studies conducted by DOE. NRECA also supports requiring congestion studies, but urges the Commission not to be prescriptive.

\314\ E.g., APPA, Arkansas Commission, California Commission, East Texas Cooperatives, Entegra, NCPA, CREPC, Southwestern Coop, TDU Systems, and WIRES.

531. Other commenters recommend eliminating the requirement.\315\ Southern, for example, argues that congestion studies could be misleading because they can imply that all congestion needs to be remedied.\316\ Duke, South Carolina E&G, and Southern agree that separate studies of congestion, beyond studies performed to meet service requests, should not be required. Rather than mandating congestion studies, Southern argues that the Commission should allow participants to determine which types of transmission studies have merit. Other commenters believe that, if congestion studies are required, they should be performed at a regional level rather than by each transmission provider individually.\317\

\315\ E.g., American Transmission, EEI, Progress Energy, and Southern.

\316\ Entegra, however, replied to Southern's assertion that congestion studies can be misleading, stating that congestion studies did not need to be misleading, and were, on the contrary, necessary for customers to assess the costs of managing versus eliminating congestion.

\317\ E.g., Imperial, MidAmerican, Nevada Companies, NorthWestern, Pinnacle, Salt River, SWAT, WestConnect, and Xcel.

532. The EEI position is representative of entities calling for elimination of the congestion study principle. EEI asserts that these studies in large part would be duplicative of the studies being performed by DOE pursuant to EPAct 2005.\318\ EEI also argues that these studies would be costly and time-consuming and that transmission providers generally do not have access to information needed for cost impact analysis and consequently cannot assess the cost of constraints.\319\ TDU Systems assert on reply that it is difficult to imagine that providers do not have the information needed or means to determine the location and magnitude of congestion on their systems, since they perform this function for themselves already. TDU Systems add that customers will readily provide any information needed for congestion studies, as it is in their interest to do so. APPA believes that customers should be expressly required to produce information to help determine the cost of congestion (e.g., the additional cost to them of running or purchasing more expensive generation). TDU Systems also argues that the distinction between economic and reliability upgrades is a fiction and should be disregarded.

\318\ Others assert that the DOE studies will be useful but not necessarily duplicative of the congestion study principle. E.g., APPA and Salt River.

\319\ Bonneville agrees that the costs of congestion itself are not readily available to transmission providers and that customers are better positioned to determine this.

533. In the Western Interconnection, entities maintain that WECC will be performing congestion studies that should meet the requirement. As a result, they assert that this principle should not be applied to individual transmission providers in the West, but that these providers should be permitted to meet the principle through the interconnection- wide congestion studies conducted by WECC. Tacoma notes that ColumbiaGrid is considering the

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services it can offer in congestion assessment at the sub-regional level in the Northwest. Other commenters, such as California Commission, Salt River, and Seattle, support a congestion studies requirement but believe it should not be required annually but rather biennially or triennially.

534. In the Eastern Interconnection, RTOs and ISOs, and entities in RTOs and ISOs, believe congestion studies are not needed where LMP markets are in place or are satisfied by RTO or ISO studies.\320\ Entergy argues that the congestion studies that will be performed by its independent coordinator of transmission should meet this requirement.

\320\ E.g., Allegheny, FirstEnergy, Indianapolis Power, and PSEG.

Determining ``Significant and Recurring'' Congestion

535. A variety of commenters provide suggestions as to what constitutes ``significant and recurring'' congestion. TDU Systems believe that there should be a presumption of congestion if a transmission provider posts zero ATC. TDU Systems, APPA, and Bonneville believe that other indications of significant and recurring congestion include the need for frequent generation redispatch, frequent curtailments for reasons other than force majeure, and repeated denials of requests for firm transmission service. California Commission and CREPC suggest a similar approach based on a comparison of ATC and schedules with historical flows and an assessment of denied requests, but emphasize that the process should be forward-looking as well.

536. APPA suggests the use of metrics to measure congestion (e.g., reporting on all congestion costs that exceed five percent of base energy costs and five percent of the hours in a season). California Commission also suggests the use of metrics, but cautions that there may be East-West differences. Sacramento stresses that such metrics should depend on whether the system being studied uses LMP or physical rights. In its view, financial metrics are most useful in LMP markets, while congestion in physical markets should be determined by paths that have been derated by a material percent of their nominal rating over a certain number of hours in a season.

537. Santa Clara suggests that significant and recurring congestion exists when congestion costs over a given path during the high use season approach or exceed the depreciation plus other fixed costs on the new facilities that would eliminate congestion on the path. Additionally, Santa Clara emphasizes that if, redispatch is necessary on an ongoing basis, this should be taken as an indication that new facilities need to be built.

538. New York Commission urges the Commission to utilize NYISO's process for measuring historical congestion--defined as the short-run production (i.e., dispatch) costs that could be avoided by system enhancements, as this represents the savings to society compared to the cost to society of investing in the system enhancement. New York Commission also cautions the Commission against using analyses focused on the impacts of transmission investments on wholesale energy prices, because these energy price impacts may be temporary and offset by changes in generation investments. TDU Systems and Old Dominion stress that in PJM significant and recurring congestion should be based on total gross congestion and not the much smaller and unrealistic measure of unhedgeable congestion, as this masks the economic reality that congestion itself has an economic cost.\321\

\321\ See also Indicated Parties Reply.

539. The Organizations of MISO and PJM States do not believe the Final Rule should address criteria for determining significant and recurring congestion, but should require each transmission provider to file criteria for inclusion and cost responsibility for upgrades that are included in the transmission plan to remedy congestion.

540. Seattle asserts that current OASIS standards do not support consistent tracking of service denials and that this inhibits the evaluation of congestion. Seattle also points out that the costs of congestion may be difficult to quantify because reliability dispatch is a reactive tool used only after service requests have been denied and prescheduled limits imposed and, therefore, foregone transactions will not be known to the transmission provider.

541. Ohio Power Siting Board asserts that distributed generation, demand response, and new technologies should be available to relieve congestion until longer-term solutions can be implemented. Commission Determination

542. The Commission adopts the NOPR proposal and retains a congestion study principle as part of the Final Rule's transmission planning process; however, we modify and clarify the principle in certain important respects in response to the comments received. At the outset, we wish to clarify that our primary objective in adopting this principle is to ensure that the transmission planning process encompasses more than reliability considerations. Although planning to maintain reliability is a critical priority, it is not the only one. Planning involves both reliability and economic considerations. When planning to serve native load customers, a prudent vertically integrated transmission provider will plan not only to maintain reliability, but also consider whether transmission upgrades or other investments can reduce the overall costs of serving native load. Such upgrades can, for example, reduce congestion (redispatch) costs or integrate efficient new resources (including demand resources) and new or growing loads. Thus, to represent good utility practice and provide comparable service, the transmission planning process under the pro forma OATT must consider both reliability and economic considerations. The purpose of this principle is to ensure that the latter is considered adequately in the transmission planning process.

543. Some commenters argue that economic upgrades should be considered only in the context of individual requests for service under the pro forma OATT. The Commission disagrees. The process for addressing individual requests for service under the pro forma OATT is adequate for customers who request specific transmission rights to purchase power from a particular resource in a particular location during a defined time period. However, it does not provide an opportunity for customers to consider whether potential upgrades or other investments could reduce congestion costs or otherwise integrate new resources on an aggregated or regional basis outside of a specific request for interconnection or transmission service. It thus limits, for example, groups of customers from considering more comprehensive solutions to transmission congestion, including investment in demand response. It also limits multiple LSEs from considering, on a more aggregated basis, whether particular upgrades may represent the most economic means of integrating new generation resources (e.g., wind resources) located in a common area that could be accessed by many customers. The Commission believes such coordinated studies can, for system planning purposes, be more beneficial than studies performed on a request-by-request basis. We also find that they are consistent with the requirement to provide comparable service.

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Transmission providers are not limited, in serving native load customers, to studying potential transmission upgrades only in the context of specific requests for service under the pro forma OATT.

544. Some transmission providers appear to object to this principle because they fear that an obligation to study potential upgrades is equivalent to an obligation to fund or build such upgrades. We clarify that this is not the intent of this principle. There is a difference between a planning process that is coordinated and open and one that dictates construction and cost responsibility. Both considerations are important, but, as we explain above, they are distinct. The purpose of this principle is to ensure that customers may request studies that evaluate potential upgrades or other investments that could reduce congestion or integrate new resources and loads on an aggregated or regional basis (e.g., wind developers), not to assign cost responsibility for those investments or otherwise determine whether they should be implemented. The issue of cost allocation is addressed in Principle No. 9 below.

545. The Commission also disagrees with the contentions of certain RTOs or ISOs that they need not comply with this principle. Although RTO and ISO planning processes tend to be more open and coordinated than the processes used by vertically-integrated transmission providers, this does not mean that RTO or ISO processes adequately address, in all circumstances, investments that are primarily economic in nature. When many RTO and ISO planning processes were created, they focused primarily on system enhancements necessary to maintain reliability. However, in recent years, as congestion has increased and generation reserve margins have declined, many RTOs and ISOs have taken increasingly progressive steps to identify investments that could reduce congestion and/or integrate new resources. For example, we recently approved a proposal by PJM to significantly enhance its RTEP planning process.\322\ We applaud these efforts as consistent with the direction of the reforms adopted herein. However, we decline to provide a blanket exception for RTOs and ISOs. Each RTO or ISO must show that its planning process is consistent with or superior to the requirements of the Final Rule in all respects.

\322\ See PJM Interconnection, L.L.C., 117 FERC ] 61,218 (2006), reh'g pending.

546. Some commenters express concern that this principle may result in costly congestion studies that are of little interest or value to customers. Our intent is not to impose a costly study requirement that is unrelated to the real-world concerns of consumers. In the NOPR, we sought comment on whether specific metrics (e.g., zero ATC or TLR frequency) should be used to trigger the congestion study requirement. After considering the comments on this topic, we do not believe that any single metric, or group of metrics, is adequate for that purpose. Relying on discrete metrics in this instance would risk both over- and under-inclusiveness--i.e., triggering too many studies, thereby imposing cost burdens on transmission providers that are not appropriate, or triggering too few studies, thereby omitting important studies that could help customers identify cost-effective solutions to congestion. Additionally, we direct transmission providers, in consultation with their stakeholders during development of their Attachment K compliance filings (as discussed above), to develop a means to allow the transmission provider and stakeholders to cluster or batch requests for economic planning studies so that the transmission provider may perform the studies in the most efficient manner. We will also require the requests for economic planning studies, as well as the responses to the requests, be posted on the transmission provider's OASIS or Web site, subject to confidentiality requirements.

547. The Commission will modify the principle to allow customers to choose the studies that are of the greatest value to them. Specifically, we are modifying the principle to require that stakeholders be given the right to request a defined number of high priority studies annually (e.g., five to ten studies) \323\ to address congestion and/or the integration of new resources or loads. The intent of this approach is to allow customers, not the transmission provider, to identify those portions of the transmission system where they have encountered transmission problems due to congestion or whether they believe upgrades and other investments may be necessary to reduce congestion and to integrate new resources. The customers should be able to request that the transmission provider study enhancements that could reduce such congestion or integrate new resources on an aggregated or regional basis without having to submit a specific request for service. This approach ensures that the economic studies required under this principle are focused on customer needs and concerns, not administratively determined metrics that may bear no necessary relation to those concerns. Once such studies are requested, the transmission provider would conduct the studies, including appropriate sensitivity analyses, in a manner that is open and coordinated with the affected stakeholders. The cost of the defined number of high priority studies would be recovered as part of the overall pro forma OATT cost of service.\324\ By limiting this principle to a defined number of high priority studies annually, we are not precluding stakeholders from requesting additional studies. However, to provide appropriate financial incentives, the stakeholder(s) requesting these additional studies would be responsible for paying the cost of such studies.

\323\ The example of five to ten studies mentioned in this Final Rule is merely illustrative. We recognize that the facts of each case will be used to determine the number of high priority studies allowed under a transmission plan.

\324\ This cost recovery mechanism is comparable and nondiscriminatory because the transmission provider already has the ability to include in its pro forma OATT rates the cost of service associated with studies performed on behalf of native load customers.

548. We also will modify this principle with respect to the scope of the studies being performed. The Commission proposed in the NOPR that the studies address ``significant and recurring congestion.'' However, the Commission also sought comment on whether, in addition, the study process should address upgrades associated with new generation resources and provide information needed to proactively evaluate such resources. We discuss the comments on this proposal in more detail below, but, as described therein, we agree that the study process should incorporate such considerations. We therefore modify Principle No. 8 to encompass the study of upgrades to integrate new generation resources or loads on an aggregated or regional basis. This is appropriate because congestion can limit both the efficient dispatch of existing generation resources as well as inhibit the development of new supply and demand resources. Moreover, many regions of the country must make investments in the near future to meet load growth and, accordingly, studies of the most economic means of making such investments are critically important to consumers.

549. By expanding the scope of this principle, we do not intend to supplant the existing process for individual customers to integrate new resources or loads through specific requests for

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interconnection or transmission service under the pro forma OATT. Rather, we contemplate that any such studies conducted pursuant to this principle, as explained above, would be for purposes of planning for the alleviation of congestion through integration of new supply and demand resources into the regional transmission grid or expanding the regional transmission grid in a manner that can benefit large numbers of customers, such as by evaluating transmission upgrades necessary to connect major new areas of generation resources (such as areas that can support substantial wind generation). Specific requests for service would continue to be studied pursuant to existing pro forma OATT processes.

550. With respect to studying the cost of congestion, several transmission providers argue that they do not have access to information regarding generation costs either from their merchant function or unaffiliated customers. We agree that the transmission provider should be obligated to study the cost of congestion only to the extent it has information to do so. We make clear, however, that if stakeholders request that a particular congested area be studied, they must supply relevant data within their possession to enable the transmission provider to calculate the level of congestion costs that is occurring or is likely to occur in the near future. To the extent that the transmission provider's merchant function possesses such information (e.g., redispatch cost information), it must provide that information to the extent necessary to conduct such studies. Providing for confidential treatment and application of the Standards of Conduct, as discussed above, will give assurance to customers that their cost and other information will not be used improperly. To that end, we direct transmission providers to clearly define the information sharing obligations placed on customers in the planning attachment to their pro forma OATT.

551. In response to those commenters that argue that regional congestion studies should be sufficient, we agree that regional congestion studies can be used as part of regional transmission planning processes required by this Final Rule. For example, to the extent the DOE has extensively studied congestion in certain broad areas, it is not necessary or appropriate for transmission providers to duplicate these studies. However, regional studies typically provide broad information on overall regional power flows and may not provide sufficient detail on local system conditions and congestion, such as detail on congested local facilities that may limit customer supply options, or detail on local conditions where additional service could be provided through redispatch. Moreover, although the DOE may identify areas where congestion exists or new generation may be developed, the purpose of DOE congestion studies is not to develop specific transmission system plans to remedy such congestion or integrate such resources. The DOE studies are therefore not a substitute for a more open and coordinated planning process to address specific upgrades that could reduce congestion or integrate new resources and loads. We therefore require each transmission provider to comply with the revised economic planning studies principle in this Final Rule both as to its own transmission system and as to the regional planning process described above. i. Cost Allocation for New Projects

552. In the NOPR, the Commission asked for comment on whether there should be a requirement for public utilities to develop cost allocation principles to address the recovery of costs associated with new transmission projects. In particular, the Commission asked whether the development of specific cost allocation principles would provide greater certainty and hence support the construction of new infrastructure or whether cost allocation is better handled on a case- by-case basis. Comments

553. Several commenters express concern that the Final Rule not reopen cost allocation principles in RTOs and ISOs or in the OATTs of vertically integrated transmission providers.\325\ Duke argues that the Final Rule should not address cost allocation for new transmission at all, stating that transmission pricing should be evaluated in a separate proceeding. Other commenters agree that cost allocation issues should be handled on a case-by-case basis.\326\

\325\ E.g., Duke, EEI, ELCON, ISO/RTO Council, MISO Transmission Owners, SCE, and Southern.

\326\ E.g., APPA, Arkansas Commission, PGP, Santee Cooper, Southwestern Coop, and Sacramento.

554. Some commenters urge the Commission to define cost allocation principles in this proceeding.\327\ For example, E.ON believes that the cost of upgrades should be directly allocated to parties benefiting from an expansion and proposes that the host transmission owner should coordinate and be responsible for obtaining funding. Many transmission customers, however, support rolled-in cost recovery for network upgrades.\328\ TDU Systems ask the Commission to clarify that direct assignment of facility upgrade costs only applies to point-to-point service, unless it is being used for the delivery of designated network resources to serve network load. If direct assignment is retained, TDU Systems suggest the Commission consider standardizing directly assignable facilities on a regional basis and stress that the critical factor is comparability. TAPS suggests ``regional'' cost-spreading for backbone high voltage facilities and criticizes participant funding because it encourages would-be beneficiaries to wait and hope that others will step forward first.

\327\ E.g., E.ON, National Grid and WIRES.

\328\ E.g., AWEA, NCEMC, NCPA, NRECA, Seattle, and TDU Systems.

555. Old Dominion emphasizes the need for cross-border transmission cost allocation mechanisms. In joint projects, Salt River emphasizes that it is inconsistent with an open season approach to assign benefits to a party and then assign cost responsibility beyond what the project participant would voluntarily assume based on the subscription rights received. Both Bonneville and TVA believe that cost allocation principles should be based on a determination of beneficiaries and cost causation. New Mexico Attorney General stresses that cost recovery for construction of transmission intended for wholesale or market transactions should not be allocated to native load. NCPA states that it would expect some Commission deference to recovery of costs of projects identified in a truly collaborative process.

556. At the October 12 Technical Conference, PJM stated that the Commission should provide generic guidance on what would be acceptable regarding cost allocation, though Progress Energy did not favor putting a cost allocation approach in the pro forma OATT, as modified by the Final Rule. National Grid expressed the view that the Commission would need to address cost allocation generally, arguing that cost allocation solely on a project-by-project basis is inefficient. Commission Determination

557. The Commission finds, after considering the comments, that it is appropriate to include a specific principle regarding cost allocation. The manner in which the costs of new transmission are allocated is critical to the development of new infrastructure. Transmission providers and customers cannot be expected to support the

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construction of new transmission unless they understand who will pay the associated costs. We therefore find that, for a planning process to comply with the Final Rule, it must address the allocation of costs of new facilities.

558. The Commission emphasizes, however, that we are not modifying the existing mechanisms to allocate costs for projects that are constructed by a single transmission owner and billed under existing rate structures. Our intent is not to upset existing cost allocation methods applicable to specific requests for interconnection or transmission service under the pro forma OATT. The cost allocation principle discussed herein is intended to apply to projects that do not fit under the existing structure, such as regional projects involving several transmission owners or economic projects that are identified through the study process described above, rather than through individual requests for service. We will not impose a particular allocation method for such projects, but rather will permit transmission providers and stakeholders to determine their own specific criteria which best fit their own experience and regional needs. The proposal should identify the types of new projects that are not covered under existing cost allocation rules and, therefore, would be affected by this cost allocation principle.

559. Although the Commission does not prescribe any specific cost allocation method in the Final Rule, we believe some overall guidance is appropriate. Our decisions regarding transmission cost allocation reflect the premise that ``[a]llocation of costs is not a matter for the slide-rule. It involves judgment on a myriad of facts. It has no claim to an exact science.'' \329\ We therefore allow regional flexibility in cost allocation and, when considering a dispute over cost allocation, exercise our judgment by weighing several factors. First, we consider whether a cost allocation proposal fairly assigns costs among participants, including those who cause them to be incurred and those who otherwise benefit from them. Second, we consider whether a cost allocation proposal provides adequate incentives to construct new transmission. Third, we consider whether the proposal is generally supported by State authorities and participants across the region.

\329\ Colorado Interstate Gas Co. v. FPC, 324 U.S. 581, 589 (1945).

560. These three factors are interrelated. For example, a cost allocation proposal that has broad support across a region is more likely to provide adequate incentives to construct new infrastructure than one that does not. The states, which have primary transmission siting authority, may be reluctant to site regional transmission projects if they believe the costs are not being allocated fairly. Similarly, a proposal that allocates costs fairly to participants who benefit from them is more likely to support new investment than one that does not. Adequate financial support for major new transmission projects may not be obtained unless costs are assigned fairly to those who benefit from the project.

561. These factors are particularly important as applied to the economic upgrades discussed above--e.g., upgrades to reduce congestion or enable groups of customers to access new generation. As a general matter, we believe that the beneficiaries of any such project should agree to support the costs of such projects. However, we recognize that there are free rider problems associated with new transmission investment, such that customers who do not agree to support a particular project may nonetheless receive substantial benefits from it. In the past, different regions have attempted to address such issues in a variety of ways, such as by assigning transmission rights only to those who financially support a project or spreading a portion of the cost of certain high-voltage projects more broadly than the immediate beneficiary/supporters of the project. We believe that a range of solutions to this problem are available. We therefore continue to believe that regional solutions that garner the support of stakeholders, including affected State authorities, are preferable. Moreover, it is important that each region address these issues up front, at least in principle, rather than having them relitigated each time a project is proposed. Participants seeking to support new transmission investment need some degree of certainty regarding cost allocation to pursue such investments. 3. Additional Issues Relating to Planning Reform a. Independent Third Party Coordinator

562. In the NOPR, the Commission acknowledged that an independent third party coordinator would provide benefits for transmission planning, but did not propose to require independence. Noting that independence could take many forms, the Commission sought comment on the level of independence that could provide benefits and the institutions that could offer such independence. Comments

563. Overall comments on the use of an independent third party to oversee or coordinate the planning process range from those who believe it is not needed to those who feel that it should be required rather than merely encouraged. Arguing against the need for an independent coordinator, South Carolina E&G does not believe an independent third party is either necessary or desirable. Arguing in favor of an independent coordinator, EPSA strongly supports independent oversight and believes that third party oversight will be necessary in non-RTO areas, particularly where transmission providers have conducted non- transparent processes.\330\ Most commenters fall somewhere between these two positions, finding potential benefits in independence but concurring with the proposal not to mandate it.

\330\ See also AWEA, Arkansas Commission, Old Dominion, and Project for Sustainable FERC Energy Policy. Old Dominion stresses that even in RTOs, the transmission owners may have the ability to exercise market power and, therefore, the market monitoring unit should have the requisite independence and authority to investigate and address undue influence.

564. Several public utility commenters acknowledge the potential benefits of using an independent coordinator and believe the Commission should encourage it.\331\ National Grid, for example, finds it difficult to see how a non-independent transmission provider would be able to manage confidential information in a manner fair to all stakeholders and recommends finding independent administration of planning ``superior to'' non-independent administration. Other commenters note only that independence can be beneficial or suggest that the Commission be open to independent third parties when offered.\332\ Progress agrees there can be benefits, but does not believe an independent coordinator is needed to ensure confidence.

\331\ E.g., National Grid, PPL, Constellation, and Tacoma.

\332\ E.g., APPA, Bonneville, California Commission, Duke, Indianapolis Power, NCEMC, NorthWestern, Progress Energy, CREPC, Sacramento, Seattle, and TDU Systems. Some public power entities, such as APPA, NRECA, and TDU Systems are concerned with ensuring that the costs of an independent coordinator do not outweigh the benefits.

565. EEI argues against an independence requirement, seeing no need to require non-RTO/ISO transmission providers to engage independent third parties to oversee the planning process.\333\ EEI believes the

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planning processes proposed in the NOPR are adequate without third party oversight and maintains that requiring third party coordination could add another layer of administration, might encroach on State authority, and could create the possibility that the transmission provider would lose control of the transmission plan. EEI however also notes that the Commission could require independent oversight in circumstances where a transmission planner has failed to implement the principles or has engaged in undue discrimination in planning for customer needs.

\333\ TVA believes that the levels of independence practiced in NERC and NAESB and the implementation and administration of those standards by the regional entitities (such as SERC) are adequate and appropriate.

566. The consensus at the October 12 Technical Conference was generally supportive of the potential benefits of an independent facilitator, but not supportive of a mandate. There was general support for the idea that an independent facilitator can assist with handling sensitive information and provide confidence that analysis of information would be fair, although several participants stated that sufficient trust and confidence could be obtained without an independent facilitator. Commission Determination

567. The Commission adopts the NOPR proposal to not require the use of an independent third party coordinator at this time. We agree that there are benefits to be gained from independent third party oversight, as cited by commenters, such as the ability to manage confidential information and the ability to ensure equitable treatment of all viewpoints in planning. We therefore encourage transmission providers and their customers and other stakeholders to explore aspects of planning where the use of an independent coordinator would be beneficial and to incorporate those aspects in their planning process compliance filings.

568. It is, however, possible to comply with the principles without the use of an independent third party. We expect the transmission plans themselves to be developed under an open process that includes coordination among each transmission provider, its customers, other stakeholders, and its neighbors. A transmission provider will need to demonstrate to us in a compliance filing that the plan meets the principles, including providing a dispute resolution process. We believe that an open, transparent planning process, with meaningful coordination and dispute resolution, will provide a sufficient basis for customers to identify and raise meaningful concerns if a plan does not treat similarly-situated customers in a comparable manner, where planning appears to be conducted in a discriminatory manner, or in other instances where the independence of planning may be in question. If disputes do arise in these areas and cannot be resolved consensually, we are available to either encourage a consensual resolution (e.g., by use of the Dispute Resolution Service) or resolve them ourselves if a complaint is filed. b. State Commission Participation

569. In the NOPR, the Commission strongly encouraged the participation of State commissions and other State agencies in the coordinated planning process, particularly with regard to regional planning. The Commission sought comment on how best to accommodate effective State participation. Comments

570. All commenters addressing the question of State participation agree that states have an important role in transmission planning, but there were only limited comments recommending specific processes to encourage State participation. Supporters of State participation generally believe that it can assist in obtaining siting approval and in cost recovery. ISO/RTO Council and individual RTOs and ISOs point to their current processes for including states in their region in the planning process. Noting the local benefits that can derive from interstate transmission projects, American Transmission supports collaborative efforts among states such as the Organization of MISO States. However, American Transmission and other commenters suggest that the Commission defer to the states to determine how they participate in the planning process.\334\

\334\ E.g., American Transmission, Duke, and Progress Energy.

571. Allegheny believes it should be the responsibility of the transmission provider to maintain good communication with State commissions. Nevada Companies assert that the real question the Commission should be posing is how to coordinate the State jurisdictional role in transmission planning and construction and the obligations imposed by the Commission on transmission providers, so that the system of coordination does not put transmission providers in the middle between conflicting State and Commission requirements. Moreover, Santa Clara notes that some State commissions do not represent all energy consumers, since they are charged only with regulating public utilities, and could be conflicted and disinclined to act in the best interests of entities not under their jurisdiction.

572. NARUC supports active State commission participation in both RTO and non-RTO markets.\335\ NARUC asks that the Commission clarify that its planning proposals assume that the results of State commission planning decisions relating to retail load will be incorporated into the planning process rather than subject to further review. NARUC and New Mexico Attorney General also ask for clarification that joint planning will allow for communications between resource and transmission planners for the purpose of developing State-required resource plans and that this will not be considered a violation of the Standards of Conduct. PNM-TNMP and Southern support the NARUC position in their reply comments.

\335\ Similar views are expressed by APPA, Arkansas Commission, Bonneville, California Commission, NCEMC, NYAPP, and CREPC. NYAPP, however, asks the Commission to be vigilant in not allowing State commissions improper control over the planning process.

573. New York Commission wants to ensure that the Commission's planning responsibilities cover only transmission that serves a bulk power system function.\336\ Florida Commission believes that it already has direct oversight of grid planning and related issues, through among other things its participation in the FRCC planning process and review of the annual Ten Year Site Plan. Seattle does not believe that any additional requirements are needed for State commission participation. Other commenters are concerned that State policy goals, such as California's Renewable Portfolio Standard, be included in the coordinated planning required by the Final Rule.\337\ NARUC and California Commission also discuss State staff and fiscal constraints on participation, and California Commission suggests that the Commission consider a tariff rider to fund State participation.

\336\ NYAPP, on the other hand, urges the Commission to require planning for all transmission facilities, not just bulk power facilities.

\337\ E.g., AWEA, California Commission, and Project for Sustainable FERC Energy Policy.

Commission Determination

574. The Commission strongly encourages State participation in the transmission planning process and expects that all transmission providers will respect states' concerns, such as retail resource needs, in the planning

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process.\338\ As with any other interested stakeholder, we emphasize that planning must be coordinated with relevant State regulators (including city councils, local siting boards, and other agencies) that wish to participate in the transmission provider's planning process. We will not prescribe a particular level of State participation, but rather encourage states to determine their own level of participation, consistent with applicable State law.\339\ We stress that State determinations with respect to retail load will not be second-guessed, but that once those determinations are incorporated into the transmission plan, the transmission planning principles will apply (e.g., for purposes of determining whether similarly-situated customers are treated comparably).

\338\ As noted above, we expect the concerns of NARUC and others that the application of the Commission's Standards of Conduct are inhibiting State resource planning will be addressed in the rulemaking proceeding on the Standards of Conduct in Docket No. RM01-7-000. See supra note 257.

\339\ We also recognize that there are concerns about how State regulators and other agencies will recover the costs associated with their participation in the planning process. As discussed below, we direct transmission providers to propose a mechanism for cost recovery in their planning compliance filings. These proposals should include relevant cost recovery for State regulators, to the extent requested.

575. Just as we intend to coordinate with State regulators and other agencies, we also encourage those parties to collaborate amongst themselves as well, particularly regionally, in order to reach agreement on how best to review and approve new transmission facilities that are the product of the coordinated and regional planning process required by this Final Rule. We intend to defer to such agreements between State regulators and other agencies in a given region as appropriate. We are, moreover, sensitive to concerns, such as Allegheny's, about the overlapping nature of regulatory jurisdiction over planning matters. We believe the planning principles in this Final Rule will help alleviate this concern by facilitating coordination through open, transparent planning and enhanced exchange of information. We also understand Santa Clara's concern that certain State regulators do not represent all energy consumers in some states; however, we do not believe this detracts from the significant interest that State regulators and other agencies have with regard to transmission planning for their State and region. c. Flexibility in Implementation and Examples of Compliant Processes

576. In the NOPR, the Commission sought comment on how much flexibility the transmission provider should be given in implementing the principles and requested examples of transmission planning processes that comply with the proposed principles. Comments

577. Commenters generally favor flexibility and urge the Commission not to be too prescriptive regarding how the planning processes must satisfy the planning principles. Many entities in the Western Interconnection cite the overall WECC process as largely compliant with the principles. Nevada Companies notes that the WECC process works well under the existing pro forma OATT, so that few changes should be required to implement the proposal. In the East, Progress Energy and Duke cite NC Transmission Planning as an example of an effective planning process that generally meets the principles.

578. Constellation agrees with providing flexibility, but believes the Commission should strongly encourage transmission providers to model their compliance filings after existing processes, such as those in RTOs and ISOs. ISO/RTO Council and all individual RTOs and ISOs argue that their processes are generally compliant and should not be disturbed. Transmission providers in RTOs and ISOs generally support this position.\340\

\340\ E.g., Allegheny, Duke, and National Grid.

579. Some entities believe that flexibility should be permitted in order to deal with regional variations, but that individual transmission providers should have limited flexibility in implementing the planning process.\341\ Some commenters simply state that regional flexibility should be permitted, without further elaboration.\342\ Other commenters urge the Commission to limit both regional and local flexibility.\343\

\341\ E.g., APPA, East Texas Cooperatives, Seattle, and TDU Systems.

\342\ E.g., Bonneville, Salt River, PJM, and TVA.

\343\ E.g., Arkansas Municipal, Project for Sustainable FERC Energy Policy, and Southwestern Coop.

580. NRG argues that system planning models should reflect economic dispatch to facilitate efficient utilization and also argues in favor of requirements for specific criteria on the treatment of system overloads and contingencies. AWEA proposes a specific regional planning protocol patterned off the ``Collaborative Governance'' model developed during mediation for the Southeast RTO in Docket No. RT01-100.

581. In reply to commenters arguing in favor of less flexibility, Indianapolis Power maintains that its experience in MISO shows that flexibility is needed, citing the wide variations within the MISO footprint and the difficulties experienced in planning for a single large region. MidAmerican opposes the NRG proposal for regional modeling standards, as well as the AWEA proposal for a regional planning protocol, as too burdensome. Exelon expresses general agreement with the EEI position on flexibility, but states that planning processes outside RTOs do not presently meet the NOPR's requirements. Exelon states planning processes outside RTOs should follow the planning direction of RTOs like PJM. Commission Determination

582. Although we allow flexibility in the development of a coordinated and regional planning process, the Commission will carefully review transmission planning compliance filings to ensure that each planning process is consistent with the planning principles and other requirements in this Final Rule. We encourage transmission providers to give consideration to existing planning processes, such as those already implemented by ISOs or RTOs, or those proposed by AWEA, as they work with their customers and other stakeholders to develop a transmission planning process that complies with the Final Rule. The Commission makes clear, however, that we do not endorse any specific existing process as a model for all transmission providers. d. Recovery of Planning Costs

583. In the NOPR, the Commission recognized that participants in the planning process must be assured of recovery of their costs incurred in the planning process, as well as assured that the costs will be borne equitably by all parties benefiting from the process. The Commission also sought comment on whether there should be a principle or requirement regarding cost recovery and allocation associated with funding the regional planning requirement. Comments

584. Public utility commenters generally support the principle that costs should be borne by the beneficiaries of the process. EEI agrees, but argues that the Commission should not establish a specific cost basis for recovery, and several other commenters concur.\344\ NorthWestern and PSEG support a cost causation principle for

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allocation of costs of planning, and Southern argues that entities that request any transmission sensitivity studies should bear the costs of those studies.

\344\ E.g., Duke, Indianapolis Power, MidAmerican, Progress Energy, PSEG, South Carolina E&G, and SPP.

585. There is general agreement with the principle that costs should be recoverable, and some public utilities request that the Commission clarify that all planning costs not directly assigned are recoverable through transmission provider transmission rates.\345\ Other commenters believe that the parties in the planning process should determine how planning costs should be allocated and funded. APPA urges simplicity, the avoidance of double collecting (e.g., LSEs should not have to pay through both transmission rates and individually) and stresses the need to assess costs based on size and assets. Other comments are consistent with equitable allocation of planning costs.\346\

\345\ E.g., Southern and South Carolina E&G.

\346\ E.g., Bonneville, NRECA, and CREPC.

Commission Determination

586. We will not propose a specific method for recovery and allocation of planning costs in this Final Rule. We recognize, however, the importance of planning cost recovery and will require transmission planning processes to provide a mechanism for recovery of costs. We direct transmission providers to work with other participants in the planning process, as part of the collaborative process described above, to develop their cost recovery proposals in order to determine whether all relevant parties, including State agencies, have the ability to recover the costs of participating in the planning process. Transmission providers should also consider whether mechanisms for regional cost recovery may be appropriate, such as through agreements (formal or informal) to incur and allocate costs jointly. The Commission will consider resulting cost recovery proposals, including special riders to transmission rates, with an eye toward encouraging the broadest participation in the planning process possible. e. Open Season for Joint Ownership

587. In the NOPR, the Commission expressed its belief that an open season to allow market participants to participate in joint ownership, particularly for large new transmission projects, could stimulate grid investment and ensure that all customers have the ability to participate in new projects on a nondiscriminatory basis. The Commission sought comment on whether to include such a requirement and, if so, what conditions or limitations should be associated with it. Comments

588. As a general matter, a number of commenters believe that the planning process should include a mandate to construct identified upgrades or otherwise hold transmission providers accountable for carrying out the plan.\347\ EEI and others argue that such a mandate would go beyond planning and result in providers giving up control of their systems. In their replies, LPPC and Sacramento assert that the decision to build facilities and to carry out transmission plans must rest with transmission providers and State authorities and that, in any event, it is unclear that the Commission has the authority to compel construction pursuant to regional transmission plans. At the October 12 Technical Conference, there was considerable discussion of the obligation to build and its relationship to the planning process proposed in the NOPR.

\347\ E.g., APPA, East Texas Cooperatives Reply, FMPA, NCPA, TAPS, TDU Systems, Utah Municipals, and WIRES.

589. While not necessarily opposed to voluntary joint ownership arrangements in general, many commenters oppose the idea of mandated open seasons.\348\ EEI provides a representative summary of the arguments of those opposed to open seasons. First, EEI argues that the Commission does not have the authority to order joint ownership and that joint ownership could interfere with State siting authority. It maintains that the instances where the Commission can order transmission construction are very limited and do not extend to the authority to order joint ownership.\349\ Second, EEI argues that joint ownership will not provide the benefits cited by the Commission, stating that there is ample evidence that joint ownership of transmission lines is not needed to achieve economies of scale in construction. In its view, the level of transmission investment is currently increasing and joint ownership should not be expected to create additional sources of transmission investment. Third, EEI contends that prospective joint owners mistakenly believe they will not be subject to the same requirements as Commission-jurisdictional owners and urge the Commission to make clear that both jurisdictional and nonjurisdictional owners would be subject to the same requirements for service over jointly-owned facilities. If the Commission were to order joint ownership, Duke argues that it must condition such ownership by a nonjurisdictional entity on that entity filing a safe harbor OATT ensuring reciprocal open access by that joint owner.

\348\ E.g., Allegheny, American Transmission, Constellation, New York Transmission Owners, MidAmerican, Duke, EEI, Entergy, FirstEnergy, MISO, National Grid, Northeast Utilities, NorthWestern, Progress Energy, PSEG, South Carolina E&G, SCE, Southern, SPP, Tacoma, Tucson, and Xcel.

\349\ APPA, FMPA, TAPS, and TDU Systems, however, point to various sources of authority on which the Commission could rely to mandate open seasons and joint ownership, such as: To remedy undue discrimination under FPA sections 205 and 206; to carry out FPA section 214(b)(4)'s requirement to facilitate the planning and expansion of transmission facilities to satisfy the needs of load- serving entities; as a condition of market-based rate authority, FPA section 203 approval, or transmission rate incentives under FPA section 219; and under the permitting regulations promulgated under FPA section 216(c)(2)(B) dealing with backstop siting authority.

590. Tacoma notes that ColumbiaGrid includes a mechanism for small users to participate in transmission projects in the proposal it is considering for its planning process. Xcel supports adopting the open season concept as an option in joint planning requirements. Though it does not completely oppose the principle, MidAmerican sees significant practical problems in developing and implementing an open season proposal and regards the open season idea as premature. Others generally support allowing for open seasons and joint ownership, but also do not believe they should be mandated.\350\

\350\ E.g., Bonneville, California Commission, and CREPC. Bonneville stresses that any jointly-owned facilities should have a single operator.

591. A number of other commenters, however, support requiring open seasons as a method of ensuring that identified upgrades are constructed. ELCON is strongly in favor, stating that open seasons for joint ownership is an ``idea whose time has come'' and expressing frustration that the Commission has not already acted on this proposal. FMPA argues that joint ownership will aid in providing additional capital for transmission projects. TDU Systems urge the Commission to require transmission providers, including RTOs and ISOs, to hold open seasons.\351\ Joined by Arkansas Commission, TDU Systems argue that open seasons should not be limited to large projects. PGP supports open seasons when providers do not voluntarily agree to add capacity based on the results of the transmission plan. TDU Systems cite the Neptune and

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Cross-Sound Cable projects, where regulated utilities failed to provide solutions despite the need for expansion of the system in those regions. Seattle argues that voluntary joint ownership of projects should not be contingent upon an open season requirement. TANC points to current joint ownership arrangements in the Western Interconnection. Sacramento likewise notes that the joint planning and ownership process in the Western Interconnection has been a success, but asks the Commission to make clear that physical rights set asides are available in CAISO to accommodate non-LMP co-owners.

\351\ Similar comments were made by APPA, Arkansas Commission, FMPA (includes a legal analysis in an attachment), NCPA, MISO/PJM States, Santa Clara, Southwestern Coop, TANC, and TAPS.

592. On reply, EEI, Entergy, and Southern repeat arguments against joint ownership and open seasons. EEI replies that FMPA's claim that joint ownership will result in increased investment is not based on fact and will not increase access. In its reply, TDU Systems states that joint ownership would not, as argued by EEI, infringe on State siting, as states would retain this authority over the jointly- developed project. APPA also stresses that its members have fewer difficulties obtaining service where joint ownership is permitted. In their replies, Lassen, Santa Clara, and TANC argue that the Commission should not, as suggested by Duke, condition the participation of a nonjurisdictional entity in a jointly-owned project on that entity filing a safe harbor OATT, as public power entities use the capacity they need and sell the rest whether or not they have a safe harbor OATT on file. However, TAPS asks on reply that access to jointly-owned facilities be available through a pro forma OATT. Participants at the October 12 Technical Conference expressed both support for joint ownership, as well as caution. National Grid states that it has had good success with joint ownership, but that jointly-owned projects are more complicated and can take longer to develop. Commission Determination

593. The Commission believes there are benefits to joint ownership of transmission facilities, particularly large backbone facilities, both in terms of increasing opportunities for investment in the transmission grid, as well as ensuring nondiscriminatory access to the transmission grid by transmission customers. The comments received in response to the NOPR support the notion that joint ownership can provide these benefits in many cases. For example, as TDU Systems note, the Neptune and Cross-Sound Cable projects have resulted in significant amounts of new transmission capacity in regions facing chronic constraints. We encourage joint ownership for other large backbone transmission upgrades included in the transmission plan developed by the planning process required by this Final Rule.\352\

\352\ As the Commission stated in Order No. 679-A, ``[t]he Commission will look favorably on incentive requests that include public power joint ownership.'' Order No. 679-A at P 102.

594. We acknowledge, however, that joint ownership can increase the complexity of planning and developing a transmission project and are sensitive to concerns that formal open seasons can add to that complexity. We therefore do not mandate open season procedures to allow market participants to participate in joint ownership. We recognize that there may be reasons, given the complexity of the transmission grid and changing conditions of supply and demand for power, why any given facility identified in a transmission plan may not ultimately be constructed. Consequently, our planning reforms do not include an obligation to construct each facility identified in the plan, whether individually or through joint ownership mechanisms. At the same time, the Commission agrees that joint ownership may be useful in certain situations and encourages transmission providers and customers alike to consider the use of open seasons to realize construction of upgrades identified in the planning studies. If a transmission provider declines to construct an identified upgrade, we also encourage customers and third parties to consider, either individually or jointly, development and ownership of a project to the extent consistent with applicable State law. f. Specific Study Processes Beyond Reliability and Congestion Reduction

595. In the NOPR, the Commission sought comment on whether there should be a specific study process to identify opportunities to enhance the grid for purposes beyond maintaining reliability or reducing current congestion. Such a study process could allow interested entities, including State resource agencies and others, to request the transmission provider to model grid upgrades needed to accommodate the construction of new resources and provide information needed to proactively evaluate such resources. The Commission expected that such studies would not conflict with State prerogatives, but rather would provide states with better information to evaluate all relevant resource options. Comments

596. Most transmission provider commenters favor providing for study of some grid enhancement beyond reliability and congestion- related needs, but believe the Final Rule should not mandate a specific study process. Various commenters argue that the Commission should allow planning participants to determine details such as the scope, number, and cost responsibility for the studies.\353\ MISO states that it is working on these issues, but enhancement beyond maintaining reliability or reducing congestion is a complicated subject best left to each RTO or ISO to decide.

\353\ E.g., EEI, MISO, NorthWestern, PSEG, and Tacoma.

597. Some commenters are more explicit or expansive in their recommendations. CAISO recommends that the Commission develop a policy to encourage construction of transmission lines necessary to connect renewable resources,\354\ and Suez Energy NA provides similar comments about new remote generation. PJM believes the planning process should look at future congestion and building for resources not yet announced. The New Jersey Board believes that demand-side management and other solutions, such as distributed renewable generation, also should be considered. WIRES and ELCON believe all credible proposals should be studied. TAPS asserts that planning should study grid enhancements needed for new potential resources.\355\ These views are consistent with the views of many of the commenters that support additional study processes.\356\ TDU Systems, however, point out that planning for reliability and economics should be incorporated into the open and inclusive planning process and, therefore, a special study process should not be needed.

\354\ Related to this, California Commission asserts that regional planning processes need to be closely linked with the resource adequacy planning processes and renewable energy portfolio standards on the State level.

\355\ EEI replies in opposition to TAPS' assertions that planning should address transmission for potential resources, arguing that such a requirement would be cost prohibitive and would harm users.

\356\ E.g., APPA, Arkansas Commission, AWEA, CREPC, Sacramento, and Seattle.

598. Other commenters are opposed to additional processes: South Carolina E&G does not see a need for additional studies; Southern believes additional study processes would be overly burdensome and would divert attention away from the fundamentals of prudent planning; and Bonneville notes that market participants often make requests

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for expensive studies without following through on them. Santee Cooper cautions the Commission against giving license to those who would attempt to hijack the regional planning process in order to advance a generation-related agenda, and notes that the Commission's authority does not extend to generation resource adequacy. Commission Determination

599. We believe that development of a study process for identifying opportunities for grid enhancement beyond reliability and congestion reduction has the potential to provide useful information and would generally benefit development of the transmission grid. We therefore will include such study processes within the scope of Principle No. 8. In the NOPR, that principle concerned only congestion studies, but, as modified above, it now includes studies regarding upgrades that could integrate new generation resources. We note that various commenters argued for the consideration of demand resources in development of enhancements to the transmission grid.\357\ As we explain above, consideration of such resources falls within Principle No. 8, as modified by the Final Rule.

\357\ E.g., New Jersey Board, Ohio Power Siting Board, and WIRES.

g. Level of Detail in the OATT

600. In the NOPR, the Commission sought comment on the level of detail to be required to be in the transmission provider's OATT regarding its planning process. Comments

601. Several commenters argued that the details of the planning process should be included in the transmission providers' OATTs.\358\ Seattle noted that the OATT should balance the need for detailed planning requirements with the need for regional processes to evolve.

\358\ E.g., APPA, NRECA, Old Dominion, and Seattle. APPA also suggests OASIS posting.

Commission Determination

602. The Commission agrees that the transmission planning attachment to a transmission provider's OATT must include sufficient detail to enable transmission customers to understand the transmission provider's planning process. This new attachment must therefore include:

(a) The process for consulting with customers and neighboring transmission providers;

(b) The notice procedures and anticipated frequency of meetings or planning-related communications;

(c) A written description of the methodology, criteria, and processes used to develop transmission plans;

(d) The method of disclosure of transmission plans and related studies and the criteria, assumptions and data underlying those plans and studies;

(e) The obligations of and methods for customers to submit data to the transmission provider;

(f) The dispute resolution process;

(g) The transmission provider's study procedures for economic upgrades to address congestion or the integration of new resources; and

(h) the relevant cost allocation procedures or principles. C. Transmission Pricing 1. General

603. As the Commission explained in Order No. 888, the pro forma OATT was designed to include primarily non-rate terms and conditions of open access non-discriminatory transmission service. Transmission providers first were required to adopt the non-rate terms and conditions of the pro forma OATT and then, in a subsequent filing under FPA section 205, to propose corresponding rates for service provided under their OATTs. Consistent with the focus of Order No. 888 on the non-rate terms and conditions of open access, the Commission did not propose broad reform of transmission pricing policy through the NOPR. Rather, the Commission identified in the NOPR several discrete pricing rules that it considered part and parcel of OATT service that merit reform, which we discuss in more detail later in this section. The Commission also specifically noted in the NOPR that the purpose of this rulemaking is to strengthen the pro forma OATT to remedy undue discrimination and not to create new market structures.

604. Despite the clear scope of this rulemaking, several commenters contend that broader ratemaking reforms should be implemented in order to remove obstacles to achieving competitive markets. Various commenters assert that rate pancaking must be eliminated in this reform, noting that the Commission has recognized in the past that pancaked rates inhibit the development of competitive markets.\359\ Arkansas Municipal and TDU Systems contend that pancaked rates are particularly burdensome for customers with loads and resources on multiple transmission providers systems and those that sit essentially at or on the boundaries. TDU Systems argue that the failure to eliminate pancaked rates has caused many of the TDU Systems to spend many millions of dollars to build transmission from generation to interconnect with multiple control areas in order to avoid paying multiple wheeling charges.

\359\ E.g., Arkansas Municipal, AWEA, FMPA, and TDU Systems.

605. Some of these commenters also advocate that the Commission should move towards joint rates.\360\ Arkansas Municipal Power argues that moving toward joint rates outside an RTO will not only eliminate competitive barriers outside RTOs, but would reduce the disincentive to formation of new and expanded RTOs. TAPS complains that the NOPR requires regional planning, but has no provision requiring transmission providers to build facilities to support regional needs, arguing that joint rates would ease this problem. TDU Systems argue, however, that any joint rate methodology should not shift costs to other network customers, especially where surcharges are sought that might open the door to potential over-recovery by transmission providers as argued in the PJM/MISO proceedings. Old Dominion also contends that the Commission should add a requirement in the pro forma OATT that regional transmission costs be recovered through a single regional transmission rate of a rolled-in nature. Relative to cost recovery, Old Dominion believes that rolled-in zonal rates work for local facilities within a single transmission owner footprint, but regional rolled-in rates would be necessary for larger footprints.

\360\ E.g., Arkansas Municipal, TAPS, and TDU Systems.

606. Old Dominion also contends that the lack of periodic review by the Commission of stated transmission rates sends a strong economic signal to transmission owners to not invest in new transmission. Old Dominion argues that the Commission should require periodic rate reviews at least every five years or implement formula rates which would remove economic incentives for failing to build transmission.

607. EEI argues that the Commission should not address in this proceeding TDU Systems' proposal to require transmission providers to eliminate pancaked transmission rates in non-RTO regions because it involves complex issues that are not easily resolved. EEI contends that transmission providers should not be required to eliminate multiple transmission rates across multiple systems simply to allow TDU members to avoid the economic consequences of their decisions to

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purchase energy from off-system resources.

608. Other commenters ask the Commission to institute much broader market reforms in this rulemaking, arguing that the Commission will not be able to achieve its objectives of remedying undue discrimination and developing competitive wholesale markets without a fundamental change in market structures. Several commenters advocate changing the market structure in non-RTO markets to allow transmission customers to access the transmission provider's dispatch and redispatch options.\361\ Some commenters \362\ go further to assert that the Commission require the use of locational marginal pricing (LMP) as a part of OATT reform. Other commenters \363\ assert that the Commission would not need to adopt a full RTO market design to achieve its more limited objectives, but contend that eliminating the fundamental inconsistency between the OATT rules and actual operation of the grid would remove a major obstacle to other reforms. Several commenters \364\ contend that requiring use of a security constrained economic dispatch is a needed part of this reform.

\361\ E.g., Chandley-Hogan, Constellation, and PJM.

\362\ E.g., Morgan Stanley and Steel Manufacturers Associations.

\363\ E.g., Chandley-Hogan and PJM.

\364\ E.g., EPSA and Chandley-Hogan.

609. Chandley-Hogan contend that the key element to ensuring transmission services are provided on a just, reasonable and not unduly discriminatory basis is to provide open access to the security constrained economic dispatch and the associated imbalance pricing that arises from that dispatch. Chandley-Hogan state that using a security constrained economic dispatch would also substantially reduce the problems inherent in the pro forma OATT's reliance on contract paths and ATC for transmission service scheduling.

610. Chandley-Hogan contend that a viable path to Order No. 888 reform is to start from the premise that open access to the dispatch (and redispatch) and marginal cost pricing for imbalances and redispatch to accommodate transmission are keys to getting open, non- discriminatory access to transmission. Chandley-Hogan argue that dispatch is the essential transmission service and providing open access to this dispatch is a path to achieving open, non-discriminatory access to transmission. Chandley-Hogan contend that a third party cannot effectively access the grid without accessing and closely interacting with the system operator's dispatch, including determining if transmission service is available, acquiring redispatch service to allow its schedule to proceed without curtailment, and settling imbalances from scheduled levels. Williams agrees with Chandley-Hogan that a system allowing non-RTO utilities to deny and curtail service requests whenever there is little ATC left and without offering redispatch to a third party is completely flawed. Williams argues that these same requests would be accommodated in an RTO through redispatch as long as the RTO has sufficient offers to arrange a security constrained economic dispatch.

611. EPSA argues on reply that an all-inclusive, ``asset-blind'' administration of open dispatch is needed to fully eliminate undue discrimination. EPSA states that security constrained dispatch will provide reliable operation and efficient utilization of the transmission grid by promoting the use of newer, cleaner and less expensive power plants. EPSA urges that these issues should be explored further here or in another policy proceeding. Project for Sustainable FERC Energy Policy asserts that there is no assurance of non- discriminatory access to transmission services and competitive wholesale markets unless load and potential competitors of the control area operators are treated comparably during dispatch. Project for Sustainable FERC Energy Policy supports additional provisions to the pro forma OATT requiring transparency and fairness in system dispatch and redispatch such as either an ``open dispatch'' requirement or a rule-based framework with standards of conduct and OASIS disclosure, as well as reporting and auditing requirement to eliminate anticompetitive incentives. Project for Sustainable FERC Energy Policy argues that sufficient data to establish marginal system costs and permit comparisons with the prices/costs of neighboring systems should be disclosed on OASIS.

612. PJM proposes open dispatch consisting of control of the dispatch function by a disinterested entity and the institution of a spot or balancing market to allow for the formation of real-time prices. Project for Sustainable FERC Energy Policy encourages the further separation of the system operator's dispatch functions from its merchant functions, to include specific dispatch transparency and comparability mandates as per PJM's and Transparent Dispatch Advocates' request. Project for Sustainable FERC Energy Policy supports comparable dispatch services through an independent entity. In its reply comments, Williams supports the rules based dispatch service proposed by PJM and states that it will reduce the opportunity for transmission providers to levy unjust and unreasonable redispatch rates.

613. PJM also contends that non-RTO/ISO systems have negative impacts on RTO systems because of the respective treatment of import transactions by non-RTOs/ISOs and RTOs/ISOs and the incidence of loop flows in market environments. PJM argues that entities scheduling flows through PJM that actually loop onto other systems nevertheless benefit financially because they collect the difference between the relatively high price at the interface where the energy is scheduled to enter the PJM footprint and the lower price at the interface where the energy is scheduled to leave the PJM footprint. When energy does not flow as scheduled, PJM states that the otherwise expected, beneficial impact on the transmission constraints are not realized, resulting in price differentials between the affected interfaces. As a result, PJM contends that such scheduled transactions only contribute to the FTR revenue adequacy issues PJM has experienced over the last 12 months.

614. PJM asserts that it is unduly preferential for a non-RTO/ISO utility to take advantage of the benefits of the organized markets of a bordering RTO/ISO without any obligation to bear any of the costs of administering those markets. PJM contends that it is unduly discriminatory and an impediment to the development of competitive markets to permit a non-RTO/ISO utility adjacent to an RTO/ISO's organized, transparent markets to accept the benefits of those markets and the regional transmission planning process that sustains them, while the same utility relies on non-market-based congestion management and limits the access of its competitors, including those who are members of the relevant RTO/ISO, to its dispatch sequence and wholesale prices within its service area. PJM asks the Commission to declare that it would not be unduly discriminatory for an RTO/ISO to include in its tariff a provision that makes an external system operator's access to those markets contingent on the external operator providing reciprocal access to its dispatch and planning functions for RTO/ISO members, as well as access to the external system's real-time marginal system cost information.

615. Transparent Dispatch Advocates propose on reply that the Commission require the industry to develop inter-

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control area coordination agreements to provide for reciprocal redispatch to alleviate constraints at specified border flowgates. Transparent Dispatch Advocates argue that redispatch over a larger area provides transmission providers more options to extract the full efficiency of their systems by allowing import/export transactions and intra-control area flows to continue that would otherwise be curtailed by providing redispatch of generation across a border at a lower cost than would result had the transaction been curtailed. Transparent Dispatch Advocates further propose that the Commission establish principles in the Final Rule to guide the development of these coordination agreements and require filing of the agreements within 12 months of the issuance of the Final Rule. Transparent Dispatch Advocates suggest that technical conferences may need to be scheduled to address any utility specific issues that arise.

616. Morgan Stanley and Steel Manufacturers Association contend that every control area should be moving toward LMP and that facing an imbalance cost measured by full replacement value of redispatch measured under LMP is the correct incentive to follow a schedule. Entegra similarly argues that customers and State regulators would benefit from more transparency regarding congestion on the transmission system and that the most efficient way to provide this transparency is to require transmission providers to apply LMP models to their systems and to post the resulting modeled LMPs.

617. Several commenters object to the proposal for a mandatory all- inclusive redispatch using bid-based pricing.\365\ These commenters generally argue that such a proposal could not lawfully be adopted in the Final Rule because it dramatically departs from the scope of the NOPR. They also argue that the proposal is bad policy because there is no record showing that consumers would benefit from the costly and disruptive implementation required for the proposal and that adoption of the proposal would create controversy given that Congress and the Commission have already rejected an LMP-based model of industry restructuring. Sacramento adds that given the record of transmission investment in RTOs, open redispatch might not meet the transmission expansion goals of the NOPR.

\365\ E.g., LPPC, Entergy, and Sacramento.

618. Southern argues on reply that there is no legal basis for claims that a lack of open dispatch results in undue discrimination. Southern states that the entities at issue are not similarly situated and that open dispatch concerns resource procurement, an area beyond the scope of the Commission's jurisdiction. Southern further argues that the open dispatch remedy proposed by PJM and others would require radical restructuring and market reforms that are unfounded, lack a legal basis and would result in political discord. Southern states that open dispatch would violate FPA section 217 by threatening the ability of LSEs to maintain access to transmission rights to serve native load. In its reply comments, Entergy states that the open dispatch proposal should be rejected because it is unnecessary to ensure open access transmission service, is contrary to the Congressional intent in passing EPAct 2005, exceeds the scope of the Commission's jurisdiction by overriding State jurisdiction over sales to retail customers, and would result in opposition that will delay other reforms and distract the Commission with divisive litigation.

619. Sacramento states that the proposals for mandatory redispatch, the control of the dispatch by a disinterested entity, and the institution of a spot or balancing market to allow for the formation of real-time prices would undermine customers' objectives to receive uninterrupted transmission service at a predictable price and ignore transmission system operational limitations. Sacramento states that the value of mandatory redispatch in the Western Grid is limited because constraints often overlap and change from thermal to voltage to stability constraints at differing load levels and redispatching large amounts of generation to relieve constraints because of the distance between loads and generation cannot be achieved in the timeframes required to maintain reliability. Sacramento is concerned that PJM's proposal would cause appropriation of generation built to serve a transmission provider's native load in order to effectuate third-party transmission transactions, strain the transmission provider's grid, and cause additional curtailment of native load and firm transactions when a force majeure event occurs.

620. Entergy cites the approval of the ICT proposal as ample evidence that the incremental approach proposed in the NOPR is a better means of improving clarity, transparency and improvements in dispatch efficiency than the Transparent Dispatch Advocates and PJM seek to mandate. Entergy states that the arguments posed by PJM and Chandley- Hogan do not target remedying discrimination or ensuring comparability, but rather focus on what they believe are mechanisms for more efficient use of the grid. Overall, Entergy does not support any changes to the basic nature of the services available under the pro forma OATT or the development of real-time markets to ensure comparable access.

621. In its reply comments, Sacramento disagrees with PJM's claims that TLRs are a discriminatory substitute for real-time redispatch and PJM's proposal to eliminate such use of TLRs in favor of an expanded redispatch obligation. Sacramento argues that firm customers under the pro forma OATT do not expect TLRs, while those in Day 2 RTOs expect that generation will be redispatched. Sacramento adds that TLRs affect all loads, but that the nature of firm physical rights service is that it will not be interrupted except in very narrow defined circumstances.

622. Southern argues that customers selling between RTO and non-RTO systems are treated equally since part of the transaction is under an LMP treatment and the other part is under OATT treatment. In response to PJM's allegations that loop flows are unduly discriminatory to its customers, Southern states that loop flows are unavoidable consequences of integrating electrical systems and that PJM itself imposes loop flows on non-RTO systems, the effects of which are not compensated by PJM. If PJM believes that entities are free-riding on its system or manipulating its system, Southern argues that PJM could seek to increase market participation charges or file a complaint with the Commission. Sacramento agrees that this rulemaking is the wrong forum for resolving seams issues given the stated scope of the NOPR. Sacramento adds that border utilities do not ``free ride'' on RTO markets because these markets impose significant costs on border entities. Sacramento also disagrees that open redispatch would resolve loop flow problems and suggests other mechanism for addressing loop flow. Finally, Sacramento states that TLRs are an Eastern Interconnection process that, although rare, occur in RTOs and non-RTO areas. Commission Determination

623. As the Commission explained in the NOPR, we do not intend to undertake a comprehensive overhaul of our transmission pricing policies in this rulemaking. Instead, the Commission proposed a number of specific reforms to discrete provisions in the pro forma OATT and a clarification to our ``higher of'' policy for pricing of transmission system expansions. Given the limited

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scope of this proceeding, we do not believe it would be appropriate to adopt the broader ratemaking proposals suggested by commenters. Issues of rate pancaking, including joint rates, regional rolled-in rates and rate reviews are beyond the scope of this proceeding.

624. Similarly, the Commission made clear in the NOPR that the purpose of the proposed rule is to strengthen the pro forma OATT to remedy undue discrimination and not to impose any particular market structure on the industry. The Commission's focus in this proceeding was and remains the development of competitive wholesale markets through the reduction of barriers to entry created through the control of transmission assets. We continue to believe that the appropriate focus of this rulemaking is to strengthen competitive wholesale markets by adopting reforms to address remaining areas of undue discrimination and issues of comparability rather than mandating a fundamental change in the market structure.

625. We therefore reject requests to institute systems that require the real-time use of regional security constrained economic dispatch and LMP for granting real-time transmission service and for the settlement of imbalances or to otherwise require transmission providers to use LMP-based modeling. We believe that LMP market designs can provide significant benefits to customers through more efficient use of the grid, but do not believe that such market designs are the only way to remedy undue discrimination or achieve comparability. We continue to support regional flexibility in market development, provided that the market design implemented by the transmission providers provides other transmission customers with comparable service to that which the transmission providers provide to their own native loads and affiliates.

626. We also reject arguments regarding seams issues creating an undue discrimination between market and non-market areas that must be resolved in this proceeding. We note that there are currently processes underway to address seams issues both in the Eastern and Western Interconnections.\366\ We believe that such seams issues are beyond the scope of this rule and are better addressed on a case-by-case basis or, as appropriate, in the proceeding on RTO Border Utility Issues.\367\

\366\ See, e.g., RTO Border Utility Issues, Notice of Technical Conference on Seams Issues for RTOs and ISOs in the Eastern Interconnections, (Docket No. AD06-9-000) (issued Jan. 25, 2007).

\367\ Id.

2. Energy and Generation Imbalances

627. In Order No. 888, the Commission concluded that six ancillary services must be included in an OATT.\368\ One of those ancillary services is energy imbalance service under Schedule 4 of the pro forma OATT.\369\ Energy imbalance service is provided when the transmission provider makes up for any difference that occurs over a single hour between the scheduled and the actual delivery of energy to a load located within its control area.\370\ The Commission recognized, in general, that the amount of energy taken by load in an hour is variable and not subject to the control of either a wholesale seller or a wholesale requirements buyer.\371\

\368\ Order No. 888 at 31,703.

\369\ Id.

\370\ See Id. at 31,960.

\371\ Order No. 888-A at 30,230.

628. The Commission found that energy imbalance service should have an energy deviation band appropriate for load variations and a price for exceeding the deviation band that is appropriate for excessive load variations.\372\ The Commission established an hourly deviation band of +/-1.5 percent (with a minimum of 2 MW) for energy imbalance. The Commission explained that this deviation band promotes good scheduling practices by transmission customers, which ensures that the implementation of one scheduled transaction does not overly burden another.\373\

\372\ Id.

\373\ Id. at 30,232.

629. With respect to compensation associated with the hourly energy deviation band, the Commission explained that, for energy imbalances within the deviation band, the transmission customer may make up the difference within 30 days (or other reasonable period generally accepted in the region) by adjusting its energy deliveries to eliminate the imbalance (i.e., return energy in kind within 30 days).\374\ In addition, the Commission explained that the transmission customer must compensate the transmission provider for each imbalance that exceeds the hourly deviation band and for accumulated minor imbalances that are not made-up within 30 days.\375\ With respect to the price of energy imbalance service, the Commission explained that it intentionally did not provide detailed pricing requirements.\376\ Instead, the Commission required transmission providers to propose rates for energy imbalance service.\377\

\374\ Id. at 30,229.

\375\ Id. The Commission further stated that the pro forma OATT permits schedule changes up to twenty minutes before the hour at no charge, and that it would allow the transmission provider and the customer to negotiate and file another deviation band more flexible to the customer, if the same deviation band is made available on a not unduly discriminatory basis. Id. at 30,232-33.

\376\ Id. at 30,234

\377\ Id.

630. Although transmission providers have different energy imbalance charges, they typically require customers to correct energy imbalances within the deviation band through return in kind or a financial settlement that requires payment for underdeliveries of energy equal to 100 percent of the transmission provider's system incremental cost for the hour the deviation occurred. For energy overdeliveries, the transmission customer would receive a payment equal to 100 percent of the transmission provider's decremental cost for the hour the deviation occurred.\378\ Outside the deviation band, transmission providers either charge the transmission customer (1) A percentage of the utility's system cost, such as 110 percent of incremental costs for underscheduling or 90 percent of decremental costs for overscheduling or (2) the greater of a percentage of system costs or a fixed charge, such as $100 per MWh.\379\

\378\ See, e.g., Arizona Public Service Co., FERC Electric Tariff, Twelfth Revised Volume No. 2, Schedule 4 (Energy Imbalance Charge), accepted in Arizona Public Service Co., Docket No. ER04- 442-003 (Sep. 30, 2004) (unpublished letter order); Public Service Company of New Mexico, FERC Electric Tariff, Second Revised Volume No. 4., Schedule 4 (Energy Imbalance Charge), accepted in Public Service Co. of New Mexico, Docket No. ER04-416-002 (Sep. 30, 2004) (unpublished letter order).

\379\ See Idaho Power Co., 102 FERC ] 61,351 (2003); Duke Electric Transmission FERC Electric Tariff, Third Revised Volume 4, Original Sheet No. 120 accepted in Duke Energy Corp., Docket No. ER04-812-001 (Jul. 2, 2004) (unpublished letter order).

631. While the Commission found in Order No. 888 that energy imbalance was an ancillary service, it also recognized that another imbalance may arise for differences between energy scheduled for delivery from a generator and the amount of energy actually generated in an hour,\380\ commonly called generator imbalance. The Commission concluded, however, that a generator should be able to deliver its scheduled hourly energy with precision and expressed concern that allowing a generator to deviate from its schedule by 1.5 percent without penalty, so long as

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it returned the energy in kind at another time, would discourage good generator operating practices.\381\ The Commission stated that a generator's interconnection agreement with its transmission provider or control area operator should specify the requirements for the generator to meet its schedule and any consequence for persistent failure to meet its schedule.\382 \

\380\ Order No. 888-A at 30,230.

\381\ Id.

\382\ Id.

632. The Commission subsequently accepted in a number of cases modifications to a transmission provider's OATT to include generator imbalance provisions.\383\ Moreover, in Order No. 2003-B, the Commission permitted the transmission provider to include a provision for generator balancing service arrangements in individual interconnection agreements.\384\ Further, in a NOPR concerning generator imbalance provisions for intermittent resources, the Commission proposed to establish a standardized schedule under the pro forma OATT to address generator imbalances created by intermittent resources and to clarify the application of the current energy imbalance provision of the pro forma OATT.\385\ In particular, the Commission proposed that generator imbalance provisions for intermittent resources would reflect a deviation band of +/-10 percent (with a minimum of 2 MW) and allow net hourly intermittent generator imbalances within the deviation band to be settled at the system incremental cost at the time of the imbalance.\386 \The Commission also reiterated its policy that a transmission provider may only charge the transmission customer for either hourly generator imbalances or hourly energy imbalances for the same imbalance, but not both.\387\

\383\ See, e.g., Niagara Mohawk Power Corp., 86 FERC ] 61,009, order on reh'g, 87 FERC ] 61,148 (1999) (Niagara Mohawk); PacifiCorp, 95 FERC ] 61,145, order on reh'g and clarification, 95 FERC ] 61,467 (2001); Alliant Energy Corporate Services, Inc., 93 FERC ] 61,340 (2000); Wolverine Power Supply Coop., 93 FERC ] 61,330 (2000); Commonwealth Edison Co., 93 FERC ] 61,021 (2000); FirstEnergy Operating Cos., 93 FERC ] 61,200 (2000), order denying reh'g & granting clarification, 94 FERC ] 61,184 (2001); Tampa Electric Co., 90 FERC ] 61,330 (2000), reh'g denied, 95 FERC ] 61,101 (2001); Florida Power Corp., 89 FERC ] 61,263 (1999); Consumers Energy Co., 87 FERC ] 61,170 (1999) (Consumers).

\384\ Order No. 2003-B at P 74-75.

\385\ Imbalance Provisions for Intermittent Resources; Assessing the State of Wind Energy in Wholesale Electricity Markets, Notice of Proposed Rulemaking, 70 FR 21349 (Apr. 26, 2005), FERC Stats. & Regs. ] 32,581 at P 9 (2005) (Imbalance Provisions Proceeding).

\386\ The Commission defined incremental cost as ``the transmission provider's actual average hourly cost of the last 10 MW dispatched to supply the transmission provider's native load, based on the replacement cost of fuel, unit heat rates, start-up costs, incremental operation and maintenance costs, and purchased and interchange power costs and taxes.'' Id. at P 9 n.17 (citing Consumers, 87 FERC ] 61,170 at 61,179 (1999)).

\387\ Under existing Commission policy, a transmission provider may only charge a transmission customer for the penalty percent adder to the incremental cost for either hourly generator imbalances or hourly energy imbalances for the same imbalance. For example, if a transmission customer has a 100 MWh point-to-point schedule in a control area, but produces 105 MWh and consumes 105 MWh, the transmission provider may charge the transmission customer 110% of its incremental cost for the 5 MWh of energy imbalance, but then must pay the transmission customer its incremental cost for the 5 MWh generator imbalance.

633. A variety of different deviation bands and pricing methods are on file for generator imbalances. Rates for generator imbalance underdeliveries range from the greater of $100/MWh or 110 percent of system incremental cost to the greater of $150/MWh or 200 percent of the incremental cost.\388\ Generator imbalance rates for overdeliveries range from 90 percent \389\ of system decremental cost to 50 percent \390\ of the decremental cost.

\388\ See Duke Energy Corp., Docket No. ER05-855-000 (Dec. 20, 2005) (unpublished letter order) (accepting Duke Electric Transmission's Large Generator Interconnection Agreement with Power Ventures Group, LLC (Duke Delegated Letter Order)).

\389\ See Entergy Services, Inc., 90 FERC ] 61,272 (2000) (concerning various generator imbalance agreements).

\390\ See Duke Delegated Letter Order.

a. Tiered Approach to Imbalance Penalties in the OATT NOPR Proposal

634. In the NOPR, the Commission noted that the existing energy imbalance charges described in Order No. 2003 are the subject of significant concern and confusion in the industry. The Commission expressed concern about the variety of different methodologies used for determining imbalance charges and whether the level of the charges provides the proper incentive to keep schedules accurate without being excessive. The Commission therefore proposed to modify the current pro forma OATT Schedule 4 treatment of energy imbalances and to adopt a separate pro forma OATT schedule for the treatment of generator imbalances.

635. The Commission proposed to create new energy and generator imbalance schedules based on the following three principles: (1) The charges must be based on incremental cost or some multiple thereof; (2) the charges must provide an incentive for accurate scheduling, such as by increasing the percentage of the adder above (and below) incremental cost as the deviations become larger; and (3) the provisions must account for the special circumstances presented by intermittent generators and their limited ability to precisely forecast or control generation levels, such as waiving the more punitive adders associated with higher deviations.

636. The Commission noted that Bonneville has adopted an energy imbalance pricing approach based on a three-tiered deviation band that appears workable for both energy imbalance service and generation imbalance service. Under this approach, imbalances of less than or equal to 1.5 percent of the scheduled energy (or two megawatts, whichever is larger) would be netted on a monthly basis and settled financially at 100 percent of incremental or decremental cost at the end of each month. Imbalances between 1.5 and 7.5 percent of the scheduled amounts (or two to ten megawatts, whichever is larger) would be settled financially at 90 percent of the transmission provider's system decremental cost for overscheduling imbalances that require the transmission provider to decrease generation or 110 percent of the incremental cost for underscheduling imbalances that require increased generation in the control area. Imbalances greater than 7.5 percent of the scheduled amounts (or 10 megawatts, whichever is larger) would be settled at 75 percent of the system decremental cost for overscheduling imbalances or 125 percent of the incremental cost for underscheduling imbalances. Intermittent resources are exempt from the third-tier deviation band and pay the second-tier deviation band charges for all deviations greater than the larger of 1.5 percent or two megawatts.

637. The Commission sought comment regarding whether this tiered approach should be adopted for inclusion in the pro forma OATT for energy and generator imbalances. The Commission specifically asked whether this approach provides sufficient incentives to ensure that transmission systems can be operated in a reliable manner and ensure that customers are treated in a just and reasonable manner. Comments

638. A number of entities generally support a tiered approach to imbalance penalties that progressively increases the penalties for imbalances, as implemented by Bonneville.\391\ These

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commenters generally state that a graduated bandwidth approach recognizes the link between escalating deviations and potential reliability impacts on the system. Other entities, however, take issue with aspects of the Commission's proposal or propose a different approach to resolving imbalances. For example, Entegra submits that the Commission should require transmission providers to establish, or permit market participants to establish, markets or pools for the netting and settlement of imbalances. Steel Manufacturers Association argues for the Commission to require real-time balancing markets.

\391\ E.g., Ameren, Northwest IOUs, Progress Energy, Suez Energy NA, Public Power Council, Sacramento, South Carolina E&G, Pinnacle, Allegheny, TDU Systems, Constellation, Imperial, and Morgan Stanley.

639. Among those supporting the Commission's proposal, Ameren asserts that the tiered approach properly allows for higher penalties for imbalances that have a greater impact on the system and thus have a greater potential to affect reliability. NorthWestern is not opposed to the generation imbalance provisions applying to all generators, arguing that imbalance charges must be based upon incremental cost and must provide an incentive for accurate scheduling. Morgan Stanley contends that basing the imbalance charge on incremental cost should be a bedrock principle for developing methods to financially settle imbalances.

640. Progress Energy, Sacramento, and Entergy encourage the Commission to allow each transmission provider to have the flexibility to craft penalty provisions that provide the right incentives to encourage their transmission customers to act responsibly. Grant similarly contends that the transmission provider must be able to decide what to charge for imbalance services and must consider the incentives for resource development and the potential for cross- subsidies paid by other customers associated with such pricing. Grant argues that transmission providers should have an ability to ``opt out'' if they can demonstrate an inability to provide the service without creating an undue burden on other ratepayers.

641. Constellation, while supporting the Commission's proposal, asks that transmission providers be required to utilize a security- constrained economic dispatch to procure and settle imbalances at least cost, which would ensure that least cost is determined on the most efficient basis. Constellation contends that imbalance charges should be based on the transmission provider's actual cost of meeting a positive imbalance or liquidating a negative imbalance, which costs can include required ancillary services and redispatch costs. Morgan Stanley states that facing an imbalance cost measured by full replacement value of redispatch measured under LMP would be an appropriate incentive. Morgan Stanley contends that the pro forma OATT should specify using opportunity cost principles to charge for imbalance solutions in those areas without LMP and come as close to mimicking the result under LMP as possible. In reply comments, Mark Lively suggests the Commission make the price for imbalances a function of the size of Area Control Error. Public Power Council recommends that transmission providers not assess penalties against loads or resources when their deviations from the schedule help the system in a given delivery hour. TDU Systems argue that inadvertent scheduling errors that do not threaten system integrity or reliability should not be penalized through charges for imbalances that exceed incremental cost in the upper tiers of imbalance bandwidths.

642. Although FirstEnergy states that the Bonneville approach for generator imbalances is appropriate, it argues that the current pro forma OATT methodology for calculating and assessing energy imbalances should be retained. FirstEnergy argues that it is more appropriate and fair to apply a graduated penalty structure to generation imbalances since greater deviations usually occur from generation. Ameren, however, believes that generators are generally better able to control their imbalances than transmission customers who take energy off of the system and that the use of a narrower deviation band may be appropriate for generator imbalances. Nonetheless, Ameren states that it does not oppose the Commission's proposal to use the same deviation bandwidths for both energy imbalances and generator imbalances.

643. Ameren contends that developing standardized provisions for generator imbalances in the OATT would eliminate the plethora of penalties that now exist. Ameren asserts that moving to a tariff approach would increase transparency and would help address the situation where such provisions may appear either in the relevant OATT or in specific interconnection agreements (at least for interconnection agreements entered into as of the date of the revised tariff provisions). Progress Energy and South Carolina E&G support separate tariff (or Generator Interconnection Agreement) provisions for these services, suggesting that generator and energy imbalance provisions could be tailored for generators and LSEs. NorthWestern states that it has long been an advocate of the inclusion of a generation imbalance OATT mechanism. TDU Systems contend that the Commission should require that the specific bandwidths and the basis for the charges be spelled out in detail in the revisions to the pro forma OATT and in each transmission provider's tariff. Allegheny argues that changing Energy Imbalance Service from Schedule 4 to Schedule 4a, adding a new Schedule 4b for Generator Imbalance Service, and eliminating proposed Schedule 9 would call attention to the fact that a transmission provider may only charge a transmission customer either an hourly generator imbalance charge or an hourly energy imbalance charge, but not both for the same imbalance.

644. Other entities contend that the Commission's imbalance proposal will not do enough to protect reliability and prevent entities from deviating from their schedules. Entergy states that the Commission should recognize that a system with significant hydro resources, such as the Bonneville system, faces different challenges in matching generation and load than a system with predominantly thermal generation. Unlike the fast ramping capability of hydro units, Entergy asserts that thermal units have a more limited ability to adjust and compensate for imbalances. Entergy adds that the Bonneville model may not provide sufficient incentives in those areas with large amounts of independent generation. In reply comments, some APPA members noted that wind variability may pose significant operational concerns that could increase regulating reserve requirements, particularly on smaller transmission systems.

645. Steel Manufacturers Association asks the Commission to delete any further reference to charges based on some multiple of incremental costs, which applies to scheduling incentives, not cost recovery. It believes that charges based on multiples of incremental costs are not necessary and do not produce rates that are just and reasonable. Steel Manufacturers Association asserts that balancing mechanisms based on real time market-clearing prices provide full compensation and adequate scheduling incentives in the organized markets and there is no reason to apply a deadband/penalty mechanism for individual OATT providers unless there is a demonstrated need, i.e., a showing that excessive gaming by LSEs or generators has been a problem.

646. Steel Manufacturers Association also contends that the current imbalance mechanism is a losing proposition for loads that cannot control energy

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consumption to match an hourly schedule of energy deliveries, with transmission providers receiving windfall revenues. It argues that the mechanism is unfair to smaller transmission systems that are not control areas (and therefore may not settle all of their imbalances through return-in-kind energy) and certain retail customers that take unbundled retail transmission service. Steel Manufacturers Association asks the Commission to institute a larger bandwidth of, at minimum, 10 percent for small wholesale customers and discrete retail loads. It contends that large utilities and wholesale transmission customers that acquire power for many discretely operated loads with varying load stages and load factors and averaging those loads creates an overall predictability to load curves that permits the practical use of a 1.5 percent bandwidth for large utilities and wholesale customers.

647. Utah Municipals assert that the Commission is wrong to believe that imbalances tend to result from carelessness or intentional conduct rather than unavoidable uncertainties and error. Utah Municipals contend that, while technology that permits perfectly accurate scheduling (i.e., namely the AGC equipment used by control area operators) is theoretically available, it is prohibitively expensive for many transmission customers and unavailable to those who do not own generation. Utah Municipals argue that financial incentives for accurate scheduling do not alter scheduling behavior or actual imbalances, but only result in a potential windfall for the transmission provider and a potentially significant competitive advantage for the transmission provider's market function, which (because of the AGC equipment that all transmission customers pay for through rates) will not be subject to the charges. Utah Municipals suggest that the Commission limit the imbalance charges for unintentional deviations by applying the third deviation band only to intentional imbalances.

648. Imperial argues that the Bonneville approach would not provide appropriate incentives for small geothermal generating units on its system to control their scheduled output, especially if imbalances are recorded on an hourly basis rather than on a cumulative basis over the course of a month. Under the Bonneville approach, Imperial asserts that it would have to pay its generators 100 percent of its incremental cost for overgeneration because such imbalances are usually less than 2 MW in any given hour. It states that using a 100 percent credit for net overgeneration would result in crediting the generator more than $28,500.

649. WECC states that it is very important to differentiate between the kind of behavior that the Commission is worried about and appropriate practices that support system reliability. WECC is concerned that inflexible generator imbalance provisions in the pro forma OATT may create incentives for generators in the West to restrict governor action on their generators in ways that degrade system reliability. WECC notes that the number of rotating machines connected to the grid in the Eastern Interconnection is much greater than in the Western Interconnection, which impacts the ability of generators to respond to maintain frequency when a system's load-resource balance changes. WECC explains that a sudden change in load-resource balance of a particular magnitude (for example, the loss of a 1,000 MW generating plant) will require a proportionately greater response from each generating unit in the West as compared to the Eastern Interconnection. WECC contends that in the West a significant frequency decline could cause responding generators to exceed a 1.5 percent deviation threshold applied under current pro forma Tariff imbalance schedules.

650. If the manner of implementing generator imbalance charges in the West does not consider the need for generators to respond to frequency deviations, WECC worries that these charges could produce perverse incentives that will undermine reliability. WECC argues that generators that use set-point controllers to override governor action will be less likely to incur imbalance charges and penalties, while those with properly operating governors may be punished for deviating from scheduled output to respond to system reliability needs. WECC believes that this has in fact been happening in the West and is one of the reasons that frequency response in the Western Interconnection has deteriorated in recent years. WECC urges the Commission to consider how generators can be given appropriate incentives to meet their obligations to supply energy to load but also to support system reliability by effectively responding to frequency deviations. WECC explains that the Commission could adopt a policy that set-point controllers should not be allowed to override governor response. WECC suggests that deviations from scheduled generator output needed to correct frequency decay could be excused from imbalance penalties under the pro forma OATT.

651. Indianapolis Power contends on reply that variation should be allowed to account for the individual facts and circumstances associated with a specific region as well as specific types of intermittent resources. A number of entities agree with providing flexibility to intermittent generators, but suggest different ways of doing so.\392\ Fertilizer Institute agrees that intermittent resources should be exempt from any penalties beyond the 90 percent/110 percent ``second tier.'' However, Fertilizer Institute also believes that intermittent resources should receive greater tolerance before they run into the 90 percent/110 percent penalty level in the first place. Fertilizer Institute urges the Commission to relax the first-tier tolerance band from 2MW to 20MW (or 40 percent of nameplate capacity, whichever is greater) for intermittent generators only. It asserts that this action is consistent with the Commission's recognition that intermittent generators can undergo sudden changes of conditions for which they cannot fairly be held responsible. Fertilizer Institute argues that a broader first-tier tolerance band for these generators will present no threat to the transmission grid, because intermittent generation facilities are limited both in size and in number.

652. Geothermal Producers supports a first-tier deviation band of +/-5 percent for intermittent resources, rather than the 1.5 percent threshold proposed by Bonneville. Geothermal Producers believes a 5 percent band is appropriate for intermittent resources, since a five percent band more accurately recognizes that intermittent resources are less capable of controlling deviations from schedules than are conventional resources. For over- or under-deliveries in excess of five percent, Geothermal Producers contends that intermittent resources should be charged no more than the control area's cost of supplying energy to correct the imbalance. Geothermal Producers also supports Bonneville's position that intermittent resources should be exempt from the third-tier deviation band and instead should pay the second-tier deviation band charges for all deviations greater than the second-tier deviation band.

\392\ E.g., NorthWestern, Fertilizer Institute, and Geothermal Producers.

653. Other commenters, however, do not support providing exceptions for

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intermittent resources.\393\ If society decides to provide incentives for intermittent resources, Morgan Stanley states that this is better done in a direct fashion, such as a certification program akin to resource adequacy rules that require LSEs to source a proportion of supply from such resources. Morgan Stanley asserts that this would motivate developers to mitigate imbalance costs through other market or technical means to the full extent of the economic signal imbedded in the imbalance price and thereby optimize the design and operation of such resources. MidAmerican argues on reply that special treatment of intermittent resources and loads has the effect of penalizing those resources and loads that have made investments to manage scheduling and enhance reliability. TDU Systems believe that the NOPR's third principle, which requires transmission providers to accord special treatment to intermittent generators, is contrary to the principle of comparability.

\393\ E.g., Morgan Stanley, Northwest IOUs, Steel Manufacturers Association, and TDU Systems.

654. Northwest IOUs argue that the transmission provider should have the option to elect whether to exempt intermittent resources from the third-tier deviation band and instead charge, in a not unduly discriminatory or preferential manner, the second-tier deviation band charge for all deviations greater than the larger of 1.5 percent or 2 megawatts.

655. Several commenters suggested that the Commission include a definition of intermittent resource in the final rule. Fertilizer Institute and South Carolina E&G contend that it is essential for the Commission to provide a clear definition of ``intermittent generation'' or ``intermittent resource'' to avoid disputes. Fertilizer Institute argues that the question of whether a given generator is ``intermittent''--and thereby entitled to the special provisions--is likely to become a source of contention. Fertilizer Institute suggests that an intermittent resource be defined as ``an electric generator that (1) Cannot store its fuel sources and (2) has limited capability to be dispatched and to respond to changes in system demand and transmission security constraints.'' EEI, however, suggests that the definition apply only to weather-driven units. Fertilizer Institute argues on reply that restricting the definition in this way would be unduly discriminatory. Fertilizer Institute argues that the definition should include the most common forms of intermittent generation--wind and solar power--as well as the less common but equally valuable forms, such as generation with ocean energy or ``waste heat'' from an industrial process. Fertilizer Institute asserts that the Commission should not broaden the definition of intermittent resource to encompass generators who are not truly ``intermittent'' and should not narrow the definition to exclude some intermittent generators in favor of others. Fertilizer Institute contends on reply that a generator should not have to be ``weather-driven'' to qualify as ``intermittent.'' Geothermal Producers supports the inclusion of geothermal energy as an intermittent resource. Geothermal Resources contends that geothermal resources satisfy both the Commission's proposed definition and the EEI proposal.

656. Ameren and Entergy ask the Commission to clarify that it does not intend to amend any existing interconnection agreements to require the use of any pro forma imbalance penalties. Entergy believes that the present form of its Generation Interconnection Agreement is absolutely critical to managing imbalances on its system and maintaining reliability. Entergy states that it has developed specialized software to monitor and manage generator imbalances and employs six system operators (one per shift) to monitor and manage generator imbalances.

657. Although Entergy supports the ``grandfathering'' of existing generator imbalance arrangements, it does not believe that it would be appropriate to require the prospective use of a different methodology while simultaneously maintaining the grandfathered arrangements. Entergy contends that administering two different generator imbalance arrangements would not be consistent with the comparability principles of Order No. 888 and would be difficult and costly from an operational perspective.

658. Several commenters \394\ argue on reply that it would be inappropriate for the Commission to grandfather existing imbalance provisions. In its reply comments, Entegra argues that prior arrangements should remain in place only if a transmission provider can demonstrate that its existing imbalance arrangements are consistent with or superior to the provisions of the pro forma OATT as modified by the Final Rule in this proceeding.

\394\ E.g., Fertilizer Institute, Entegra, and TAPS.

659. EEI and Exelon contend that the transmission provider may not be able to charge a generator under its OATT if the generator is not the transmission customer and, therefore, generators should be able to include standardized imbalance terms in agreements with eligible customers prior to providing service. Exelon suggests that the Commission both adopt in the pro forma OATT a standard imbalance penalty structure and direct transmission providers to include the same terms and conditions in their interconnection agreements with generators. TAPS suggests on reply that each generator could simply be required to sign a service agreement that requires it to comply with the generator imbalance provisions of the transmission provider's OATT. Unless the pro forma OATT governs both generator and load imbalances, TAPS argues that it would be impossible to implement and enforce the Commission's prohibition against charging both energy and generator imbalances for a single transaction.

660. ICNU argues on reply that the Commission should adopt less restrictive imbalance charges for retail access customers or, at a minimum, continue to recognize that the standard energy imbalance charge needs to be modified to accommodate direct access customers. ICNU asks the Commission to modify its proposed imbalance provision to reflect the unique characteristics of direct access customers by adopting wider imbalance bandwidths and/or waiving the more punitive adders associated with higher deviations.

661. Several entities assert that the proposed imbalance reform should not apply to RTOs. Exelon requests that the Commission explicitly state that these rules do not apply in regions that have organized markets, such as PJM, that obviate the need for imbalance penalties. They contend that within organized markets, an imbalance penalty rule is not necessary, as the independent transmission operators have effectively addressed the concerns that the proposed imbalance schedules are intended to address. Indicated New York Transmission Owners contend that the Commission should grant the NYISO a regional variation from the revised pro forma OATT with respect to imbalance charges. It contends that the existing mechanisms in ISO/RTO markets with LMP are consistent with the Commission's objectives in its NOPR and that the Commission should permit a regional variation to the NYISO. SPP states that the Commission should state that it does not intend to affect its effort to implement a real-time energy imbalance market by any final rule. SPP further contends that the Commission should clarify that its energy imbalance changes do not apply to ISOs and RTOs with organized

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markets providing for real-time energy imbalance markets. SPP believes that the Commission should view the existence of a spot energy price in organized markets as superior to penalties based on incremental costs or some multiple thereof.

662. Entegra suggests that, since many RTOs have (or are developing) separate markets for commitment costs, it may not be necessary to incorporate such costs into imbalance prices in certain RTO markets. Organizations of MISO and PJM States contend that this proposed change to Schedule 4 is not applicable in the RTO context and argue that, to the extent that the Commission's suggestions regarding the special circumstances presented by intermittent generators are applicable to RTOs, those issues are best addressed in a context other than the instant rulemaking proceeding. Commission Determination

663. In order to increase consistency among transmission providers in the application of imbalance charges, and to ensure that the level of the charges provides appropriate incentives to keep schedules accurate without being excessive, the Commission adopts in the pro forma OATT imbalance provisions similar to those implemented by Bonneville. We agree with commenters that a graduated bandwidth approach recognizes the link between escalating deviations and potential reliability impacts on the system. Furthermore, we conclude that these provisions adhere to the three principles discussed in the NOPR, which we also adopt here: (1) The charges must be based on incremental cost or some multiple thereof; (2) the charges must provide an incentive for accurate scheduling, such as by increasing the percentage of the adder above (and below) incremental cost as the deviations become larger; and (3) the provisions must account for the special circumstances presented by intermittent generators and their limited ability to precisely forecast or control generation levels, such as waiving the more punitive adders associated with higher deviations.

664. Specifically, imbalances of less than or equal to 1.5 percent of the scheduled energy (or two megawatts, whichever is larger) will be netted on a monthly basis and settled financially at 100 percent of incremental or decremental cost at the end of each month. Imbalances between 1.5 and 7.5 percent of the scheduled amounts (or two to ten megawatts, whichever is larger) will be settled financially at 90 percent of the transmission provider's system decremental cost for overscheduling imbalances that require the transmission provider to decrease generation or 110 percent of the incremental cost for underscheduling imbalances that require increased generation in the control area. Imbalances greater than 7.5 percent of the scheduled amounts (or 10 megawatts, whichever is larger) will be settled at 75 percent of the system decremental cost for overscheduling imbalances or 125 percent of the incremental cost for underscheduling imbalances.

665. The Commission adopts Bonneville's tariff provisions that provide that intermittent resources are exempt from the third-tier deviation band and would pay the second-tier deviation band charges for all deviations greater than the larger of 1.5 percent or two megawatts. We believe this is consistent with the fact that intermittent generators cannot always accurately follow their schedules and that high penalties will not lessen the incentive to deviate from their schedules.

666. Several commenters argue that the Commission should adopt a standard definition of intermittent resource. In order to clarify application of imbalance charges, we define an intermittent resource for this limited purpose as ``an electric generator that is not dispatchable and cannot store its fuel source and therefore cannot respond to changes in system demand or respond to transmission security constraints.'' \395\ We conclude that this definition of intermittent resource properly limits the exemption from imbalance charges, without excluding certain classes of intermittent generators for which the exemption is appropriate (e.g., non-weather driven intermittent resources).

\395\ See Docket No. RM05-10-000. We note that this definition was proposed by the Commission in the NOPR on Imbalance Provisions for Intermittent Resources. See Imbalance Provisions for Intermittent Resources; Assessing the State of Wind Energy in Wholesale Electricity Markets, Notice of Proposed Rulemaking, 70 FR 21349 (Apr. 26, 2005), FERC Stats. & Regs. ] 32,581 (2005).

667. The Commission believes that adopting a tiered approach for both energy and generation imbalances will best balance the needs of transmission providers to operate their transmission systems in a reliable manner with the needs of transmission customers to have reasonable access to those systems at just and reasonable rates. Furthermore, we conclude that the partial exemption from imbalance charges for intermittent resources appropriately reflects the special circumstances faced by such resources and, consequently, is not unduly discriminatory. Moreover, formalizing generator imbalance provisions in the pro forma OATT will standardize the future treatment of such imbalances from the wide variety of generator imbalance provisions that exist today in various generator interconnection agreements. Standardizing generator imbalances should lessen the potential for undue discrimination, increase transparency and reduce confusion in the industry that results from the current plethora of different approaches.

668. Several commenters debate whether the imbalance provisions adopted here should be applied to energy imbalances, generation imbalances, or both. The Commission concludes that subjecting both energy and generation imbalances to the same charges is appropriate. Energy and generation imbalances have the same net effects on the transmission system in requiring other generation to be ramped up or down to make up for the imbalance. As such, the Commission will modify the current pro forma OATT Schedule 4 treatment of energy imbalances and adopt a new separate pro forma OATT Schedule 9 for the treatment of generator imbalances, each based on the tiered structure described above. To the extent a transmission provider wishes to deviate from these revised pro forma provisions, it may demonstrate in an FPA section 205 proceeding that the proposed changes are consistent with or superior to the pro forma OATT as modified by this Final Rule. However, we note that proposed alternative provisions must comply with the three imbalance charge principles addressed in the NOPR and adopted in this Final Rule and be consistent with or superior to the specific imbalance charges set forth in the pro forma OATT (and discussed above).

669. Some commenters stated that the Commission should require transmission providers to establish, or permit market participants to establish, markets or pools for the netting and settlement of imbalances. As explained previously, the purpose of this rule is to strengthen the pro forma OATT to remedy undue discrimination and not to impose any particular market structure. If transmission providers offer to modify their OATTs to allow such pools, we will consider such proposals. But, imposing such requirements goes beyond the scope of this proceeding. The Commission therefore declines, for all these reasons, to impose the structural reforms requested by some commenters.

670. The Commission instead adopts the three-tiered approach in the pro

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forma OATT. As with other reforms adopted in this Final Rule, all transmission providers must submit compliance filings containing these pro forma tariff provisions. Transmission providers with previously- approved tariff provisions governing imbalances that no longer conform to the pro forma OATT, as revised in this Final Rule, may seek renewed approval of those tariff deviations in accordance with the procedures described in section IV.C above, demonstrating that the alternative imbalance charge structures are consistent with or superior to the reformed pro forma OATT. With respect to the concerns raised by ISOs and RTOs, we agree that LMP-based markets can provide an efficient and nondiscriminatory means of settling imbalances and, as indicated in the NOPR, we are not proposing to redesign ISO/RTO markets in this rulemaking. Nevertheless, ISOs and RTOs must follow the procedures described in the Applicability section for seeking approval of deviations that are consistent with or superior to the pro forma OATT.

671. We do not, however, abrogate existing generator imbalance agreements between transmission providers and their customers. These agreements have been negotiated between willing parties, and the Commission will not re-open them generically in this proceeding. To the extent a particular party desires to amend an existing generator imbalance agreement in light of the reforms we adopt in this Final Rule, that party may exercise whatever rights it may have under the agreement or FPA section 206.

672. With regard to WECC's frequency-response concerns, we agree that a generator should be excused from imbalance penalties that occur due to directed reliability actions by generators to correct frequency. It would not be appropriate to assess imbalance charges on generator deviations that are associated with supporting system reliability by responding to frequency deviations as directed by the transmission provider or general reliability requirements. As such, if a response from a generator (particularly in the West) is required to prevent frequency decay and the corresponding deviations from the generator's schedule would cause additional imbalance penalties, the transmission provider should exempt the generator from those penalty charges. b. Intentional Deviations NOPR Proposal

673. In the NOPR, the Commission noted that the Bonneville imbalance provision allows for greater charges when a customer has an ``intentional deviation.'' \396\ The Commission sought comment on whether the pro forma OATT imbalance provision should provide for similar penalties for behavior that represents deliberate reliance on the transmission provider's generation resources, as opposed to scheduling errors, with such penalties being subject to prior notice and approval by the Commission and based on the facts and circumstances of the individual transmission provider.

\396\ See 2006 Transmission and Ancillary Service Rate Schedules, approved in United States Dep't of Energy--Bonneville Power Administration, 112 FERC ] 62,258 (2005). The Bonneville tariff provides that ``For any hour(s) that an imbalance is determined by [Bonneville] to be an Intentional Deviation: (1) No credit is given when energy taken is less than the scheduled energy, (2) When energy taken exceeds the scheduled energy, the charge is the greater of: (i) 125% of [Bonneville's] highest incremental cost that occurs during that day, or (ii) 100 mills per kilowatthour.'' An ``Intentional Deviation'' is defined as ``a deviation that is persistent during multiple consecutive hours or at specific times of the day,'' a ``pattern of under-delivery or over-use of energy,'' or ``persistent over-generation or under-use during Light Load Hours, particularly when the customer does not respond by adjusting schedules for future days to correct these patterns.'' Id. at 46.

Comments

674. Several entities contend that higher imbalance charges and penalties for deliberately leaning on the grid can be appropriate.\397\ Imperial supports an imbalance provision that allows for greater charges for persistent or patterned deviations. Pinnacle agrees that deliberate reliance on the transmission provider's generation resources is inappropriate and could adversely affect the reliability of the transmission system, but they are unsure if such an intentional deviation could be proven. Imperial also expresses concern that the burden to prove the intent of the generator will fall on transmission providers and that, in reality, transmission providers may face an uphill battle to prove a generator's deviation was intended. South Carolina E&G and Imperial request that the Commission provide a specific process for imposing such penalties, including what procedures should be followed if a transmission provider seeks to have the Commission impose such penalties.

\397\ E.g., Imperial District Irrigation, Progress Energy and Ameren.

675. Several entities oppose penalties for intentional deviations or suggest modifications. Constellation supports an elimination of the separate penalty structure for customers deliberately leaning on the system. Constellation and Grant believe that a graduated percentage adder/discount will provide the right incentives and disincentives without the need for an intentional deviation provision. If deviation costs are properly calculated, Morgan Stanley contends that requiring those who deviate to pay the full marginal cost of that deviation would result in fair allocation of cost responsibility and sufficient stability of system operations as a result of both cost and risk avoidance by participants. TDU Systems argue that the Commission should eliminate the 100 mill per kWh floor for penalties for intentional deviations. Commission Determination

676. The Commission recognizes the need to provide transmission customers with the appropriate incentives not to intentionally dump power on the system or lean on other generation. We do not believe, however, that separate penalties for intentional deviations need to be generically imposed in the pro forma OATT. The tiered imbalance penalties adopted in this Final Rule generally provide a sufficient incentive not to engage in such behavior. Proposals to assess additional penalties for intentional deviations will continue to be considered on a case-by-case basis, subject to a showing that they are necessary under the circumstances. We note that any such tariff provisions must include clearly defined processes for identifying intentional deviations and the associated penalties. c. Calculation of Incremental Cost NOPR Proposal

677. With respect to the pricing of energy and generation imbalances, the Commission stated in the NOPR its belief that charges based on incremental costs or multiples of incremental costs would provide the proper incentive to keep schedules accurate without being excessive. The Commission proposed that incremental cost be defined to include both energy and commitment \398\ costs, to the extent additional commitments are needed.\399\

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The Commission sought comment on how such charges should be calculated, as well as how they would be applied to transmission customers. The Commission sought further comment as to how additional demand and energy costs, if incurred in responding to imbalances, such as redispatch, commitment, or additional regulation reserves, should be appropriately reflected in the calculation of imbalance charges and which customers should be charged for such costs.

\398\ The Commission noted that ``capacity commitment'' is generally defined as the generating capacity committed by a utility to provide capability for another utility to attain its reserve level. See, e.g., Central & South West Services, Inc., 48 FERC 61,197 at 61,731 n.9 (1989).

\399\ The Commission proposed defining incremental cost, based on its decision in Consumers, as the transmission provider's actual average hourly cost of the last 10 MW dispatched to supply the transmission provider's native load, based on the replacement cost of fuel, unit heat rates, start-up costs, incremental operation and maintenance costs, and purchased and interchange power costs and taxes.

Comments

678. Several entities argue that incremental pricing for both energy imbalances and generator imbalances should reflect the full incremental costs incurred by the transmission provider (e.g., such as redispatch costs, capacity commitment costs or additional regulation reserve costs) resulting from the imbalance.\400\ Allegheny questions whether the Consumer's definition is appropriate because ``the last 10 MW'' requirement is independent of the time of the scheduling deviation. Allegheny contends that the definition should be modified such that it specifically addresses the incremental dispatch to supply the transmission provider's load ``in the hour in which the imbalance occurs.''

\400\ E.g., Allegheny, Ameren, Indicated New York Transmission Owners, and FirstEnergy.

679. Entergy argues that imbalance pricing on an hourly basis does not capture all of the costs and reliability risk to the transmission provider of over- and under-deliveries. Entergy states that the real- time regulation burden imposed by IPPs is similar to the real-time regulation burden imposed by loads, and loads are charged for this cost through a transmission provider's Schedule 3 Regulation and Frequency Response Service. Entergy asserts that the NOPR does not propose any recovery mechanism for the regulation burden imposed by IPPs, recognizing that Bonneville may not face significant generator regulation costs due to the rapid ramping rate and relatively low cost of hydroelectric resources. Entergy submits that its regional experience has demonstrated that generator regulation service is a necessity. Entergy states that its generator regulation service recovers charges for the generating capacity that Entergy must maintain on-line in order to respond to the moment-to-moment deviations between scheduled output and actual generation. Entergy explains that the charge compensates Entergy on a cost-basis for the generation capacity used by IPPs, while at the same time sending the appropriate economic signal that encourages generators to match their generation with their schedules.

680. In its reply comments, EEI argues that a transmission provider should be entitled to recover the cost of additional reserves needed to meet the increased reliability requirements resulting from the provision of the imbalance energy if the transmission provider generates additional energy to compensate for a load that schedules less energy than it takes or a generator that produces less energy than it schedules. EEI further contends that transmission providers should be permitted to include in their calculation of imbalance charges any other costs associated with committing a unit that is not on-line such as minimum run times, losses, etc.

681. Entergy opposes a single price for settling over-deliveries and under-deliveries. For transmission providers who choose to base energy and generator imbalance charges on incremental and decremental costs, Entergy requests that the Commission not adopt standardized definitions of incremental cost and decremental cost in the pro forma OATT. In its reply comments, Entergy further argues that a requirement that the transmission provider post incremental and decremental cost information is unfair and harmful to the market, placing the transmission provider at an unfair competitive disadvantage in the market. Duke on reply proposes that System Incremental Cost (SIC) be used to price both over-deliveries and under-deliveries. Duke defines SIC to mean the incremental expense, measured in dollars per megawatt hour, incurred by the utility to produce or procure the next megawatt hour (MWh) of energy, after serving all of the utility's electric energy and/or capacity sales. Duke proposes that SIC shall include but not be limited to: The replacement cost of fuel; incremental operating and maintenance costs; emissions allowance replacement costs and other environmental compliance costs; the cost of starting and operating any generating units, (including costs incurred due to minimum runtimes or loading levels); purchase and interchange power costs; and all applicable taxes or assessments based on the revenues received or quantities sold.

682. Allegheny states that the Commission should clarify that the definition of incremental cost is equally applicable to intermittent generator imbalance service as well as non-intermittent generator imbalance service.

683. Pinnacle and Utah Municipals request that the Commission allow the use of alternative pricing methodologies, such as market proxy pricing methodology based on trading hubs in or adjacent to their respective control areas, where appropriate. Utah Municipals urge the Commission to make clear in the final rule that market-based pricing may be acceptable in some circumstances and to amend Schedule 4 of the pro forma OATT to ensure that imbalance charges are designed not only to provide legitimate incentives for accurate scheduling, but also to avoid unjustified penalties (masquerading as ``incentives''), to minimize the discriminatory impact of such charges, and to avoid penalizing behavior or results that in fact help to keep the system as a whole in balance.

684. TDU Systems believe the Commission should disallow recovery of demand charges or capacity commitment costs in any charges approved for imbalances. TAPS and TDU Systems argue that capacity required to follow load is already paid for by charges for regulation and reserves under Schedules 3, 5 and 6. TDU Systems also support that the Commission continue to apply its existing policy of imposing a heavy burden on transmission providers to justify such demand or capacity commitment charges in the context of a full base rate case, and of requiring transmission providers to develop alternative solutions for balancing schedules and loads.

685. To the extent transmission providers are permitted to include commitment costs in negative imbalance charges, Entegra believes that additional monitoring would be needed, to include posting of hourly imbalance charges, even if with a lag of a day or so. Suez Energy NA contends that the Commission should require a transmission owner to support its incremental cost filing on the basis of Form No. 423 data and actual operations of the selected units, based on operational data as reported in utilities Continuous Emission Monitoring reports.

686. EEI argues that since Schedule 3, 5 and 6 charges recover the costs of capacity based on test year data, they would not recover the additional costs of reserves that transmission providers incur to compensate for their customers' failures to match their schedules and their loads or generator output, and they also do not recover other commitment costs such as start-up costs or minimum run times. EEI argues that if transmission providers could not recover such costs through imbalance

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charges, they would not be able to recover them at all. Commission Determination

687. The Commission concludes that it is appropriate to define incremental cost, for purposes of the tiered imbalance provisions adopted above, as the transmission provider's actual average hourly cost of the last 10 MW dispatched to supply the transmission provider's native load, based on the replacement cost of fuel, unit heat rates, start-up costs, incremental operation and maintenance costs, and purchased and interchange power costs and taxes, as applicable.

688. In deriving such charges, we note that the Commission proposed in paragraph 244 of the NOPR that incremental cost be defined to include both additional energy and commitment costs. The Commission also sought comment on how additional demand and energy costs, such as redispatch, commitment, or additional regulation reserves, would be appropriately recovered if incurred in responding to imbalances.

689. The Commission finds that it is appropriate, through the definition of incremental cost, to allow for recovery of both commitment and redispatch costs while excluding the cost recovery of additional regulation reserve costs. Commitment and redispatch costs shall be accommodated as a part of the hourly cost of the last 10 MW dispatch and in the start up cost portion of the definition. The Commission concludes that excluding additional regulation costs as a general matter is appropriate since much of those costs would be demand costs.\401\ We believe including charges for unit commitment costs (e.g., start-up and minimum load costs) and O&M costs is necessary to ensure that both energy and generation imbalance charges reflect the full incremental costs incurred by the transmission provider. We emphasize, however, that such costs should only be the additional costs incurred by the transmission provider due to the imbalance. If applicable, start-up costs should be allocated pro rata to the offending transmission customers based on cost causation principles.

\401\ To the extent a transmission provider wishes to recover costs of additional regulation reserves associated with providing imbalance service, it must do so via a separate FPA section 205 filing demonstrating that these costs were incurred correcting or accommodating a particular entity's imbalances.

690. If the transmission provider elects to have separate demand charges assigned to customers for the purpose of recovering the cost of holding additional reserves for meeting imbalances, the transmission provider should file a rate schedule and demonstrate that these charges do not allow for double recovery of such costs. To address Entergy's concern that the real-time regulation burden imposed by IPPs is similar to the real-time regulation burden imposed by loads, we will allow transmission providers to propose separate regulation charges for generation resources selling out of the control area and consider such proposals on a case-by-case basis. We believe that the other demand costs of providing imbalance service are already being provided under Schedule 3, 5, and 6 charges.

691. In responding to Allegheny's comments, we clarify that the definition of incremental cost is equally applicable to intermittent generator imbalance service as well as non-intermittent generator imbalance service.

692. We do not believe it appropriate to require transmission providers to use market proxy pricing to calculate incremental costs in the pro forma OATT. The feasibility of using market proxies must be considered on a case-by-case basis, given the characteristics of each market. If proposed, the proxy price must represent a valid alternative to the incremental cost calculation, reflecting competitive, transparent and liquid conditions similar to those that would exist in the seller's market.\402\

\402\ See RockGen Energy, LLC, 100 FERC ] 61,261 (2002) (setting for hearing, inter alia, whether proposed market proxy price is reliable, verifiable, and also indicative of the prevailing price in liquid non-redispatch markets in the region).

d. Inadvertent Energy Treatment NOPR Proposal

693. The Commission proposed in the NOPR to continue to allow inadvertent energy to be treated differently from energy and generator imbalances, explaining that these two types of service are not comparable. The Commission noted that, given the nature of inadvertent energy and historical practices, transmission providers pay back inadvertent energy imbalances and that the Commission has accepted this practice as just and reasonable. The Commission sought comment on whether the current return-in-kind approach to inadvertent energy encourages leaning on the grid in times of shortage and, therefore, whether any reforms in this area are appropriate. The Commission asked whether pricing inadvertent energy at incremental cost (or some variant thereof) would be an appropriate disincentive and, if any reforms in this area are appropriate, whether they should be pursued under FPA section 215 as part of the review of reliability standards. Comments

694. A number of commenters support continuing to allow inadvertent energy to be treated differently from energy and generator imbalances, agreeing that these two types of services are not comparable.\403\ Allegheny argues that this historical practice makes sense because the variables germane to inadvertent interchange are beyond the control of individual transmission providers and, therefore, are best addressed in the context of reliability. Entergy notes that transmission customers have some flexibility to mitigate the deviations between their schedules and the operation of their load in real-time, while control area interchange imbalances may involve the failure of control areas to match their scheduled inflows and outflows due to contingencies occurring even in a third control area.

\403\ E.g., Entergy, Allegheny, Progress Energy, Public Power Council, South Carolina E&G, PGP, and Ameren.

695. Northwest IOUs argue that there is no reason to think that there is abuse of one system leaning on another in regards to inadvertent energy, particularly in light of Control Performance Standards 1 and 2 and other protocols for balancing flows across interconnections. Public Power Council states that in-kind return of inadvertent energy between Balancing Authorities is governed by numerous agreements and tariffs that are designed to limit the ability of one system to lean on another.

696. Sacramento states that the Commission expressed concern in other settings that generators may intentionally undergenerate during high-cost hours and make it up by overgenerating during low-cost hours under a return-in-kind approach. Sacramento contends that in kind means not only a return of energy, but a return of energy at like times and conditions and does not believe that this results in leaning. In its reply comments, Exelon requests that the Commission's imbalance penalty rules explicitly prohibit the local utility Balancing Authority operator from relying on inadvertent energy to balance its affiliated generators' schedules and thus obtaining a competitive advantage.

697. Other commenters disagree that inadvertent energy should continue to be treated differently. Exelon expresses concern that in regions without organized markets there is the potential

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for local utility balancing authority operators to seek to avoid paying deviation charges by favoring their own generators over merchant generators or by using inadvertent energy to balance their schedule. Exelon argues that a balancing authority operator could maintain system balance by choosing to order its affiliated generators to deviate from the schedule and thereby allow its affiliated generator to avoid deviation charges that the merchant generator could not avoid. If the local utility balancing authority operator relies on inadvertent energy to balance its affiliated generators' schedules, Exelon contends it is using an option that is unavailable to other generation resources and obtains a competitive advantage.

698. TDU Systems argue that energy imbalances and inadvertent interchange may occur for many of the same reasons, e.g., telemetry failure, meter error, generator governor response to system problems, human error, and under- or over-supply of generation. TDU Systems state that deviations between load and supply, whether in the form of energy imbalances or inadvertent interchange, require adjustment or compensation, but there is no reason why the form of that adjustment or compensation should be different among transmission users. TDU systems explain that NERC's Final Report of the Control Area Criteria Task Force describes inadvertent interchange as one of the ``strong incentives'' driving the newer market participants, such as independent generators, to become control areas, and driving existing control area operators to retain their functions.

699. TDU Systems explain that as the Commission acknowledged in Order No. 2000, for transmission providers in RTO regions, unequal access to balancing options can lead to unequal access in the quality of transmission service. TDU Systems oppose deferring consideration of inadvertent interchange issues until the Commission's order in the Mandatory Reliability Standards rulemaking proceeding in Docket No. RM06-16-000. TDU Systems argue that the Commission should place energy imbalance service on a footing as nearly comparable to inadvertent interchange as feasible by allowing like-kind exchanges of energy, at the incremental cost of their own supply portfolio, to remedy imbalances in lieu of the present paradigm of punitive charges.

700. TDU Systems also argue that the Commission should require comparability between transmission providers and transmission customers by imposing charges for inadvertent interchange at the suppliers' incremental cost. FirstEnergy believes that the Commission should establish a tiered penalty structure that, similar to the Bonneville method discussed by the Commission, levies penalties based on the severity of the inadvertent energy violation. TDU Systems state that currently there are no penalties for under-supply even when one control area could be deemed to be intentionally ``leaning'' on the grid to arbitrage energy market prices; but there should be.

701. FirstEnergy argues that a nationwide process should be established by the Commission to eliminate regional differences in the treatment of inadvertent energy. Constellation asks the Commission to require that transmission providers specifically separate imbalances from inadvertent energy and closely track and report the two. Commission Determination

702. As stated in the NOPR, the Commission finds that inadvertent energy is not comparable to energy and generation imbalances and, therefore, we will continue to allow inadvertent energy to be treated differently from energy and generation imbalances. Inadvertent energy represents the difference between a control area's net actual interchange and the net scheduled interchange. It is caused by the combined effects of all the generation and loads in the control area and generation and loads outside of the control area. Variables affecting inadvertent interchange often depend on the actions or the omissions of utilities other than the individual transmission providers and are distinct from those resulting in energy and generation imbalances.

703. We also note that management of inadvertent energy is needed to adhere to NAESB standards. Historically, transmission providers have paid back inadvertent interchange imbalances in kind, which has not, as a general matter, proven to be problematic. Our primary concern with respect to inadvertent energy is to avoid incentives that could degrade reliability. To date, the return-in-kind approach has proven to be adequate as a general matter. However, if there is evidence that it is no longer sufficient to maintain reliability, or is allowing certain entities to lean on the grid to the detriment of other entities, the Commission has authority under FPA section 215 to direct the ERO to develop a new or modified standard to address the matter. e. Netting/Crediting of Energy and Generator Imbalances NOPR Proposal

704. In the NOPR, the Commission sought comment on whether or not it is appropriate to allow a transmission customer to net energy and generator imbalances for a particular transaction within a single control area to the extent they offset.\404\ The Commission asked whether the potential to allow netting for offsetting imbalances contradicts the principle of encouraging good scheduling practices. The Commission sought further comment on what would be a reasonable percentage to net without concerns that allowing such netting would lead to reliability concerns from using unscheduled transmission or would cause redispatch costs by the transmission provider.

\404\ For example, the Commission noted that a transmission customer scheduling 100 MWh over an hour, but with a load of 120 MWh, would face an imbalance of 20 MW. The Commission questioned whether there should be a net charge if the customer also dispatched its generation to the same 120 MWh. Similarly, what if a transmission customer schedules 100 MWh, but has a load of 80 MWh and dispatches its generation to 80 MWh?

705. The Commission also proposed to add provisions to schedule 4-- Energy Imbalance Service and schedule 9--Generator Imbalance Service of the pro forma OATT to reflect the Commission's policy that a transmission provider may only charge a transmission customer for either hourly generator imbalances or hourly energy imbalances for the same imbalance, but not both.\405\ The Commission explained that this policy only applies to a transmission customer that otherwise would be charged for both generator imbalances and energy imbalances for the same imbalance occurring within the same control area.

\405\ Imbalance Provisions Proceeding at 32,123 note 19 (citing Niagara Mohawk, 86 FERC ] 61,009 at 61,028).

Comments

706. A number of entities believe that transmission customers should be permitted to net energy and generator imbalances to the extent that such imbalances offset.\406\ Ameren and FirstEnergy assert that netting better reflects the impact of imbalances. Morgan Stanley argues that allowing such netting provides a clear competitive benefit because it would allow competitive suppliers to offer a load following service in competition with the transmission provider. Sacramento agrees that netting of offsetting imbalances should be allowed

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provided the transmission customer relies on reasonable load forecasts.

\406\ E.g., Ameren, FirstEnergy, Xcel, Suez Energy NA, Morgan Stanley, Sacramento, TDU Systems, and Utah Municipals.

707. Utah Municipals and Steel Manufacturers Association argue that the Commission should impose charges based on netted imbalances, both for each customer and across the system as a whole. PGP contends that there is no reason to charge for both imbalances if a generator overruns during the same hour when a load overruns, so long as the overruns cancel out within a given control area. Steel Manufacturers Association contends that the Commission should incorporate control area-wide netting of imbalances to ensure that penalties are only assessed on significant imbalances and energy imbalance charges do not become a windfall profit center for utilities. Utah Municipals suggest that the Commission provide that all imbalances be netted for each hour and that penalties (charges above or credits below actual costs) be imposed only when the system as a whole is out of balance by more than a de minimis amount and, even then, only on those customers whose imbalances fall in the same direction as the system imbalance. Utah Municipals note that Sierra Pacific has established a similar imbalance mechanism, which appears to be working well in its control area.

708. TDU Systems argue that the netting rules should be sufficiently flexible to allow individual customers to net their transactions within an hour, a day, a week or a month, so long as the results keep the transmission provider economically whole. TDU Systems state that the Commission should not impose a cap on the quantity of netting allowed unless the transmission provider is able to demonstrate that good system performance requires such a cap. Ameren suggests that the Commission use a tiered system for determining when imbalances can be netted, but argues that a transmission customer should not be allowed to net offsetting imbalances elsewhere on the system if the imbalance has the potential to have a significant reliability impact.

709. FirstEnergy and Utah Municipals contend that both point-to- point and network transactions should be eligible for netting. Utah Municipals and NRECA in their reply comments note that the Commission's reference to ``a particular transaction'' does not mesh with the needs and practices of network customers, who do not attempt to match portions of their total hourly loads with particular resources or ``transactions.'' Utah Municipals argue that the Commission's proposal should be modified to make clear that such customers should be permitted to net energy and generator imbalances within a single control area to the extent they offset, with no requirement that the imbalances be part of a single ``transaction.''

710. Other commenters, however, contend that transmission customers should not be permitted to net energy and generator imbalances.\407\ For example, Entergy and Pinnacle believe that to permit netting of energy and generator imbalances is to undercut the very purpose of the imbalance provisions, which is to provide adequate incentives to schedule correctly and in accordance with good utility practice. Pinnacle asserts that, depending upon the location, energy or generator imbalances could create reliability or economic problems for specific areas of the system and it is important that the transmission operator know what is happening on its system and for the customer to adhere to accurate scheduling. SPP argues that allowing netting of imbalance energy between generation and load would allow price arbitrage that would be unjust and unreasonable. Indicated New York Transmission Owners assert that positive and negative imbalances do not actually offset, as the NOPR would suggest, but rather each imbalance independently places stress on the transmission system. Duke states on reply that, although several commenters support netting imbalances, not one entity supporting such netting has put forth a workable proposal for how to implement such netting where multiple generators are serving multiple loads.

\407\ E.g., Entergy, Pinnacle, Indianapolis Power, and Indicated New York Transmission Owners.

711. Entergy believes that independent generators must take full responsibility for meeting their own schedules, including making adjustments to their schedules to conform them to their operation in real-time. Entergy argues that a netting approach, however, would provide an incentive for a generator to over-generate above its schedule if its load proves to be greater than expected in real-time. Entergy argues that allowing the netting of these imbalances will result in the virtual elimination of transmission schedules.

712. In instances in which transmission customers intentionally game the transmission system through netting, FirstEnergy contends that the transmission provider should have the ability to apply punitive measures through a Commission-mandated penalty process. FirstEnergy states that there appears to be no clear cut number which defines the boundary between ``good'' netting and ``bad'' netting associated with reliability issues and additional redispatch cost. During periods when transmission constraints exist, Entergy contends that it may in fact be ramping up some generators to respond to imbalances while ramping down other generation to respond to other imbalances at exactly the same time and, therefore, it is incorrect to assume that over-generation supplied by one IPP accompanied by under-generation from another IPP, even simultaneously, will have no operational effect or impose no costs on a transmission provider.

713. Allegheny believes that allowing netting of hourly deviations inside the first deviation band on a monthly basis would not allow for full recovery of imbalance costs because balances that occur in on-peak periods cost more than imbalances that occur during off-peak periods. Allegheny contends that deviations within the first band should be measured and settled financially on an hourly or, at least, an on-peak/ off-peak basis, rather than allowing deviations during one part of the month to be offset by deviations in another part of the month. Indianapolis Power & Light Company argues that the imbalance volume could be within the allowed bandwidth tolerance, but still be significant enough to allow for the energy market participant to make money off of the price difference.

714. Entergy also contends that a crediting mechanism for generator imbalances would be not appropriate. Entergy asserts that such a credit would result in indifference by generators by largely immunizing them from the costs resulting from their imbalances and, as a consequence, produce economic inefficiencies and a potential threat to system reliability. Entergy argues that the current method, which provides an incentive to generators to control their own imbalances, is appropriate because generators have a desire to accurately schedule to avoid imbalances. Entergy argues that a non-offending generator in one hour can be an offending generator in the next hour and that the credit will bankroll generators so that penalty payments in one hour will be offset and paid for by penalty receipts in another hour. Commission Determination

715. The Commission recognizes that there is a trade off between the competitive benefits of reducing imbalance charges, including allowing transmission customers to net energy and generation imbalances, and the reliability implications of the transmission provider needing to plan to accommodate such imbalances.

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Allowing transmission customers to net imbalances would further comparability between the transmission provider's dispatch and the transmission customers serving load. However, netting and crediting could lessen the incentive for accurate scheduling and resulting energy or generator imbalances could create reliability or economic issues for specific areas of the system if the transmission provider cannot adequately plan for such imbalances.

716. In weighing these tradeoffs, the Commission concludes that for both energy and generator imbalance services it is not appropriate to require transmission providers to allow netting of imbalances outside of the tier one band. We agree that netting can cause problems because netting would lessen the incentive for transmission customers to schedule accurately, and inaccurate schedules, in turn, could require actions by the transmission provider even when the imbalances offset. Where transmission constraints exist, a transmission customer whose load and generation was on net equal could still have an effect on the transmission system if, as Entergy contends, some generation is ramping up to respond to some imbalances while other generation is ramping down at exactly the same time. Similarly, where transmission constraints exist, if one IPP has a positive deviation from its schedule while another IPP has a corresponding negative deviation from its schedule, the transmission provider could need to ramp up generation in one area while simultaneously ramping down generation in another area. Further, we believe that flexible scheduling deadlines should allow transmission customers to change their schedules such that their loads can be accurately met and implementation of the tiered imbalance bands will ensure that charges corresponding to imbalances are just and reasonable. f. Intra Hour Netting NOPR Proposal

717. Under the current pro forma OATT, energy imbalances occur when there is a difference between the scheduled and the actual delivery of energy to a load located within a control area aggregated over a single hour. As a result, if a transmission customer is under its scheduled level for the first half of a given hour, but over its schedule the second half of the hour, there would be no imbalance charge. The Commission did not address intra hour netting in the NOPR. Comments

718. Several commenters argue that the Final Rule should address within-hour deviations that occur when generator imbalances are calculated on an integrated hour basis.\408\ If the generator imbalance is measured over an integrated hour, as is typical of the current practice, TVA asserts that significant intra-hour swings may be masked.

\408\ E.g., TVA, South Carolina E&G, and International Transmission.

719. South Carolina E&G states that generators, unable to ramp precisely to the 15-minute schedules, often undergenerate in the initial part of the hour, then overgenerate in later parts of the hour, in order to integrate closer to the schedule when settled over the entire hour. South Carolina E&G contends these intentional swings burden the balancing authorities who are charged with continuously keeping Area Control Error within predefined limits. International Transmission argues that intentional swings in output can be quite severe, imposing operational strains on the system, negatively impacting the control area's ability to meet NERC Control Performance Standards, and potentially jeopardizing reliability.\409\ Entergy agrees that settling hourly energy imbalances with generators does not provide adequate incentives for generators to schedule and dispatch accurately within the hour. Entergy asserts that generators have imposed significant moment to moment swings within the hour requiring it to deploy its regulating reserves in response. Entergy states that it has been increasingly difficult to meet NERC's operating criteria for control area performance without committing, and incurring the costs for, additional regulating reserves. TVA contends that all generators should be required to ensure that the instantaneous generation level equals the scheduled output. International Transmission asks that the imbalance provisions in the Final Rule address this situation by either specifying penalties that may be assessed for within-hour variations or advising that transmission providers may implement their own penalties to the extent that within- hour variations cause operational difficulties.

\409\ International Transmission provides the example that a large generator with scheduled output of 100 MW for an hour might stay at zero for the first 50 minutes of the hour and then generate 600 MW during the last ten minutes.

720. South Carolina E&G contends that allowing generator imbalance settlements over a shorter period, such as at 15-minute intervals, together with the proposed tiered charges for imbalances, would provide better, more refined incentives for generators to more closely match their scheduled deliveries and would help balancing authorities reduce Area Control Error excursions. TVA suggests generator imbalances be measured on ten-minute intervals rather than integrated over an hour. These ten-minute imbalances would not be netted against other imbalance intervals, so as to avoid the problem of encouraging undergeneration followed by overgeneration and vice versa. In addition to having generator imbalance charges for generation outside the operating bands, TVA argues that there should be a separate charge assessed based on the peak generator imbalance between the scheduled and actual generation recorded instantaneously during the clock hour to provide a further incentive for proper generator scheduling.

721. Pinnacle and Utah Municipals assert that a transmission provider should only charge hourly generator imbalances or hourly energy imbalances for the same imbalance. PGP argues that customers should pay only one charge for the net imbalance that occurs within a single control area, either energy or generation, unless congestion occurs inside a control area that requires redispatch. Commission Determination

722. The Commission concludes that it is appropriate to maintain the status quo of aggregating net generation over the hour in the pro forma OATT. Requests by transmission providers to adopt a shorter interval will continue to be considered on a case-by-case basis.\410\ The Commission acknowledges that shorter intervals may be appropriate in particular circumstances and, for this reason, declined to use a clock-hour interval in the Large Generator Interconnection Final Rule.\411\ There, the Commission permitted use of an interval ``consistent with the scheduling requirements of the Transmission Provider's Commission-approved Tariff and any applicable Commission- approved market structure.'' \412\ Allowing transmission providers to continue to propose alternative intervals for purposes of the pro forma OATT imbalance provisions is therefore appropriate provided that such proposals are consistent with relevant market structures.

\410\ See Entergy Services, Inc., 102 FERC ] 61,014 (2003) and Entergy Services, Inc., 111 FERC ] 61,314 (2005).

\411\ See Order No. 2003 at P 335.

\412\ See pro forma LGIA Article 4.3.1

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g. Distribution of Penalty Revenues Above Incremental Cost NOPR Proposal

723. The Commission also sought comment in the NOPR regarding the treatment of revenues the transmission provider receives above the cost of providing the imbalance service. Comments

724. Various commenters state that the transmission provider should retain any amounts above the incremental cost of providing imbalance service. Ameren and Constellation argue such revenues should serve as a contribution towards the fixed costs of providing this service. Entergy argues that premium charges would compensate it for the administrative costs of maintaining an organization capable of providing this purchase and sales function and provide generators with an incentive to avoid mismatches between scheduled quantities and actual deliveries to Entergy. Entergy states that the Commission has previously recognized that these generator imbalance charges are analogous to the economy power rates that have historically included a percentage adder for out- of-pocket costs to recover difficult-to-quantify costs.

725. On the other hand, FirstEnergy states that the additional revenue derived from charges above incremental costs should be provided to generators and/or customers able to regulate load that provided the redispatch, commitment, or additional regulation reserves. Utah Municipals contend that the Commission should credit revenues from charges above incremental costs to accurately-scheduling customers, rather than to the transmission provider. Utah Municipals argue that the penalty portion of incremental and decremental charges and rates could be credited back to all transmission customers who incur imbalance charges and whose schedules fell within the first deviation band for that hour. Progress Energy suggests that all imbalance revenues above the cost of providing the imbalance should be distributed to all non-offending transmission customers, based on the weighted amount of each non-offending transmission customer's usage of the transmission provider's transmission system. TAPS and TDU Systems ask on reply that penalty revenues not be earmarked for retail customers.

726. Morgan Stanley believes that imbalance charges should be ``keep whole'' charges calculated and designed to reimburse whoever remedied whatever problem the imbalance caused while leaving the transmission provider financially indifferent. Commission Determination

727. In this Final Rule, the Commission has reformed existing imbalance provisions to reduce the variety of different methodologies used for determining imbalance charges and ensure that the level of the charges provide appropriate incentives to keep schedules accurate without being excessive. We also believe that transmission providers should have a consistent method of treating revenues received through imbalance penalties or charges that are in excess of incremental cost. The Commission has previously required transmission providers with significant imbalance penalties to develop a mechanism to credit penalty revenues to non-offending transmission customers.\413\ This was intended to remove the incentive of the transmission provider to hinder the development of other imbalance services that do not rely on penalties.\414\ We believe it is appropriate to maintain the requirement that transmission providers credit revenues in excess of incremental costs. Therefore, as part of their compliance filings in this proceeding, transmission providers are required to develop a mechanism for crediting such revenues to all non-offending transmission customers (including affiliated transmission customers) and the transmission provider on behalf of its own customers. Such a distribution of penalty revenues recognizes that transmission providers bear the responsibility to correct imbalances and often use their own facilities to do so.

\413\ See Carolina Power & Light Co., 103 FERC ] 61,209 at P 25 (2003) (CP&L); Entergy Svcs., 105 FERC ] 61,319, reh'g denied, 109 FERC ] 61,095 at P 65-66 (2004).

\414\ See Carolina Power & Light Co., 97 FERC ] 61,048 at 61,279 (2001).

728. We acknowledge that in the CP&L decision, the Commission declined to allow the transmission provider to allocate a share of imbalance penalty revenues to itself as a user of the transmission system on behalf retail customers. Given the reforms to the pro forma OATT imbalance provisions adopted in this Final Rule, we believe the circumstances presented in that case are no longer applicable. There, the Commission based its holding on its understanding that the high imbalance penalties imposed by the transmission provider were an interim measure that were intended to be in place only until an imbalance market was developed.\415\ In this Final Rule, we are adopting imbalance charges that are closely related to incremental cost and therefore minimize any incentive on the part of the transmission provider to rely on penalty revenues rather than seeking other methods of encouraging accurate scheduling. Under these circumstances, there remains no reason to exclude the transmission provider from receiving an appropriate share of penalty revenues.

\415\ Id.

3. Credits for Network Customers

729. In Order No. 888, the Commission established that network customers should be eligible for credits for customer-owned transmission facilities under certain circumstances. Specifically, section 30.9 of the pro forma OATT states that a network customer owning existing transmission facilities that are integrated with the transmission provider's transmission system may be eligible to receive cost credits against its transmission service charges if the network customer can demonstrate that its transmission facilities are integrated into the plans or operations of the transmission provider to serve its power and transmission customers. Section 30.9 also states that new facilities are eligible for credits when the facilities are jointly planned and installed in coordination with the transmission provider. NOPR Proposal

730. In the NOPR, the Commission proposed severing the link in the pro forma OATT between joint planning and credits for new facilities owned by network customers because such linkage can act as a disincentive to coordinated planning. The Commission proposed deleting from section 30.9 the language that permits transmission providers to refuse crediting for new network customer-owned facilities that are not part of its planning process, and adding language that puts a greater emphasis on comparability. Specifically, the Commission proposed that the network customer shall receive credit for transmission facilities added subsequent to the effective date of the Final Rule in this proceeding provided that such facilities are integrated into the operations of the transmission provider's facilities and if the transmission facilities were owned by the transmission provider, they would be eligible for inclusion in the transmission provider's annual transmission revenue requirement as specified in Attachment H of the pro forma OATT.

731. In the NOPR, the Commission also declined to allow transmission providers as part of this proceeding to automatically add costs of credits to the transmission provider's cost of service. However, the Commission stated that a

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transmission provider may propose to add an automatic adjustment clause to its rates in a filing submitted under section 205 of the FPA. The Commission also explained that it would not propose to make credits generically available to point-to-point customers that own transmission facilities, but clarified that if some facilities owned by a point-to- point customer meet all the criteria for credits, consistent with the Commission's statement in Order No. 888, the Commission would address such situations on a fact-specific, case-by-case basis.\416\

\416\ Order No. 888 at 31,742; Order No. 888-A at 30,271.

a. Severance of Credits and Planning Comments

732. The NOPR proposal to sever the link between transmission credits and joint planning by eliminating the joint-planning requirement for credits for new facilities constructed by network customers is supported by a cross-section of the industry.\417\ Exelon asserts that linking credits to network customers with coordinated planning simply creates an incentive for the transmission provider to avoid coordinated planning with the network customers so that the provider can avoid providing credits. In addition, the criterion of ``jointly planned'' with the transmission provider provides little or no value for discerning what facilities should qualify for crediting treatment. Further, Exelon argues, tying credits to joint planning is no longer necessary because the Commission's regional planning initiatives will insure that most, if not all, newly constructed facilities will be jointly planned. While EEI disagrees that the joint planning provision has acted as a disincentive to joint planning, it agrees that the coordinated planning initiatives in the NOPR has made the link unnecessary.

\417\ E.g., Allegheny, East Texas Cooperatives, ELCON, Exelon, FMPA, MDEA, MidAmerican, MISO, Suez Energy NA, Tacoma, TAPS, and Utah Municipals.

733. FMPA also argues that the link between credits and planning discourages joint planning because companies can avoid transmission rate credits, often for competitors, by simply refusing to jointly plan. FMPA asserts that it makes no sense to create economic disincentives to joint planning. According to these commenters, transmission lines cannot be built without some exchange of information; the joint planning link may discourage the most productive exchange and can create needless and non-productive disputation over whether joint planning did or should have taken place.

734. PGP points out, however, that credits for new facilities can only result from joint planning, because new facilities must be interconnected with the existing grid, and planning studies are necessary for that to happen. NorthWestern requests that the Commission reconsider its proposal to allow crediting of customer-owned facilities that have not been jointly planned with the transmission provider. NorthWestern contends that allowing the construction of network facilities and making a judgment after the fact is inefficient and will result in protracted litigation and facilities that do not serve the overall grid as efficiently as planned facilities. PNM-TNMP contends that the Commission's proposed action to ``sever the link'' will excuse the network customer from the coordinated planning process and can only operate at cross-purposes with the coordinated transmission planning goal that is addressed in the planning sections of the NOPR. Commission Determination

735. The Commission adopts the NOPR proposal to sever the link in the pro forma OATT between joint planning and credits for new facilities owned by network customers. The proposal received broad industry support, and we agree with these commenters that the link between credits for new facilities and the requirement for joint planning can act as a disincentive to coordinated planning, which is contrary to the Commission's original objective in adopting the provision. A transmission provider has an incentive to deny coordinated planning in order to avoid granting credits for customer-owned transmission facilities.

736. We find that arguments against the proposal are largely theoretical and do not adequately take into account the coordinated planning provisions proposed in the NOPR. The coordinated planning initiatives that the Commission is adopting in the Final Rule will ensure that most, if not all, transmission facilities are planned on a coordinated basis, making it unnecessary to retain this provision of section 30.9. b. The New Test to Determine Eligibility for Credits

737. Comments support the test for new facilities proposed in the NOPR.\418\ Some argue that the test for network customer credits should continue to be whether the network customer's facilities provide capability and reliability benefits to the grid--the same standard that would apply to inclusion of the facilities in the transmission provider's cost of service if the transmission provider constructed the facilities.\419\ MidAmerican states that further clarification of this point in the Final Rule would be beneficial in minimizing disputes over this issue. Likewise, MidAmerican asks the Commission to clarify in the Final Rule that such credit can be applied only to network customers taking OATT service and not to transmission customers that are under non-OATT (i.e., grandfathered bundled agreements) contracts. PGP supports the new rules for granting credits to network customers, but argues implementation details should be left up to individual transmission providers.

\418\ E.g., Allegheny, EEI, Exelon, MISO, Nevada Companies, South Carolina E&G, Suez Energy NA, and Tacoma.

\419\ E.g., Allegheny, Ameren, and MidAmerican.

738. Although several transmission providers support the continued use of the integration test,\420\ other commenters representing municipal and public power interests ask that the Commission reconsider or clarify its application.\421\ Some commenters argue that given the Commission's current interpretation of ``integration'' for transmission credit purposes and the historical application of the test, retaining any integration requirement for existing or new facilities conflicts with comparability or constitutes undue discrimination.\422\ TDU Systems argue that the integration standard has encouraged discriminatory behavior by allowing transmission providers to charge network customers for transmission provider facilities constructed to serve the transmission provider's native load, while refusing to pay the network customer for comparable customer-owned transmission facilities. TDU Systems further argue that the integration test has resulted in a form of ``and'' pricing since the TDU Systems, as network transmission service customers, remain obligated to pay their load ratio share of the full transmission revenue requirement of the transmission provider's system, including the cost of transmission facilities built to serve the transmission provider's own loads.

\420\ E.g., EEI, MidAmerican, and Nevada Companies.

\421\ E.g., FMPA, NRECA, and TAPS.

\422\ E.g., East Texas Cooperatives, NRECA, TAPS, and TDU Systems.

739. NRECA questions the Commission's statement in the NOPR that, in order to satisfy the integration

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standard, a customer ``must demonstrate that its facilities not only are integrated with the transmission provider's system, but also provide additional benefits to the transmission grid in terms of capability and reliability and can be relied on by the transmission provider for the coordinated operation of the grid.'' \423\ According to NRECA, that statement identifies three nominal requirements for customer facilities--integration, benefits and ``relied upon''--as compared to the one nominal requirement for transmission provider facilities--integration. This is fundamentally inconsistent with comparability, NRECA continues, as the Commission seems to recognize in its rationale for adding the comparability requirement to new facilities.

\423\ NRECA further notes that proposed OATT section 30.9 does not include these additional ``benefits'' and ``relied upon'' requirements. NRECA argues that these requirements cannot be part of the section 30.9, since regulatory preambles cannot vary the words of the rule, citing Wyoming Outdoor Council v. U.S. Forest Service, 165 F.3d 43, 53 (D.C. Cir. 1999) (``[L]anguage in the preamble of a regulation is not controlling over the language of the regulation itself'').

740. NRECA further argues that the NOPR failed to distinguish the proposed new standard in revised section 30.9 from the Commission's recent decision in North East Texas Electric Cooperative, Inc.,\424\ which found transmission provider facilities integrated on the grounds that a showing of any degree of integration is sufficient, rejected a ``benefits'' requirement, and did not consider a ``relied upon'' requirement. East Texas Cooperatives argues that the Commission's decision in East Texas Electric Cooperative, Inc. v. Central and South West Services, Inc.,\425\ applied an integration requirement for customer facility credits that was different and stricter than the standard applied to a transmission provider's facilities.

\424\ 108 FERC ] 61,084 (2004), reh'g denied, 111 FERC ] 61,189 (2005).

\425\ 114 FERC ] 61,027 at P 42 (2006), appeal docketed, No. 06- 1090 (D.C. Cir. Mar. 10, 2006).

741. Regarding the application of the integration component, FMPA argues that, in order to avoid continued discrimination, it is important that the Commission reaffirm that ``additional benefits to the transmission grid in terms of capability, delivery options, and reliability'' \426\ are benefits, regardless whether the transmission customers or the transmission provider (or others) benefit. Similarly, FMPA continues, the requirement that facilities must ``be relied upon for the coordinated operation of the grid'' \427\ must equally include operations that serve transmission providers, customers or others.

\426\ NOPR at P 256.

\427\ Id.

742. Comments on the comparability component of the proposed credits test for new facilities range from several requesting that the Commission adopt a comparability-driven analysis \428\ to one asking the Commission to eliminate the comparability component in favor of an integration-only analysis.\429\

\428\ E.g., APPA, FMPA, and NRECA.

\429\ Entergy.

743. Some commenters argue that eligibility for credits should turn in the first instance on the comparability standard set forth in the NOPR, otherwise the proposal does not eliminate undue discrimination.\430\ NRECA argues that this requirement does not abandon integration because current Commission policy requires a Transmission Provider's facilities to be integrated for their cost to be rolled in to the transmission provider's annual transmission revenue requirement.\431\ APPA would apply an integration test only if the transmission facilities for which the customer seeks credits are found not to be eligible under this comparability standard.

\430\ E.g., APPA, East Texas Cooperatives, FMPA, and NRECA.

\431\ NRECA compares North East Texas Electric Cooperative, Inc., 108 FERC ] 61,084 (2004), reh'g denied, 111 FERC ] 61,189 (2005) (finding transmission provider facilities integrated and rolling in their cost over transmission provider objection) with Mansfield Municipal Electric Department v. New England Power Co., 97 FERC ] 61,134 (2001), reh'g denied, 98 FERC ] 61,115 (2002) (finding transmission provider facilities not integrated and rolling out their cost over transmission provider objection).

744. TAPS states that, by eliminating the integration test and simply providing that customer-owned facilities would be eligible for credits to the extent they would be included in the transmission provider's rate base if they were owned by the transmission provider (i.e.comparability test), the Commission would avoid litigation over what (if anything) the separate ``integration'' requirement adds in the proposed formulation. If the integration terminology is retained in section 30.9, TAPS argues that the Commission at least should clarify that the new integration test is truly different from the old integration test and cannot properly be read as limiting the comparability requirement and that the Commission will not follow precedents developed in credits cases decided under the original section 30.9.

745. To provide a comparability baseline and eliminate the need for an integration test, APPA recommends that transmission providers provide a detailed inventory of the existing facilities owned by transmission provider and network transmission customers that are included in their annual transmission revenue requirement. Network transmission customers could use the inventory, which would be updated annually, to assess whether they currently own transmission facilities comparable to those included in the transmission provider's transmission rate base, or to third-party transmission facilities for which credits are being provided.

746. MDEA argues that proposed section 30.9 appears contrary to comparability principles by imposing a standard for transmission facilities owned by customers that is more stringent than the one applied to the transmission provider's own facilities. In MDEA's view, the NOPR proposal is inconsistent with prior Commission precedent to the extent comparability is not required in evaluating eligibility of existing facilities owned by transmission providers for cost recovery.\432\

\432\ MDEA cites Florida Power and Light Co., 116 FERC ] 61,013 (2006), and notes that the Commission applied principles of comparability to a transmission provider's existing facilities.

747. TDU Systems ask that the Commission clarify that the comparability prong will be aggressively enforced. For example, TDU Systems request that the Commission consider a bright-line voltage criterion to address comparability, rather than leaving it to the transmission provider's discretion as to whether the facilities would be eligible for inclusion in the transmission provider's annual transmission revenue requirement.

748. Arguing against the use of the comparability component, Entergy contends that it could cause significant confusion, and should in no way change the basic requirements needed to show integration of network customer facilities. According to Entergy, a network customer should be entitled to credits only when the transmission provider cannot meet the transmission provider's firm obligations without the customer's transmission facilities.

749. On reply, MDEA states that the principle of comparability requires that there be no distinction based on ownership or between existing and new facilities. It further asserts that Entergy attempts to draw a distinction between customer-owned transmission facilities needed by the transmission provider to meet the transmission provider's obligations to native load and firm transmission customers (for which credits should be available) and

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facilities that a network customer decides that it needs to meet its obligations. Entergy argues that credits should be available only for the former type of facility. According to MDEA, there is no justification for the distinction Entergy seeks to draw or the standard it proposes to apply. Network customers pay a full load ratio share of the embedded costs of the transmission grid, based on the premise that the entire grid is available and required to support network loads. In this regard, there is no difference between Entergy's native load and network customer loads. Transmission facilities required to meet network customer needs by definition are required to meet grid needs, provided that such facilities are integrated with the transmission network.

750. Several commenters ask the Commission to consider crediting mechanisms other than the NOPR proposal.\433\ For example, Entergy and Exelon contend that new facilities should be eligible for credit only if determined through the regional planning process that such new facilities are needed, i.e., that a measurable system capability or reliability benefit is provided. In their view, this will avoid litigation of cases addressing questions of integration. Utah Municipals argue that the Commission should not discount the potential evidentiary value of joint planning in assessing eligibility for customer credits. Taking a more expansive view, APPA argues that network transmission customers also should be able to obtain credits for transmission facilities they build pursuant to an open and collaborative transmission planning process in their region or sub- region. This additional opportunity for credits, according to APPA, would spur participation in the transmission planning process and would be superior to litigating the proper application of the integration standard.

\433\ E.g., Entergy, Exelon, and Utah Municipals.

751. Entegra argues that the Commission should make the crediting policy for network customers consistent with the Commission's policies for generator interconnection facilities, and require credits to be available for facilities that are integrated with the transmission grid, without any showing of additional benefits and irrespective of whether the service in question is interconnection service, network service, or point-to-point service. Entegra further argues that the Commission should allow customers to sell transmission credits to obtain transmission service elsewhere on the transmission provider's system. By allowing the development of a more liquid market for such credits, Entegra reasons, the Commission could increase the willingness of market participants to fund upgrades to the transmission system.

752. TDU Systems request that the Commission recognize that inequities have occurred and, if any upgrades are required to make network customers' facilities comparable (or comparably integrated), the costs of such network upgrades should be rolled into the transmission providers' rates. Commission Determination

753. The Commission declines to adopt the credits test for new facilities proposed in the NOPR. The intent underlying that proposal was to prevent application of the integration test in a manner that exclusively benefits the transmission provider.\434\ After reviewing the comments, we conclude that the proposed test may not in fact accomplish this objective. The test proposed in the NOPR may not effectively set forth the relationship of the integration standard to the comparability requirement. We therefore revise the test as follows, to more accurately reflect the Commission's intent as expressed in the NOPR: A network customer shall receive credit for transmission facilities added subsequent to the effective date of the Final Rule if such facilities are integrated into the operations of the transmission provider's facilities; provided however, the customer's transmission facilities shall be presumed to be integrated if the transmission facilities, if owned by the transmission provider, would be eligible for inclusion in the transmission provider's annual transmission revenue requirement as specified in Attachment H of the pro forma OATT.

\434\ See NOPR at P 256.

754. Under our precedent, a transmission provider's facilities are presumed to provide benefits to the transmission grid, whereas a transmission customer must make an affirmative showing that its facilities provide benefits in order to qualify for credits.\435\ Under the test we adopt in this Final Rule, a transmission customer will be required to meet the integration standard under pro forma OATT section 30.9 in order to receive a credit for its facilities.\436\ Because joint planning will no longer be required in order to obtain credits, we find that it is particularly important in this context to require a showing that a network customer's facilities provide benefits to the transmission provider's grid, i.e., a transmission customer should not be eligible for credits for facilities that the network customer may use to provide service for itself but that the transmission provider does not need to use to provide transmission service to any other customer. However, to ensure comparability, a presumption of integration will be afforded to transmission customer facilities if it is shown that, if owned by the transmission provider, such facilities would be eligible for inclusion in the transmission provider's rate base.

\435\ See e.g., North East Texas Electric Cooperative, Inc., 108 FERC ] 61,084; East Texas Electric Cooperative, Inc. v. Central and South West Services, Inc., 114 FERC ] 61,027.

\436\ The integration standard, in brief, requires that to be eligible for credits under pro forma OATT section 30.9, the customer must demonstrate that its facilities not only are integrated with the transmission provider's system, but also provide additional benefits to the transmission grid in terms of capability and reliability and can be relied on by the transmission provider for the coordinated operation of the grid. Southwest Power Pool, Inc., 108 FERC ] 61,078 at P 17 (2004) (citing Order No. 888-A at 30,271), reh'g denied, 114 FERC ] 61,028 (2006). This policy is premised on the principle that ``just as the transmission provider cannot charge the customer for facilities not used to provide transmission service, the customer cannot get credits for facilities not used by the transmission provider to provide service.'' Id. at P 20 (citing Order No. 888-A at 30,271 & n. 277); accord East Texas Coop., Inc. v. Central & South West Services, Inc., 108 FERC ] 61,079 at P 28 (2004), reh'g denied, 114 FERC ] 61,027 (2006); Southern California Edison Co., 108 FERC ] 61,085 at P 10 (2004); Northern States Power Co., 87 FERC ] 61,121 at 61,488 (1999); Florida Municipal Power Agency v. Florida Power & Light Co., 74 FERC ] 61,006 at 61,010 (1996), reh'g denied, 96 FERC ] 61,130 at 61,544-45 (2001), aff'd sub nom. Florida Municipal Power Agency v. FERC, 315 F.3d 362 (D.C. Cir. 2003).

c. Application of the New Test to Existing Facilities Comments

755. Several commenters object to the Commission's proposal to apply the new comparability test in section 30.9 to new facilities, and not to existing facilities.\437\ If the Commission requires the same integration standard for both existing and new facilities, East Texas Cooperatives ask us to specify which integration standard--the pre- existing integration standard, or the new standard that applies the integration standard comparably--applies and explain the difference and the basis for that choice. MDEA, FMPA and TAPS argue that no distinction is warranted between the treatment of new and

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existing facilities and that the same standard should apply.

\437\ E.g., APPA, FMPA, MDEA, NRECA, and TAPS.

756. TAPS clarifies that it is not suggesting that the standard be applied retroactively to past uses, but rather prospectively to existing facilities, with the key consideration being when the claim for credits is brought and not when the facilities are constructed. TAPS argues that it cannot be claimed that the revised standard should apply only to new facilities because the comparability requirement is new. To the contrary, TAPS contends that comparability has been the theme and bedrock foundation of the Commission's transmission open- access requirement since its inception.

757. APPA argues that the Commission effectively acknowledges in the NOPR that transmission providers have failed to plan new facilities jointly with their transmission customers for the last ten years under the current section 30.9, but offers no redress for this past discrimination. Commission Determination

758. We conclude that the new test for determining credits will apply only to transmission facilities added subsequent to the effective date of this Final Rule. A number of customer-owned transmission facilities have been developed, and resulting credits negotiated and litigated, under the prior test which the Commission determined to be just and reasonable at the time.\438\ We find no basis for revisiting the Commission's determinations in those cases in this Final Rule. On a prospective basis, however, given the increased planning and coordination we require in the Final Rule, we believe it appropriate to apply the new test for determining credits.

\438\ See East Texas Electric Cooperative v. Central and South West Services, Inc., 114 FERC ] 61,027 (2006).

d. Cost of Customer Facilities Automatically Included in Transmission Provider Cost of Service Without a Rate Filing Comments

759. Several transmission providers argue that, contrary to the Commission's proposal, credits should be added automatically to the transmission provider's cost of service.\439\

\439\ E.g., Allegheny, EEI, MidAmerican, and Nevada Companies.

760. MidAmerican argues that requiring the transmission provider to defer including the cost of the transmission credit until its next filed transmission rate case penalizes the transmission provider's shareholders who must unfairly bear the cost of providing the credit until the next rate case. If the Commission does not allow automatic rate recovery of the incremental cost of credits, MidAmerican continues, the Commission should clarify that the customer will not be allowed transmission facility credits until the rate adjustments are filed and accepted by the Commission. MidAmerican explains that such filings would examine only the new revenue requirements to be added and should not require a general rate case for the transmission provider's entire revenue requirement. Nevada Companies likewise argues that credits should not be granted to network customers if the recovery of those credits is not provided for in the revenue requirement.

761. TAPS agrees with the Commission's conclusion that it would not be appropriate in this rulemaking to allow transmission providers to automatically add costs of credits to their cost of service, and that such costs should continue to be evaluated as part of a regular transmission rate case (or recovered through an approved formula rate). APPA expresses concern that transmission providers may attempt to use the Commission's decision not to allow them to add the costs of credits associated with customer-owned transmission facilities automatically to their costs of service as a pretext for not granting such credits in the first instance (at least until they decide to file a new rate case). APPA continues that a transmission provider's decision not to exercise the option to file under FPA section 205 a new rate case or an automatic adjustment clause should not serve as a reason to allow it to decline to provide credits.

762. EEI explains that the customary basis for not allowing single- issue rate adjustments for new transmission facilities is that while one aspect of the transmission provider's costs may have increased, others may have decreased or load may have increased. This is not the case with respect to the inclusion of the transmission costs related to customer-owned facilities, EEI continues, since the existence of customer-owned facilities does not have any impact on the transmission provider's own cost of service. EEI concludes that a transmission provider should not be forced into what is essentially re-justifying its transmission cost of service simply because a customer receives a credit for the integration of its own facilities.

763. Some commenters also address the option currently open to transmission providers to add an automatic adjustment clause to their rates through a rate filing with the Commission.\440\ EEI argues that if the concept of an automatic adjustment clause is just and reasonable for one transmission provider, it is equally just and reasonable for all transmission providers, and there is no need to adopt a case-by- case approach. EEI further requests that the Commission clarify that its policy is to accept rate adjustments that incorporate the costs that transmission providers incur to provide credits related to customer-owned facilities, provided that the rate adjustment methodology is just and reasonable. MidAmerican contends that the revenue requirement of the transmission provider and those of transmission customers should not be co-mingled, rather, consistent with Commission precedent, the burden is on the transmission-owning customer to demonstrate to the Commission that its cost of service and revenue requirement used to establish the amount of the credit are just and reasonable before it can receive credits. As for nonjurisdictional entities, MidAmerican explains that they may file for a declaratory ruling from the Commission regarding their revenue requirement.

\440\ E.g., Allegheny, EEI, Exelon, and MidAmerican.

764. Allegheny argues that if the Commission continues to deny transmission providers an automatic adjustment clause for these credits, it should, at a minimum, assure transmission providers that transmission credits will be recognized as a cost of service in FPA section 205 rate proceedings.

765. Entergy argues that the Commission should recognize that any filed agreement providing for payments of credits would be subject to the filed-rate doctrine. Commission Determination

766. We are not persuaded to generically allow automatic recovery of the costs of credits associated with integrated transmission facilities to the transmission provider's cost of service. These costs typically are considered and evaluated as part of a regular cost of service review process. Automatic recovery of the costs of credits would be contrary to our long-standing policy concerning single-issue rate adjustments, a policy we decline to modify here.\441\ Nevertheless, transmission providers continue to have the option to propose an automatic adjustment clause in their rates under

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FPA section 205 to address the time lag between incurring costs associated with credits and the transmission provider's next rate case.

\441\ See, e.g., City of Westerville, Ohio v. Columbus Southern Power Co., 111 FERC ] 61,307 (2005).

767. Contrary to EEI's assertions, customer credits do not warrant an exception to the Commission's general policy regarding single-issue rate adjustments. EEI argues that customer credits should be treated differently because the existence of customer owned facilities, in EEI's view, does not have any impact on the transmission providers' own cost of service. Even if true, this fact would not obviate the Commission's policy. Regardless of whether the customer credit is deemed to impact the transmission provider's own cost of service, the costs it imposes may be offset by cost decreases in other areas, by load growth, or both. Allowing single-issue rate adjustments would enable a utility to increase the total rate charged by focusing solely on a single cost element, while avoiding scrutiny of all other determinants of the rate. The Commission has an obligation to ensure the justness and reasonableness of the total rate and it would be improper to allow a utility to raise rates by selectively focusing only on particular elements of its costs, while avoiding scrutiny of other rate inputs. The Commission has refused to allow such rate treatment except in the most limited of circumstances and we find no basis for deviating from that policy in this context. As explained above, a transmission provider that wishes to add an automatic adjustment clause to its rates may seek Commission approval for its methodology in a filing submitted under FPA section 205. e. Point-to-Point Customers Not Eligible for Credits on Generic Basis Comments

768. Several commenters support the Commission proposal to not make credits generically available to point-to-point customers that own transmission facilities.\442\ APPA argues that if the frequency of cases seeking credits for facilities owned by point-to-point customers is high, then the Commission should reconsider its decision to use a case-by-case approach.

\442\ E.g., APPA, Bonneville, EEI, Exelon, FirstEnergy, Nevada Companies, and TAPS.

769. Some commenters encourage the Commission to clarify that point-to-point transmission customers that pay for upgrades should be compensated if such upgrades benefit the system.\443\ PGP argues that customers be given credits if they meet the same conditions as network customers who would qualify. Additionally, Entegra contends that denying credits for upgrades funded by point-to-point customers would overlook the Commission's past warnings that a customer funding any new facilities integrated with the grid should be entitled to credits because a transmission system ``cannot be dismembered'' or examined piecemeal.\444\

\443\ E.g., FirstEnergy, Seattle, and Suez Energy NA.

\444\ Citing Nevada Power Co., 101 FERC ] 61,036 at P 8 (2002).

Commission Determination

770. The Commission adopts the NOPR proposal not to make credits generically available for point-to-point customers that own transmission facilities. As the Commission explained in the NOPR, a network customer takes a usage-based service which integrates its resources and loads and pays on the basis of its total load on an ongoing basis. The transmission provider includes the network customer's resources and loads in its long-term planning horizon and the two parties coordinate operations of their facilities through a network operating agreement. In this way, network service is comparable to the service that the transmission provider uses to serve its own retail native load, and credits for certain integrated network facilities are appropriate. The point-to-point customer, however, does not purchase integration service, nor does it sign a network operating agreement with the transmission provider. Because of the inherent differences between point-to-point and network service, we therefore decline to require that transmission providers make credits generically available to point-to-point customers that own transmission facilities. If a particular facility owned by a point-to-point customer meets all the criteria for credits, we will continue to address such situations on a fact-specific, case-by-case basis consistent with the Commission's statement in Order No. 888.\445\

\445\ Order No. 888 at 31,742; Order No. 888-A at 30,271.

f. RTO and ISO Issues Comments

771. Several RTOs or ISOs assert that they should not be required to comply with the crediting provisions because their respective planning processes and procedures are superior to or obviate the need for those set forth in the NOPR.\446\ CAISO states that it does not oppose the Commission's proposal, provided that the Commission confirms that facilities cannot be integrated into CAISO's operations unless they are under CAISO's operational control, consistent with the Commission's prior rulings.

\446\ E.g., Indicated New York Transmission Owners, ISO New England, PJM, and SPP.

772. In Xcel's view, an RTO has no incentive to refuse to jointly plan to avoid paying a credit and there is thus good cause to allow an RTO to deviate from the language in the pro forma OATT relating to joint planning of new facilities in order to be considered for a facility credit. Xcel and International Transmission argue that RTOs should be allowed to incorporate network customer-owned facilities into RTO rates in the same manner as if they were constructed by a transmission owner, while ensuring against double recovery of both revenue requirements and network credits. Commission Determination

773. The Commission concludes that it would not be appropriate at this time to generically exempt all ISOs and RTOs from the Final Rule requirements regarding credits for network transmission customers. We will address issues relating to network transmission customers credits in the RTO and ISO context in orders addressing OATT reform compliance filings submitted by each RTO and ISO. The Commission determined previously that the existing tariffs of certain RTOs and ISOs provide opportunities for transmission customers to receive credit or the equivalent (e.g., Transmission Congestion Contracts, Firm Transmission Rights or Auction Revenue Rights) for building facilities or upgrades that are consistent with or superior to Order No. 888 requirements.\447\ Each RTO and ISO will have the opportunity to show on compliance that this continues to be the case given the reforms adopted in this Final Rule.

\447\ For example, NYISO's tariff provides that a facilities study will contain a non-binding estimate as to the feasible Transmission Congestion Contracts (TCCs) resulting from the construction of new facilities. There, upon completion of the transmission upgrade and the first subsequent centralized TCC auction, the NYISO will determine the incremental TCCs associated with the upgrade. See section 19.4 ``Facilities Study Procedures'' of NYISO's tariff. Similarly, PJM's tariff provides that an interconnection customer that undertakes responsibility for constructing or completing network upgrades and/or local upgrades to accommodate its interconnection request will be entitled to receive the incremental Auction Revenue Rights associated with such facilities and upgrades subject to conditions. See section 46.1 ``Right of Interconnection Customer to Incremental Auction Revenue Rights'' of PJM's tariff.

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Other issues Comments

774. East Texas Cooperatives argue that the Commission should clarify that a network customer is entitled to transmission credits for its own transmission facilities and the facilities of member utilities for which the network customer arranges and pays for network transmission services. East Texas Cooperatives explain that a recent Commission decision \448\ allows transmission credits only for facilities owned by the generation and transmission cooperative (G&T) and not for its individual members, which in its view is contrary to past Commission precedent.

\448\ East Texas Electric Cooperative, Inc. v. Central and Southwest Services, Inc., 108 FERC ] 61,077 at P 21-23 (2004), reh'g denied, 114 FERC ] 61,027 at P 43-44 (2006), appeal docketed, No. 06-1090 (D.C. Cir. Mar. 10, 2006)

775. FMPA asks that the Commission affirmatively state that it will exercise its jurisdiction to ensure that public power entities are compensated for transmission investment (including joint transmission projects) in the event of dispute with jurisdictional transmission providers. FMPA explains that the proposed revisions to section 30.9 may be insufficient to address all problems that may arise, especially in regions without an RTO or an existing compensation method. NRECA asks the Commission to prohibit RTOs and ISOs from using a non-public utility's transmission facilities without compensating the entity simply because it has not joined the RTO or ISO. NRECA argues that comparable treatment requires compensation for use of a transmission owner's facilities, whether the owner is subject to Commission jurisdiction or not, and the Commission should not consider a transmission tariff to be just and reasonable if it allows unlawful trespass and conversion.

776. TAPS asks the Commission to include language in section 30.9 of the pro forma OATT that affirmatively states customers' eligibility for rate incentives for new facilities under recently established Commission policy. TAPS further requests that the Commission guard against a transmission provider blocking such incentive based credits by refusing to engage in joint development of transmission projects with its customers. Commission Determination

777. The Commission finds that there is not enough evidence on the record to make a generic determination on these issues and, instead, will address them on a case-by-case basis in response to appropriate filings under FPA sections 205 and 206. With regard to incentives for new facilities, the Commission has already addressed incentives for transmission infrastructure investment in Order No. 679.\449\ There the Commission identified specific incentives that it will allow when justified in the context of individual proceedings. With regard to FMPA's concerns regarding potential disputes over compensation for transmission investment by non-public utilities, we note that section 12 of the existing pro forma OATT contains dispute resolution procedures. This Final Rule also requires transmission providers to propose a dispute resolution process as part of the coordinated planning process. Additionally, the Commission's Dispute Resolution Service is available to assist in developing a dispute resolution process, as well as the Commission via a formal complaint filed pursuant to section 206 of the FPA.

\449\ Promoting Transmission Investment through Pricing Reform, Order No. 679, 71 FR 43294 (Jul. 31, 2006), FERC Stats. & Regs. ] 31,222 (2006), order on reh'g, Order No. 679-A, 72 FR 1152 (Jan. 10, 2007), FERC Stats. & Regs. ] 31,236 (2007).

4. Capacity Reassignment

778. In Order No. 888, the Commission concluded that a transmission provider's pro forma OATT must explicitly permit the voluntary reassignment of all or part of a holder's firm point-to-point capacity rights to any eligible customer.\450\ With respect to the rate for capacity reassignment, the Commission concluded it could not permit reassignments at market-based rates because it was unable to determine that the market for reassigned capacity was sufficiently competitive so that assignors would not be able to exert market power. Instead, the Commission capped the rate at the highest of (1) The original transmission rate charged to the purchaser (assignor), (2) the transmission provider's maximum stated firm transmission rate in effect at the time of the reassignment, or (3) the assignor's own opportunity costs capped at the cost of expansion (price cap). The Commission further explained that opportunity cost pricing had been permitted at ``the higher of embedded costs or legitimate and verifiable opportunity costs, but not the sum of the two (i.e., `or' pricing is permitted; `and' pricing is not).'' \451\ In Order No. 888-A, the Commission explained that opportunity costs for capacity reassigned by a customer should be measured in a manner analogous to that used to measure the transmission provider's opportunity cost.\452\

\450\ See Order No. 888 at 31,696; pro forma OATT section 23.1.

\451\ Id. at 31,740.

\452\ Order No. 888-A at 30,224.

NOPR Proposal

779. In the NOPR, the Commission noted that capacity reassignment does not appear to have developed into a competitive alternative to primary capacity since the issuance of Order No. 888. To facilitate development of this market, the Commission proposed to remove the price cap on capacity reassignment and allow negotiated rates for transmission capacity reassigned by transmission customers. The Commission explained that, because the price cap appears to have reduced customers' transmission options, removal of the cap may be warranted without a market-by-market analysis. Due to market power concerns, however, the Commission proposed to retain the price cap for capacity reassigned by the transmission provider's merchant function or its affiliates.

780. The Commission proposed to monitor the market for reassigned capacity by requiring regular OASIS postings and quarterly reports from transmission providers using information submitted by reassigning customers. First, the Commission proposed retaining the existing posting and filing requirements for reassigned capacity transactions to ensure that capacity is equally available to all customers and to protect against undue discrimination and the potential exercise of market power.\453\ Second, the Commission asked several questions regarding OASIS postings and the data that should be required in quarterly reports related to capacity reassignments: (1) What information should be required in the quarterly reports and OASIS postings, i.e., information about the capacity released, the original rate paid for that capacity, the price charged to the assignee for the capacity, and the term of the assignment; (2) whether other information was necessary for operational and reliability purposes; (3) whether additional reports by assignors to the transmission provider are necessary and, if so, what information should be reported by assignors; (4)

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should the Commission establish a new quarterly reporting process with a new form, or use the existing Electric Quarterly Report procedures; and (5) how frequently should OASIS postings be made.

\453\ The existing OASIS posting requirements for reassigned capacity already require, if selling on OASIS, for sellers to include data elements such as the path name, point of receipt, point of delivery, source, sink, capacity requested, capacity granted, start time, stop time, and offer price. See 18 CFR 37.6(c)(5).

Comments Lifting the Price Cap for All Transmission Customers

781. Some commenters support eliminating the price cap for reassignment of transmission capacity in the secondary market.\454\ For example, EPSA states that the Commission is correct to recognize that negotiated rates are dynamic and provide a market discipline on the price for reassigned capacity. Entegra argues that the Commission's removal of rate caps on releases of natural gas pipeline capacity increased available peak capacity and facilitated the movement of capacity into the hands of those that value it most highly, proving that an uncapped capacity release market can be both competitive and result in just and reasonable rates for customers.\455\ Exelon supports eliminating the price cap, but asserts that, since the transmission customer is seeking to reassign the capacity, it is likely the capacity is not useful in gaining access to load and therefore is not very valuable. BP Energy contends that transparent competition between the transmission provider (marketing primary and subscribed but unutilized capacity) and transmission customers, with monitoring by the Commission and prospective capacity purchasers, will moderate if not eliminate the potential exercise of market power and encourage the release of capacity that is not otherwise used or useful. As a result, BP Energy urges the Commission to require transmission providers to facilitate a competitive capacity reassignment process, similar to that used for capacity release on natural gas pipelines.

\454\ E.g., Allegheny, AWEA, Constellation, EEI, Entegra, EPSA, Exelon, Morgan Stanley, PPL, Seattle, Suez Energy NA, and TranServ.

\455\ Citing Natural Gas Pipeline Negotiated Rate Policies and Practices, 114 FERC ] 61,034 (2006) (Brownell, Comm'r concurring).

782. Some commenters support the proposal to retain the price cap for transmission providers and their affiliates.\456\ Seattle states that the Commission is correct to continue to cap prices for the transmission provider since the transmission provider is a regulated monopoly. In its reply, Entegra states that the Commission has found that having a pro forma OATT mitigates but does not eliminate a transmission provider's ability to leverage its monopoly power in transmission into market power in generation markets.\457\ Entegra further contends that Southern, Entergy, and other transmission providers have monopoly power in transmission markets in their service territories and without a cap would exploit that market power in the secondary market. Moreover, Entegra argues that allowing transmission providers and their affiliates to charge market-based rates for transmission capacity in the primary or secondary market would exacerbate the skewed incentives that already operate to discourage construction of much needed transmission facilities in many markets.

\456\ E.g., APPA, AWEA, NRECA, Seattle, TAPS, and TDU Systems.

\457\ Citing Public Service Electric & Gas Company, 78 FERC ] 61,119 at 61,455 (1997) (granting market-based rate authority based in part on the adequate ``mitigation of market power'' as evidenced by a pro forma OATT).

783. Many commenters contend that lifting the price cap for reassignment of transmission capacity only for unaffiliated transmission customers would be unreasonable.\458\ For example, Entergy argues that for the wholesale markets to work all wholesale market participants, including the transmission provider's affiliated marketers, must be treated comparably under the pro forma OATT. EEI contends that lifting the price cap can result in a more robust secondary market for transmission capacity and will reduce any risks that transmission customers may associate with being required to purchase transmission service for five-year terms in order to obtain rollover-rights. In addition, Manitoba Hydro asserts that changing the current one-year minimum term creates additional risks for transmission customers and therefore having the ability to re-sell the transmission capacity at market-based rates would assist transmission customers to better manage the financial risks involved with holding longer term contracts.

\458\ E.g., Community Power Alliance, EEI, Entergy, FirstEnergy, Imperial, Manitoba Hydro, MidAmerican, Progress Energy, and Salt River.

784. Some commenters support lifting the price cap for affiliates if caps are removed for non-affiliates, but are only generally supportive of lifting the price cap.\459\ If the Commission does lift the price cap, Southern argues that it should also lift the price caps for the transmission provider and its affiliates as well in order to counter efforts to corner the market and other related unforeseen consequences. MidAmerican agrees, asking the Commission to retain the cap for all transmission customers if the transmission provider and its affiliates are not allowed to resell capacity at market-based rates.

\459\ E.g., MidAmerican, PNM-TNMP and South Carolina E&G.

785. Several commenters argue that the Commission's justification for eliminating the price cap--namely, reducing the ability of non- affiliated customers to exercise market power in the secondary market through competition among releasing customers, monitoring the market via quarterly reports, and continuing rate regulation of primary capacity--applies to energy and marketing affiliates as well.\460\ First, several commenters argue that the Standards of Conduct and existing pro forma OATT rules ensure that transmission provider affiliates have no more ability to obtain information about the transmission system or to reserve point-to-point transmission capacity than unaffiliated customers.\ 461\ Entergy contends that, although the Commission correctly concludes elsewhere in the NOPR that functional unbundling and Standards of Conduct requirements, if properly enforced are sufficient to address affiliate abuse concerns, the Commission seems to assume that those same protections cannot be effective where the reassignment of transmission capacity is concerned.

\460\ E.g., EEI, Entergy, MidAmerican, PNM-TNMP, Progress Energy, Southern, and South Carolina E&G.

\461\ E.g., Community Power Alliance, Entergy, Imperial, Manitoba Hydro, Salt River, South Carolina E&G, and Southern.

786. Second, some commenters question the Commission's assertion that permitting transmission provider's energy and marketing affiliates to resell or reassign transmission capacity would give them the ability to favor their own generation.\462\ For example, EEI contends that transmission providers have no control over the reassignment process, and transmission customers have complete freedom to reassign transmission capacity to any customer they choose. Entergy points out that under Order No. 888 the assignor of capacity may deal directly with an assignee and without involvement of the transmission provider.\463\

\462\ E.g., EEI, Entergy, MidAmerican, and Progress Energy.

\463\ See Order No. 888 at 31,697.

787. Third, some commenters disagree with the Commission's statement that lifting the price cap for affiliates may dampen transmission investment.\464\ These same commenters argue that there is no relationship between the transmission provider's obligation to build transmission

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facilities to accommodate third party requests for transmission service and the ability of marketing and energy affiliates to resell unused transmission capacity at market-based rates. For example, Progress Energy and others contend that the transmission provider is obligated under the pro forma OATT to construct transmission facilities to meet all requests for transmission service.\465\ Progress Energy and EEI contend that the transmission customer will decide to purchase secondary market transmission capacity if it meets the reasonable needs of customers so long as the capacity is priced below the higher of the embedded cost of transmission service or the cost of expansion. EEI argues that the customer can require the transmission provider to construct additional capacity to accommodate the customer's request for service if secondary market service--whether offered by the transmission provider's marketing and energy affiliates or by a third party customer--is priced above the cost of expansion. In such situations, EEI and Progress Energy contend that the cost of expansion serves as a cap on the price at which both third party customers and the transmission provider's marketing and energy affiliates can resell transmission capacity. Moreover, Entergy argues that this is the same justification that the Commission relies upon to conclude that transmission customers would not hoard secondary capacity, and it is arbitrary for the Commission to ignore that principle in concluding that a transmission provider would hoard capacity.

\464\ E.g., EEI, MidAmerican, and Progress Energy.

\465\ E.g., EEI, Entergy and MidAmerican.

788. Additionally, some commenters argue that lifting the price cap for affiliates will encourage transmission investment.\466\ NorthWestern contends that allowing transmission providers to collect more than their ceiling price when the market is willing to pay a higher price could further the Commission's goal of encouraging transmission investment to maintain reliability and keep pace with load growth. NorthWestern suggests that the Commission could place restrictions on the proceeds in excess of the ceiling price such that, within some specified period, the dollars must be reinvested into transmission facilities or be refunded back to customers.

\466\ E.g., Entegra and NorthWestern.

789. Several commenters contend that lifting the price cap only for non-affiliates could dampen participation in the secondary market and place affiliates at a competitive disadvantage.\467\ Community Power Alliance argues it is unfair for the Commission to now say that their separated marketing affiliates, which have abided by Commission rules like any other market participant, cannot now compete on an equal footing with other participants in the secondary market for transmission capacity. Rather than prohibit transmission providers' affiliates from reselling capacity, Manitoba Hydro suggests that a more equitable approach would be for the Commission to lift the price cap for all resold transmission capacity, except for transmission capacity administered by an affiliate's transmission provider.

\467\ E.g., Community Power Alliance, EEI, FirstEnergy, Imperial, Northwest IOUs, Southern, and TVA.

790. To the extent the Commission adopts the proposed restriction on affiliate reassignments, MidAmerican seeks guidance on whether the transmission provider is expected to assure that the assignee is a valid eligible customer under the pro forma OATT. Similarly, Southern encourages the Commission to carefully identify and evaluate the possible adverse effects of lifting any reassignment price caps. Southern asserts that such effects could include expanded involvement and influence by financial players driven exclusively by profit motives and who may not be subject to Commission regulation.

791. Several commenters contend that the Commission should retain the price cap for the reassignment of transmission capacity for all customers, not just affiliates of the transmission provider.\468\ APPA argues that allowing the resale of such a scarce and valuable service to those who value the capacity more highly is a recipe for undue discrimination and unjust and unreasonable transmission rates, at the expense of end-use customers. While NRECA opposes the Commission proposal to remove the price cap, NRECA would support the proposal to retain the price caps for affiliates. Similarly, TAPS supports the decision not to lift the price caps for affiliates; however, TAPS urges the Commission to rethink the NOPR's proposal to otherwise lift the price cap for non-affiliates.

\468\ E.g., Alcoa, APPA, International Transmission, Nevada Companies, NRECA, PJM, Public Power Council, TAPS, and WAPA.

792. Several commenters argue that lifting the cap for any transmission customers would encourage the exercise of market power, including hoarding, and discourage transmission investment.\469\ If removal of the cap were effective in making reassignment more profitable, TAPS contends it would encourage hoarding of capacity on key paths that would run afoul of the directive in FPA section 217(b)(4) to ensure the ability of LSEs to secure long-term rights for their long-term power supply arrangements. Northwest IOUs argue that lifting the price cap would encourage non-affiliated transmission customers to buy transmission capacity at cost and resell it at market, in an effort to reduce the amount of transmission capacity available for resource development and other long-term uses. PJM argues that the final rule should include a requirement that appropriate hoarding mitigation procedures be implemented should the price cap be removed. APPA argues that, if no transmission capacity is available in the short run from the transmission provider, and an LSE needs additional capacity to serve load within the next day or week, the fact that the transmission provider could build capacity in future years at an incremental rate has little if any bearing on the price that LSE is willing to pay for the next day, week, or month to avert a looming supply problem. TVA asserts that transportation prices rose drastically during periods of high demand or constraint after the price cap for resale of gas transmission capacity was removed in Order No. 637 for everyone except pipelines and their affiliates. TVA states that this benefited entities that could afford to hold capacity, but harmed those that had to buy additional capacity on a short-term basis.

\469\ E.g., APPA, Nevada Companies, Northwest IOUs, NRECA, PJM, TAPS, and WAPA.

793. Alcoa and Nevada Companies argue that there is a significant potential for abuse in connection with the removal of the cap, particularly in load pockets. Alcoa argues that it is not clear at this point that there are sufficient safeguards in place to prevent and monitor the exercise of market power, something that must be assured before the cap is lifted on transmission capacity resale. Nevada Companies contend the proposal to remove the cap may actually reduce utilization of the grid, contrary to its intended purpose. For example, Nevada Companies state that transmission customers who have locked up capacity in constrained markets will likely wait to the very last minute to make that capacity available in order to drive up the price, which will often result in the capacity not being utilized if transactions cannot occur quickly enough. Some

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

[[pp. 12365-12414]] Preventing Undue Discrimination and Preference in Transmission Service

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commenters contend that, like LMP in organized markets, allowing price signals via lifting the cap may not encourage transmission investment, but rather create entrenched interests that profit from the existence of congestion and oppose efforts to eliminate such congestion through transmission expansion.\470\ If transmission providers are forced to purchase capacity at higher prices on the secondary market, Imperial argues that their native load customers be harmed by such higher prices, which may in turn hamper transmission expansion contrary to the Commission's stated goals for promoting transmission investment.

\470\ E.g., APPA, International Transmission, NRECA, Public Power Council, and Seattle.

794. In addition, some commenters are skeptical of the Commission's assertion that existing market mechanisms are a sufficient deterrent to anticompetitive behavior.\471\ WAPA and TAPS argue that, while eliminating the price cap might increase customers' transmission options, the Commission still needs to conduct case-by-case market power analyses prior to lifting the cap.\472\ As a result, WAPA argues, it is critical for the Commission to identify and aggressively mitigate all transmission market power on an ex ante basis, rather than utilizing an ex post monitoring scheme as proposed in the NOPR. If the Commission lifts the price cap, certain commenters argue that the Commission should establish competitive bidding transaction standards.\473\ For example, Seattle asserts that a standards organization such as NAESB will need to establish bid/ask transaction standards and reporting formats and the Commission must periodically validate the assumption that the secondary market is workably competitive.

\471\ E.g., Alcoa, APPA, Bonneville, TAPS, and WAPA.

\472\ Citing Farmers Union Cent. Exch., Inc. v. FERC, 734 F.2d 1486, 1508-10 (D.C. Cir. 1984) (concluding that ``undocumented reliance on market forces is insufficient to satisfy the Commission's regulatory responsibilities.''); California ex. Rel. Lockyer v. FERC, 383 F.3d 1006, 1013 (9th Cir. 2004).

\473\ E.g., BP Energy, Seattle, and TranServ.

Application of the Price Cap to Members of ISOs/RTOs

795. Some commenters request clarification that, if the Commission retains the price cap for capacity reassigned by affiliates, that it not apply to entities that have turned over control and operation of their transmission facilities to an RTO, ISO or independent entities.\474\ For example, Constellation requests that the Commission clarify that the revised pro forma OATT does not impose the cap on affiliates of transmission owners that have turned their transmission facilities over to an RTO/ISO when they reassign transmission capacity on facilities operated by the RTO/ISO. While MISO takes no position on whether the Commission should retain its cap for stand-alone transmission providers and their affiliated customers, it argues that the cap makes no sense in the context of capacity reassignments administered by RTOs and ISOs. MISO observes that the NOPR cites affiliate preference and market power concerns as the basis for retaining the cap on reassignments by transmission providers and their affiliated customers, which MISO argues are not applicable in the RTO/ ISO context. Further, MISO argues that the ownership of transmission assets in an RTO/ISO is divorced from the provision of transmission service, and RTO transmission owners are transmission customers no different from any other customer class.

\474\ E.g., Ameren, Constellation, SPP, and TranServ. ISO New England and PJM argue that, as providers of transmission service, they have no affiliates and likewise are not bound by the Commission's reassignment proposal.

796. On the contrary, APPA notes that the issue is whether the transmission customer holding transmission rights over a constrained path has the ability to exercise market power and charge unjust and unreasonable rates if the cap is lifted. APPA argues that the issue is the same in both RTO and non-RTO regions. In APPA's view, whether the public utility transmission provider has joined an RTO, does not affect the ability of its merchant affiliate to extract unjust and reasonable rents for the resale of scarce transmission rights. Alternative Price Cap Proposals

797. Some commenters propose alternatives to negotiated pricing of transmission capacity in the secondary market.\475\ While APPA supports retaining the current rate cap, it contends that firm point-to-point customers should be allowed to collect demonstrable out-of-pocket costs in addition to the maximum capped rate. Alcoa suggests that the Commission could stimulate the secondary market for transmission capacity by increasing the cap and allowing parties to charge a percentage over the original price paid. Seattle contends that the existing Commission policy could be incrementally modified to permit recovery of remarketing costs and recognize that, for many customers, the transmission right is held at a much higher per unit cost than the primary rate stated in the transmission provider's pro forma OATT (due in part to the fact that a customer may not use all of the capacity for which it has contracted).

\475\ E.g., Alcoa, APPA, Manitoba Hydro, PGP, Sacramento, and Seattle.

798. Sacramento proposes that prices for released capacity be capped at the amortized and rate-based cost of a transmission upgrade. Seattle states that costly redirect processes, including system impact studies, may be needed to create a reassignment product that has value to other customers, given that the point of receipt, point of delivery or both typically change in a reassignment. While the current pro forma OATT pricing model differentiates transmission rates based on term and time of day (monthly, weekly, daily, hourly), Seattle asserts that seasonal variations in the value of transmission rights offered for short-term reassignment are also worthy of consideration, especially in a region like the Northwest, where power production varies seasonally.

799. MISO states that it believes the Commission should further strengthen its pro-competitive policy by permitting RTO/ISO transmission providers to offer firm point-to-point transmission service for drive-out/drive-through transactions at market-based rates, including ``rollover'' transactions. MISO states that the principles for allocating firm capacity on such interfaces should be the same as for reassigning capacity within an RTO: i.e., permitting customers that value the capacity more highly to benefit from it. MISO asserts that allowing market participants to compete based strictly on price on external interfaces would resolve many inefficiencies stemming from the cumbersome queue administration procedures currently used on such facilities. MISO states that the final rule should encourage RTOs and ISOs to introduce such competitive practices in their footprints.

800. PGP proposes two alternative approaches. First, PGP proposes that the Commission could wait until a regional approach for pricing reassignments is developed in those areas of the country that still rely on reassignments of point-to-point capacity to create a secondary market in transmission service. Second, PGP proposes that any decision to remove the price cap could be made on a case-by-case basis after a filing by a point-to-point customer at the Commission, in which the applicant must meet standards developed by the Commission that demonstrate the lack of market power in relevant transmission or generator markets.

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801. South Carolina E&G requests that the Commission clarify how the cap is calculated if the Commission chooses to retain the price cap. International Transmission asserts that the Commission should lift the price cap, on an experimental basis, similar to the approach followed in the natural gas industry. Similarly, WAPA recommends that the Commission either retain the price cap or institute a separate rulemaking proceeding for the purpose of establishing detailed market analysis criteria for eliminating the price cap for specific transmission segments or paths. Posting and Filing Requirements

802. Some commenters support the proposal to require transmission providers to submit quarterly reports and make OASIS postings regarding reassignments of transmission capacity.\476\ Bonneville asserts that, at a minimum, transmission customers should be required to provide a downloadable file to the transmission provider for posting on the transmission provider's OASIS that identifies the assignee, the amount of capacity assigned or transferred, the date of the offer of assignment, and the rate and duration of the assignment. Other commenters argue that transmission customers should be given greater reporting responsibility.\477\ Southern contends that transmission providers should not be burdened with submitting quarterly reports and making OASIS postings based on assignment information provided to them by other assignors/assignees. Rather, Southern and EEI argue that assignment information should be filed by the respective assignors and assignees in connection with their Electric Quarterly Report filings and not by the transmission provider. PNM-TNMP contend that the Commission should prescribe specific reporting obligations and associated deadlines to the assignors and reporting obligations should also include appropriate consequences for non-compliance on the part of the assignor. Nevada Companies ask that a system be put in place to charge relevant transmission customers for the additional reporting if the transmission provider is required to do the reporting, either on the OASIS or through some other mechanism.

\476\ E.g., Bonneville, FirstEnergy, and PJM.

\477\ E.g., EEI, Entergy, Nevada Companies, PNM-TNMP, South Carolina E&G, Southern, and TVA.

803. Some commenters argue that more information should be posted on OASIS beyond what was proposed in the NOPR.\478\ EEI asserts that the details the transmission customers should report on the OASIS and in the quarterly reports include: The identity of the primary market seller; the identities of the secondary market seller and purchaser; the points of receipt and delivery; the term of reassigned service; the quantity of the reassigned service; and the charge for the reassignment, expressed in dollars per MW-month, week, day, or hour as appropriate. Other commenters contend that the existing quarterly report is appropriate and a new report should not be instituted.\479\ TranServ argues that the existing OASIS posting template query and audit functions are sufficient and no new obligations should be required. As to frequency of OASIS postings, Seattle suggests seven days after a transaction and NorthWestern proposes that the OASIS postings be no more frequent than monthly.

\478\ E.g., EEI, PJM, and Seattle.

\479\ E.g., PJM, PNM-TNMP, and TranServ.

804. Other commenters raise confidentiality concerns or state that business practice standards for capacity reassignment posting requirements would be required.\480\ Because these negotiated rates will be market sensitive, Allegheny asks the Commission not to require reporting and OASIS posting until the term of the reassignment has expired. NAESB states that capacity reassignment, including removing the price cap and allowing negotiated rates, could require posting standards for OASIS sites and the addition of significant functions to support such postings.

\480\ E.g., Allegheny, Morgan Stanley, NAESB, Seattle, and TranServ.

805. NAESB states that capacity reassignment including removing the price cap and allowing negotiated rates could require posting standards for the OASIS site, and significant functions added to support such postings. NAESB asserts that this will require a more comprehensive standards solution, which may include data aggregation by the transmission provider, reports prepared and posted quarterly including how the information is communicated between the transmission provider and marketer for collection, submittals of quarterly reports from the transmission provider to the Commission, changes to the OASIS S&CP, and determination of informational content and design of templates. NAESB states that posting is more complicated if the transmission provider is required to post information given to it by a marketer on its non- standard products and requests Commission guidance regarding posting requirements. Other Issues

806. Some commenters argue that price caps are not limiting capacity reassignment under the current pro forma OATT.\481\ Williams contends that other non-price limitations on capacity reassignment, such as the requirement that the assignee utilize the same source and sink as the original customers, are the real reasons there has not been more capacity reassignment. Williams acknowledges that this bars network customers from reassigning transmission capacity and requests that Commission clarify that classification of a transmission customer as a network or point-to-point customer does not restrict the purchase or reassignment of transmission capacity. Sacramento similarly complains that one of the chief impediments to capacity reassignment is that network integration service customers are not permitted either to assign their capacity or to utilize it to make off-system sales. Sacramento contends that a point-to-point customer may utilize otherwise unused capacity to make sales ``off-system'' to third parties, while network customers cannot make full use of the transmission capacity for which they are paying.

\481\ E.g., Powerex, Sacramento, TAPS, and Williams.

807. Some commenters contend that timelines for the release of capacity should be clearly stated.\482\ APPA argues that section 13.8 of the pro forma OATT provides too little time for LSEs attempting to make firm power supply arrangements to obtain even daily firm point-to- point service using the capacity left unscheduled by other firm point- to-point customers. Powerex and SPP also ask the Commission to set out clear rules, including timelines, for releasing unused transmission capacity for non-firm use to better encourage full and economically efficient use of the existing transmission grid.

\482\ E.g., APPA, Powerex, and SPP.

Commission Determination

808. To foster the development of a more robust secondary market for transmission capacity, the Commission concludes that it is appropriate to lift the price cap for all transmission customers reassigning transmission capacity. In Order No. 888, the Commission found that allowing holders of firm transmission capacity rights to reassign capacity would help parties manage the financial risks associated with their long-term commitments, reduce the market power of transmission providers by enabling customers to compete, and foster

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efficient capacity allocation.\483\ Over the past ten years, however, it has become clear that capacity reassignment has failed to develop into a competitive alternative to primary capacity. In particular, the price cap has served to reduce customers' transmission options and impaired the development of a secondary market for transmission capacity. In order to achieve the goals originally stated in Order No. 888, we therefore lift the price cap for reassigned capacity. We believe this will allow capacity to be allocated to those entities that value it most, thereby sending more accurate price signals to identify the appropriate location for construction of new transmission facilities to reduce congestion.

\483\ Order No. 888 at 31,696.

809. We decline to adopt the NOPR proposal to retain price caps for capacity resold by a transmission provider's merchant function or its affiliates.\484\ After reviewing the comments submitted in response to the NOPR, and further considering our ten years of experience regulating capacity reassignments, we conclude that retaining the price caps for this portion of the market would continue to impair development of the secondary market and is not otherwise necessary to ensure just and reasonable rates. We find there are no significant market power concerns to justify retaining the price caps for any transmission customer. Indeed, the Commission did not distinguish between affiliated and non-affiliated transmission customers when it initially found in Order Nos. 888 and 888-A that excess capacity reserved could be reassigned.\485\ The Commission instead placed a price cap on all reassignments of capacity out of a concern that the entire market for reassigned capacity was not sufficiently competitive.\486\ We now find that market forces, combined with the requirements of the pro forma OATT as modified in this Final Rule, will limit the ability of assignors to exert market power, including affiliates of the transmission provider. First, competition among reassigning customers will restrict the exercise of market power. Second, the continued regulation of rates for primary capacity will act as a further check to ensure rates for reassigned capacity remain just and reasonable. Finally, the amended rules we adopt below to govern the reassignment of capacity will increase our regulatory oversight of the secondary capacity market, allowing us to effectively monitor the secondary capacity market. There is thus no need to retain the existing price caps on reassigned capacity for any market participant.

\484\ Because Order Nos. 888 and 888-A require a separation of a public utility's transmission function and its wholesale generating marketing (merchant) function, a transmission provider will take service under its OATT through its merchant function or affiliate.

\485\ Order No. 888 at 31,696-97; Order No. 888-A at 30,219-25.

\486\ Order No. 888 at 31,697.

810. Our decision to lift the price caps for capacity reassignments by all transmission customers is motivated by growing concerns regarding the decrease in transmission investment and the corresponding increase in congestion costs, as described more fully in section III.C of this Final Rule. The Commission believes it is important to take every opportunity to explore more efficient use of the grid by industry participants, whether they are affiliates of the transmission provider or not. Eliminating the price cap for reassigned capacity will provide greater flexibility to respond to changing system conditions and alternatives for customers that value the capacity more highly. As commenters suggest, lifting the price cap will enhance the ability of customers that reserve long-term capacity for five-year terms in order to obtain rollover rights to resell that capacity if their needs change.\487\ Other customers may determine that it is more economic to acquire reassigned capacity reflecting market rates than reserve long- term capacity. In either case, lifting the price cap will help ensure that, during peak demand periods, transmission capacity will be used by those that value it the most. Establishing a competitive market for secondary transmission capacity will thus send more accurate price signals that promote efficient use of the transmission system by fostering the reassignment of unused capacity.

\487\ As explained in section V.D.3, the Final Rule extends from one year to five years the minimum term required to obtain a rollover right.

811. While some commenters argue that lifting the cap encourages the exercise of market power, including hoarding, and discourages transmission investment, we find that competition among reassigning customers, continuing rate regulation of the transmission provider's primary capacity, and reforms to the secondary capacity market adopted below, combined with enforcement proceedings, audits, and other regulatory controls, will assure just and reasonable rates. The Commission discussed the possibility of transmission capacity hoarding in Order No. 888. The Commission noted that unscheduled firm capacity is available on a non-firm basis to other customers and, thus, there is little practical possibility of hoarding. Instead, the capacity reassignment provisions of the pro forma OATT provide an economic incentive to make that capacity available to third parties.\488\ This applies even when the entity obtaining transmission capacity under the pro forma OATT is the transmission provider.\489\ It is equally in the corporate interests of a transmission provider and its affiliates not to over-reserve or ``hoard'' transmission capacity. Under the pro forma OATT, the affiliate--and therefore the upstream corporate parent of the affiliate and the transmission provider--bears the cost responsibility for transmission capacity that it reserves but does not use to make wholesale sales. If the affiliate attempts to hoard transmission capacity, its upstream corporate parent loses revenues just like the non-affiliate. Like any other customer, an affiliate of the transmission provider should find it in its overall corporate interest to reassign transmission capacity to others with higher valued uses at negotiated rates.\490\

\488\ Order No. 888 at 31,693.

\489\ See Southwestern Public Service Company, 80 FERC ] 61,245 at 61,905 (1997).

\490\ Moreover, Order No. 889 required that all public utilities establish or participate in an OASIS that meets certain specifications and comply with Standards of Conduct designed to prevent employees of a public utility (or any employees of its affiliates) engaged in wholesale power marketing functions from obtaining preferential access to pertinent transmission system information. The Standards of Conduct mitigate the ability of an affiliate to hoard capacity or collect rates that are inconsistent with market conditions. As a result, we are less concerned in this instance about affiliates competing on the same terms as non- affiliates. To the extent problems arise from affiliate participation in the secondary capacity market, we will revisit our decision here to lift the price caps for transmission providers and their affiliates.

812. We reject the suggestion in the NOPR that lifting the price caps for the transmission providers' merchant function or affiliates will provide disincentives to build or expand the transmission system. Without congestion, the transmission provider's rate on file will serve as the de facto price cap and, if congestion exists, the ``incremental rate'' reflecting the transmission provider's cost of expanding the system should act as a price ceiling for long-term transactions. It would be unreasonable to expect a transmission customer to pay a rate for reassigned capacity that is higher than the cost of expansion when it could simply exercise its rights under the pro forma OATT as a cheaper alternative. To the extent there is a lag-time between the request for new transmission service

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and the date on which new facilities would be available, the adoption of conditional firm service and modifications to redispatch service elsewhere in this Final Rule will mitigate the exercise of market power during the interim period. We believe that the reforms to rules governing reassignments of capacity discussed below, along with associated reporting obligations, will adequately limit the ability of capacity holders to exercise market power in the limited circumstances when neither primary transmission capacity nor these additional services are available.

813. Several commenters raise concerns that lifting of the price ceiling could lead to speculative pricing. If high prices occur during periods of peak demand it is a legitimate reaction to supply and demand forces. As we explained in Order No. 637-A, ``[a] surge in the price of candles during a power outage is not evidence of monopoly in the candle market.'' \491\ To the extent that capacity is not being anticompetitively withheld from the market, high prices are the competitive responses to market conditions and should result in a more efficient allocation of capacity to those customers valuing it the most and a resulting expansion of transmission facilities.

\491\ Order No. 637-A at 31,595.

814. We emphasize that we are not deregulating or otherwise adopting market-based rates for the provision of transmission service under the pro forma OATT. Transmission providers will continue to be obligated to make ATC available to customers, including ATC associated with purchased but unused capacity. Transmission providers also will continue to be obligated to construct new facilities to satisfy a request for service if that request cannot be satisfied using existing capacity. The pro forma OATT therefore does not, and will not, permit the withholding of transmission capacity in an effort to exercise market power. Furthermore, the rates for transmission service provided under the pro forma OATT will continue to be determined on a cost-of- service basis unless the transmission provider can demonstrate, on a case-specific basis, that it lacks market power. Nothing in this Final Rule affects the obligations of transmission providers to offer service under the pro forma OATT at cost-based rates. The only reform being adopted concerns the resale of capacity by transmission customers. Given that traditional regulation will continue to govern the sale of primary capacity under the pro forma OATT, we no longer believe that cost-of-service regulation is necessary or appropriate for secondary capacity.\492\

\492\ Our findings here address the particular circumstances associated with the electric utility industry and are not intended to suggest that corresponding changes should be made to the rates for capacity release by customers of natural gas transportation capacity. Any such changes would be considered only after notice and comment and based on a record applicable to the natural gas industry.

815. As with any innovative rate program, however, the Commission will monitor the secondary capacity market to ensure that participants are not exercising market power. To enhance oversight and monitoring by the Commission, we adopt reforms to the underlying rules governing capacity reassignments. First, we require that all sales or assignments of capacity be conducted through or otherwise posted on the transmission provider's OASIS on or before the date the reassigned service commences. The Commission thus eliminates the current ability of transmission customers to assign the transmission rights to another party with subsequent notification to the transmission provider.\493\ The mechanisms for negotiating a reassignment remain the same. The transmission customer may either request that the transmission provider make the capacity available on its OASIS or the transmission customer may negotiate the terms of an assignment bilaterally. In either instance, however, the resulting sale or assignment must be posted by the transmission provider on its OASIS prior to the date the reassigned service commences. We require transmission providers working through NAESB to develop appropriate OASIS functionality to allow such postings. Transmission providers need not implement this new OASIS functionality and any related business practices until NAESB develops appropriate standards.

\493\ See Order No. 888 at 31,697.

816. Second, we require that assignees of transmission capacity execute a service agreement prior to the date on which the reassigned service commences. Under the current pro forma OATT, transmission customers that have executed service agreements may negotiate and implement assignments of capacity without involving the transmission provider, subject to after-the-fact reporting and posting, provided the transmission customer has a market-based rate tariff on file.\494\ In order to increase our oversight of reassigned capacity, we find that all reassignments must instead be accomplished by the assignee executing a service agreement with the transmission provider that will govern the provision of reassigned service.\495\ This will effectively return the specified capacity to the transmission provider for the purpose of reassignment to the assignee.\496\ The assignment shall be only to the specified assignee, without any obligation that the capacity be made available to third parties, and shall not be subject to any queuing by the transmission provider since the assignee is merely accepting the assignor's already-approved service for a specified period.\497\ All of the non-rate terms and conditions that otherwise would apply to the transmission provider's sale of transmission capacity continue to apply in the case of a reassignment.\498\

\494\ See Order No. 888 at 31,697 n.394; Order No. 888-A at 30,224 n.151.

\495\ The pro forma Form of Service Agreement for the Resale, Reassignment or Transfer of Long-Term Firm Point-to-Point Transmission Service is set forth in a new Attachment A-1 to the pro forma OATT.

\496\ As reformed in this Final Rule, the structural mechanism for reassigning transmission capacity will be similar to the mechanism for releasing pipeline capacity. While parties may be able to negotiate the prices applicable to assigned capacity, the assignee will execute a service agreement directly with the transmission provider and, thus, there will no longer be a need for the assigning party to have on file with the Commission a rate schedule governing reassigned capacity. See Order No. 888 at 31,697 n. 324. The transmission provider's OATT will govern the reassigned service. The assignee will pay the transmission provider for service at the negotiated rate and the transmission provider will bill or credit the assignor with any the difference between the negotiated rate and the assignor's original rate. As noted above, however, there will be no requirement for the transmission provider to create an auction for reassigned transmission capacity similar to the pipeline capacity reassignment program, since the underlying price caps are being removed for electric transmission capacity.

\497\ To the extent the assignee desires to change its points of receipt or delivery, the limitations set forth in section 23.2 shall apply.

\498\ See Commonwealth Edison Co., 78 FERC ] 61,312 at 62,336 (1997); Boston Edison Co., 81 FERC ] 61,372 at 62,768 (1997); Southwestern Public Service Co., 80 FERC ] 61,245 at 61,905 (1997). The non-rate terms and conditions of reassigned service will therefore conform to the pro forma OATT. As a result, there is no requirement to file with the Commission service agreements for reassigned transmission service.

817. Third, in addition to existing OASIS posting requirements, we require transmission providers to aggregate and summarize in an electronic quarterly report the data contained in these service agreements. As proposed in the NOPR, the use of quarterly reports will assist the Commission in gathering data to ensure the effectiveness of market forces and regulatory requirements to mitigate the exercise of market power. The Commission directs that this quarterly report be submitted electronically in spreadsheet format

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consistent with the electronic filing system used for Electric Quarterly Reports so that it is readily accessible to the Commission and the public.\499\

\499\ The transmission provider should identify capacity reassignments in the Contracts tab of the EQR using the Product Type Name ``CAPACITY REASSIGNMENT.'' All terms must be fully described and rates provided. If no Product Name adequately captures the nature of a given aspect of the capacity reassignment, the assignor may use the Product Name ``OTHER,'' but that aspect must be fully described in the Rate Description field. If that description is over 150 characters, the transmission provider may use multiple Contract Product lines to describe it. General instructions on how to file the EQR may be found at http://www.ferc.gov/docs-filing/eqr.asp.

818. Taken together, these reforms to the rules governing reassigned capacity will increase transparency and facilitate our monitoring of the secondary market for transmission capacity. We do not believe it is necessary to require a market power analysis as a condition to exercising the right to reassign transmission capacity. Although market power analyses are one method for ensuring that market- based rates remain just and reasonable, they are not the only method.\500\ To achieve the Commission's original goals for capacity reassignment expressed in Order No. 888, we adopt a more flexible approach in this area and rely on posting requirements and other regulatory controls to ensure that rates for reassigned transmission capacity remain just and reasonable. As noted above, we find that a market power analysis is not required because transmission providers continue to be obligated to satisfy requests for service--whether out of existing capacity or new facilities--at cost-based rates. Transmission capacity therefore cannot be withheld in an effort to exercise market power. Moreover, the posting and filing requirements adopted herein provide the Commission the necessary information to ensure that, even if an entity sought to exercise market power in the secondary market, such an attempt could be effectively detected.

\500\ See Alternatives to Traditional Cost-of-Service Ratemaking for Natural Gas Pipelines and Regulation of Negotiated Transportation Services of Natural Gas Pipelines, 74 FERC ] 61,076 (1996).

819. We therefore disagree with commenters who assert that lifting the cap on reassignment contradicts judicial and Commission precedent. In Order No. 637-A, the Commission explained at length why Farmers Union \501\ and other precedent did not prevent the Commission from adopting negotiated rates for secondary capacity as part of a regulatory scheme that provides safeguards to ensure that rates remain just and reasonable.\502\ The court affirmed the Commission's removal of price ceilings for short-term capacity release shippers in the natural gas market established in Order Nos. 637 and 637-A, recognizing that non-cost factors such as the need to lift price ceilings to facilitate movement of capacity into the hands of those who value it most and the negotiated rates only to the secondary market distinguished the case from Farmers Union.\503\ The same is true here, given the non-cost factor advantages of lifting the price cap and the use of monitoring and enforcement of remedies to mitigate the exercise of market power.

\501\ Farmers Union Central Exchange v. FERC, 734 F.2d 1486, 1501 (D.C. Cir. 1984) (Farmers Union) (finding that Commission failed to justify relaxation of cost-based regulation of oil pipeline companies because it did not ensure rates would remain within the zone of reasonableness).

\502\ Order No. 637-A at 31,558-72.

\503\ Interstate Natural Gas Association of America v. FERC, 285 F.3d 18 (D.C. Cir. 2002).

820. The Commission directs staff to closely monitor the reassignment-related data submitted by transmission providers in their quarterly reports to identify any problems in the development of the secondary market for transmission capacity and, in particular, the potential exercise of market power. We direct staff to prepare, within six months of receipt of two years of quarterly reports, a report summarizing its findings. To inform our analysis, we encourage market participants to provide feedback regarding the development of the secondary capacity market and, in particular, to contact the Commission's Enforcement Hotline \504\ with any particular concerns as this market develops.

\504\ Market participants may contact the Commission's Enforcement Hotline via telephone (202) 502-8390, toll-free 1-888- 889-8030, fax (202) 208-0057, or at http://www.ferc.gov/cust-protect/enforce-hot.asp .

821. Although several commenters argue that additional posting and filing requirements could be too burdensome and costly, the Commission does not believe this burden will be great. All capacity reassignments must be conducted or otherwise posted on OASIS and each assignee will be required to submit an executed service agreement for reassigned service. The transmission provider thus will have ready access to data necessary for the OASIS postings and electronic quarterly transaction reports. In any event, the Commission's access to this data is vital to ensure effective monitoring and oversight and, thus, we find that any burden on the transmission provider is outweighed by the need for transparency. To the extent the transmission provider incurs costs to maintain or report this information, Order No. 889 made clear that all OASIS users, including the transmission provider, pay all of the fixed costs of OASIS-related activities in wholesale rates and pay usage- related variable costs and fees.\505\

\505\ Order No. 889 at 31,625.

822. With regard to confidentiality concerns, the Commission finds that the disclosure of reassigned capacity information is necessary for the Commission and market participants to effectively monitor transactions for undue discrimination and preference. Consistent with our determination in Order No. 2001, where similar concerns were raised regarding disclosure of information, we believe that disclosure will promote competition and make the market operate more efficiently.\506\ Moreover, public reports will provide customers with a certain level of price transparency to help them make informed decisions regarding the relative value of capacity on a particular path.

\506\ See Order No. 2001 at P 94-129.

823. We decline requests to require implementation of electronic auctions for reassigned capacity. While such mechanisms are in place in RTO and ISO markets, we conclude that it would be too great a burden to impose electronic auctions on other transmission providers simply to facilitate capacity reassignments. The continued use of OASIS, combined with the posting and service agreement requirements adopted here, should be sufficient to facilitate more efficient use of the grid and mitigate the exercise of market power.

824. With regard to the requests that the Commission institute alternative specific timelines and other rules for the reassignment of capacity rights to ensure efficient use of the grid, we will not revise the rules set forth in the pro forma OATT. We do not have sufficient evidence in this proceeding to suggest that public utilities' existing scheduling timelines generally hinder customers from reselling unused transmission capacity or lead to capacity withholding.

825. With regard to requests for network customers to reassign transmission capacity, we affirm our finding in Order Nos. 888 and 888- A that capacity reassignments are available only to point-to-point customers.\507\ Point-to-point service under the pro forma OATT clearly sets forth defined capacity rights and is therefore reassignable. In comparison,

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there are no specific capacity rights associated with network service and, thus, that service is not reassignable. Network service provides a network customer with a right to integrate its designated resources with its designated loads, in a generation pattern primarily determined by the customer. As a result, it would be difficult to determine at any moment in time exactly what portion of network service could be resold, because the network customer does not have a discrete capacity reservation and its usage of the transmission system varies as it attempts to most economically use its resources to meet its loads. To the extent an entity elects network service, it does so with the understanding that the service is not reassignable because there are no specific capacity rights to reassign.

\507\ Order No. 888 at 31,696; Order No. 888-A at 30, 223.

5. ``Operational'' Penalties a. Unreserved Use Penalties NOPR Proposal

826. In the NOPR, the Commission proposed to clarify that unreserved use penalties apply to any circumstance where a transmission customer uses transmission service that it has not reserved.\508\ Specifically, the transmission customer would be subject to an unreserved use penalty in circumstances where the transmission customer has a transmission service reservation, but uses transmission service in excess of its reserved capacity. A transmission customer also would be subject to an unreserved use penalty if the transmission customer uses transmission service where it does not have a transmission service reservation. The Commission also proposed that a transmission customer would not be subject to an unreserved use penalty in circumstances where the transmission customer inappropriately uses a network service reservation to support an off-system sale.

\508\ In the NOPR, we referred to an unreserved use penalty as an ``unauthorized use penalty.'' For the purpose of the Final Rule, we adopt the term ``unreserved use penalty'' as it more clearly articulates the nature of the penalty.

827. The Commission sought comment on whether the current policy that limits unreserved use penalties to twice the standard rate for the entire service period has resulted in penalties that are not just and reasonable and, if so, it sought further comment regarding provisions that would yield unreserved use penalties that are just and reasonable. (1) Unreserved Use of Transmission Service Comments

828. Several commenters express general support for the Commission's proposed clarification that unreserved use penalties apply to any circumstance where a transmission customer uses transmission service that it has not reserved.\509\ Several commenters support the Commission's proposed clarification, but suggest that the transmission provider should only assess unreserved use penalties when a transmission customer repeatedly uses transmission service that it has not reserved.\510\ For instance, PNM-TNMP believes penalty assessment should be optional and should be imposed on transmission customers that do not change their practices regarding transmission use and OATT compliance after being advised of their non-compliance.

\509\ E.g., APPA and Bonneville.

\510\ E.g., MidAmerican, Southern, and PNM-TNMP.

829. Several commenters argue that transmission customers with special circumstances should not be subject to unreserved use penalties in the same manner as other transmission customers. For instance, Seattle believes unreserved use penalties can result in charges that are unjust and reasonable for intermittent resources, such as wind generators, that can not precisely schedule power in future periods, but are capable of controlling output. Seattle believes that unreserved use penalties should not apply if the transmission provider is able to operate the transmission system reliably. Seattle argues that an unreserved use penalty should only apply if scheduling parties have failed to respond to dispatchers' orders stating that system conditions necessitate curtailment of output. Southern disagrees with Seattle and states that, as a general principle, unreserved use penalties should not be based on whether reliability is threatened. TDU Systems recommend that the Commission consider treating inadvertent use of point-to-point transmission service in excess of reservations by an entity serving native load in multiple control areas as an energy imbalance in the control area in which the energy imbalance occurs, rather than an unreserved use of point-to-point service. In their reply comments, EEI and PNM-TNMP disagree with TDU Systems. EEI argues that energy imbalance charges compensate generators for the additional expense they incur to compensate for the customer's failure to schedule sufficient energy to serve its load and do not compensate the transmission provider for the use of the transmission system. EEI asserts that customers that use more transmission service than they schedule should be required to pay for that transmission service just like any other user of the system.

830. Duke opposes the Commission's proposed clarification and suggests that an effective means of deterring and punishing unreserved use of transmission service is to charge the customer for the point-to- point service necessary to support the transaction and, additionally, to make the customer subject to a civil penalty in cases of intentional or repeated unreserved use. TDU Systems argue on reply that a transmission provider should not be allowed to charge unreserved use penalties unless it employs software technology designed to identify unreserved use prior to operation.

831. Several commenters suggest modifications to the manner by which transmission providers determine when unreserved use penalties should be assessed. TDU Systems believes unreserved use penalties should only be applied with prior Commission approval after notice and opportunity for hearing in order to limit the transmission provider's discretion in applying such penalties. To encourage regulatory certainty, Seattle suggests that the Commission implement tariff provisions that state a clear basis for application of unreserved use penalties.

832. Several commenters ask that the Commission delete the proposed language added to section 30.4 of the proposed revised pro forma OATT regarding the unreserved use of a network resource beyond its designated capacity.\511\ In the event the Commission elects to retain this language, these commenters ask the Commission to clarify the language to expressly permit use of the undesignated portion of a remote network resource under secondary non-firm service (as a non- network resource) and to preserve the customer's right to use the undesignated portion of the resource for other purposes (e.g., to serve its load on systems other than the host transmission provider or to make off-system sales). In its reply comments, Duke notes that the fact that a generator is designated as a network resource for a network load on one system does not prohibit a network load on a second system from obtaining non-firm energy

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from that same generator using point-to-point and secondary network resource. Duke points out that the proposed revised section 30.4 prohibits a network customer from using its firm network service to schedule power in excess of the DNR amount. Finally, TAPS asks the Commission to modify the language added to section 30.4 so that its terms are consistent with the terms used in the rest of the pro forma OATT.

\511\ E.g., APPA, TAPS, TDU Systems, and EEI Reply.

833. EEI recommends that a customer that takes unreserved transmission service, but that does not have a service agreement with the transmission provider, be deemed to have consented to the transmission provider's filing of a service agreement, so that the transmission provider has a basis for imposing both the prevailing OATT rate and the penalty charge on the customer. EEI also recommends that the Commission clarify that a customer that uses more transmission service than it has reserved also is subject to charges for ancillary services. Commission Determination

834. The Commission adopts the NOPR proposal that a transmission customer will be subject to unreserved use penalties in any circumstance where the transmission customer uses transmission service that it has not reserved. Specifically, a transmission customer will be subject to an unreserved use penalty in circumstances where a transmission customer has a transmission service reservation, but uses transmission service in excess of its reserved capacity. A transmission customer also will be subject to an unreserved use penalty if the transmission customer uses transmission service where it does not have a transmission service reservation, including the situations described in the Arizona Public Service Company (APS) audit report.\512\ We note that the transmission provider is subject to the same penalties when it takes transmission service under its OATT.

\512\ Arizona Public Service Co., 109 FERC ] 61,271 at P 6 (2004) (APS). APS contained two findings that Commission audit staff characterized as unauthorized use of transmission service. In the first finding, APS's wholesale merchant function did not request and pay for point-to-point service to support some of the off-system power sales it made at trading hubs where APS system resources were directly connected. In the second finding, APS incorrectly treated the Phoenix Valley 230kV system as a single node on its transmission system. As a result, off-system sales made by generators connected to the Phoenix Valley system should have been, but were not, supported by point-to-point service.

835. Our decision to clarify the application of unreserved use penalties will eliminate a potential source of discretion in the implementation of the pro forma OATT and will assist the Commission in its enforcement of the OATT obligations. The unreserved use penalty itself will help discourage disorderly use of transmission service. Charging a transmission customer for just the unreserved transmission service used, as suggested by Duke, would not provide a sufficient incentive to procure adequate transmission service, even with the threat of possible civil penalties. In addition, an operational penalty rather than a civil penalty is a more appropriate default remedy, even though certain circumstances may warrant a civil penalty in addition to an operational penalty. In most instances, an unreserved use penalty can be applied in a relatively mechanical manner. As a result, an operational penalty has a relatively low administrative burden and still provides a clear signal to transmission customers regarding the cost of non-compliance.\513\ We do not agree with TDU Systems' proposal that a transmission provider be required to employ software designed to identify unreserved use if the transmission provider wants to charge unreserved use penalties. As we explain below, we adopt reforms in this Final Rule that will reduce the level of unreserved use penalties for instances of inadvertent unreserved use. For instance, we reduce the period over which a one-time inadvertent use will be penalized from one month to one day. We believe that this and other reforms are sufficient to address TDU Systems' concerns.

\513\ The unreserved use penalties thus work in conjunction with imbalance penalties described in section V.C.2 of this Final Rule to reduce incentives to take actions that impair the reliability of the transmission system.

836. We will not adopt Seattle's suggestion to add provisions to the pro forma OATT that specify all circumstances that constitute use of transmission service without a transmission service reservation. Any list of transmission customer actions that would be deemed to constitute use of transmission service without a transmission service reservation will necessarily be incomplete and out-of-date given the dynamic manner by which trading patterns and practices evolve. We believe that Commission actions, such as in APS, will provide a sufficient guide to circumstances that constitute use of transmission system without a transmission service reservation. We also reject TDU Systems' suggestion that unreserved use penalties be applied only after Commission approval. As mentioned above, an unreserved use penalty can be assessed in a relatively straightforward manner in most cases. As a result, there will typically be little need for the Commission to become involved. That said, a transmission customer can always file a complaint with the Commission protesting an unreserved use penalty.

837. We will not exempt any class of transmission customer from the potential assessment of unreserved use penalties. We do not agree with Seattle's assertion that unreserved use penalties can result in charges that are unjust and reasonable for intermittent resources, such as wind generators, that can not precisely schedule power in future periods. Unreserved use penalties are based on the transmission capacity reserved rather than the transmission service scheduled, so an intermittent resource's inability to precisely schedule power in future periods is irrelevant, as long as the resource has reserved sufficient transmission capacity to deliver the resource's full output. We also do not agree with TDU Systems' suggestion that unreserved use of transmission service by an entity serving native load in multiple control areas should be treated as an energy imbalance in the control area in which the energy imbalance occurs, rather than an unreserved use of point-to-point service. In this regard, we agree with EEI that energy imbalance charges compensate the transmission provider for the additional expense it incurs to compensate for a transmission customer's failure to schedule sufficient energy to serve its load and do not compensate the transmission provider for the use of the transmission system.

838. We will not limit unreserved use penalties to instances where the unreserved use jeopardizes the reliable operation of the transmission system. Unreserved use penalties are intended, in part, to give transmission customers an incentive to reserve and pay for the appropriate level of transmission service so that transmission service is allocated in an orderly fashion. A transmission customer that uses unreserved transmission service requires the transmission provider to take some action to accommodate the additional use of the system. Some penalty is warranted even in those instances when the transmission provider's accommodations are sufficient to avoid curtailment of transmission service to other transmission customers. Absent a penalty in all instances, transmission customers would have an increased incentive to under-reserve transmission service, which would lead to an increase in the likelihood that system reliability would be impaired. In

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addition, a transmission customer that uses more transmission service than it has reserved, even in periods when system reliability has not been impaired, has nonetheless disturbed the orderly allocation of transmission service.

839. In response to comments requesting that we remove the language added to section 30.4 of the proposed revised pro forma OATT regarding the unreserved use of a network resource beyond its designated capacity, we clarify our intent in modifying section 30.4. The Commission has identified instances when a transmission provider has scheduled delivery of off-system non-designated short-term purchases using transmission capacity reserved for designated network resources.\514\ The intent of the language added to section 30.4 of the pro forma OATT was to clarify that network customers are subject to unreserved use penalties when they schedule delivery of off-system non- designated purchases using transmission capacity reserved for designated network resources. We clarify, however, that a network customer may use the undesignated portion of a remote network resource to serve network load using secondary network service and may use the undesignated portion of the resource for other non-network service purposes, such as third-party sales, as long as the network customer acquires the appropriate point-to-point transmission service. Moreover, because a transmission provider does not have to ``take service'' under its own OATT for the transmission of power that is purchased on behalf of bundled retail customers, it is free to use the undesignated portion of a remote network resource to serve its bundled retail customers.\515\ If the transmission provider desires to use a remote network resource for non-native load purposes, such as third-party sales, it must acquire the appropriate point-to-point transmission service.\516\

\514\ See MidAmerican Energy Co., 112 FERC ] 61,346 (2005); PacifiCorp, 118 FERC ] 61,026 (2007).

\515\ See Order No. 888-A at 30,216-17.

\516\ See id. at 30,217.

840. In order to ensure that the transmission provider has a basis for charging an unreserved use penalty, we modify section 13.4 of the pro forma OATT to provide that a customer that takes unreserved point- to-point transmission service and does not have a service agreement with the transmission provider is deemed to have executed the transmission provider's form of service agreement for point-to-point service. In addition, we clarify that a customer that uses more transmission service than it has reserved is also subject to charges for ancillary services. The ancillary service charges will be based on just the period of unreserved use. For instance, if a transmission customer has unreserved use during two hours on the same day, the customer must pay the ancillary service charges for those two hours, rather than for the entire day. This modification is appropriate, as the transmission provider is entitled to compensation for the ancillary services it provides when it provides transmission service. We also will modify section 3 of the pro forma OATT to reflect this rule. (2) Treatment of Inappropriate Use of Network Service as an Unreserved Use of Point-to-Point Transmission Service Comments

841. A few commenters argue that a transmission customer that inappropriately uses a network service reservation to support an off- system sale should be subject to unreserved use penalties.\517\ Other commenters request clarification or modifications to the Commission's proposal regarding the treatment of transmission customers that inappropriately use a network service reservation to support an off- system sale. TAPS asks the Commission to clarify that a transmission provider that inappropriately uses network service to support an off- system sale is required to pay for point-to-point service to support the off-system sale and potentially is liable for civil penalties, as the Commission proposed in the NOPR. Suez Energy NA suggests that an affiliate of the transmission provider that violates network tariff provisions by making unauthorized sales should also disgorge unjust profits from such sales. TDU Systems urges the Commission not to impose civil penalties for inadvertent use of network service by an LSE when it serves its own native load on a neighboring system.

\517\ E.g., APPA and PNM-TNMP.

Commission Determination

842. The Commission declines to adopt the NOPR proposal to exempt a network customer or transmission provider that inappropriately uses network transmission service to support off-system sales from unreserved use penalties. As mentioned above, one of the purposes of unreserved use penalties is to encourage orderly use and acquisition of transmission service. A network customer or transmission provider that inappropriately uses network transmission service to support off-system sales potentially uses or acquires transmission service that should be allocated to other transmission customers. In addition, the network customer or transmission provider has not paid for transmission service as required. Therefore, we conclude that a network customer or transmission provider inappropriately using network transmission service to support off-system sales should be subject to unreserved use penalties. We will evaluate the appropriateness of civil penalties in addition to unreserved use penalties on a case-by-case basis and will not exempt, as a matter of general policy, inadvertent use of network service by an LSE when it serves its own native load on a neighboring system as suggested by TDU Systems. A network customer or transmission provider that inappropriately uses network transmission service to support off-system sales also may be required to disgorge unjust profits from such sales, as the Commission may determine on a case-by- case basis. (3) Penalty Rate for Unreserved Use of Transmission Service Comments

843. Transmission providers generally assert that the Commission's current policy of limiting unreserved use penalties to twice the standard rate for the entire service period has yielded just and reasonable rates.\518\ EEI contends that if the customer is required to pay an unreserved use charge only for the period of unreserved use, the customer would have an incentive to reserve service for less than its maximum expected use and simply pay unreserved use charges in the hours in which it exceeds that usage. EEI concedes, however, that the maximum period for which the unreserved use charge should be assessed is one month. For example, EEI acknowledges that it would be unreasonable to charge a customer that takes yearly service a penalty for an entire year because of, for instance, a single hour of unreserved use. In addition, EEI suggests several modifications to the current unreserved use penalty policy. EEI suggests the Commission include, in the pro forma OATT, provisions stating that the penalty charge for unreserved use of transmission service is equal to twice the standard rate for transmission service. EEI recommends that the Commission establish a policy that a

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customer that uses transmission service without a reservation must pay a penalty equal to twice the rate for transmission service for the greater of the period of unreserved use or one month.

\518\ E.g., EEI, Bonneville, MidAmerican, Nevada Companies, and PNM-TNMP Reply.

844. Transmission customers generally assert that unreserved use penalties should be limited to twice the standard rate for the period of unreserved use.\519\ Transmission customers who take this position argue that using the service period rather than the period of unreserved use as the basis for the penalty charge discriminates against transmission customers with longer term transmission service reservations.\520\ For instance, AWEA believes that applying an unreserved use penalty based on the reservation period rather than the period of unreserved use has resulted in charges that are not just and reasonable. AWEA asserts that such a policy would also be discriminatory because, if the customer causing the unreserved use had made a shorter reservation, its penalty would be much lower. TDU Systems argue in its reply comments that there is little to be gained from charging inadvertent unreserved use more than twice the standard rate for the period of unreserved use.

\519\ E.g., APPA, AWEA, TAPS, and TDU Systems.

\520\ E.g., APPA, AWEA, TAPS, and TDU Systems Reply.

845. Several commenters suggest that unreserved use penalty charges greater than twice the standard rate for the entire service period should be limited to instances of intentional unreserved use.\521\ Nevada Companies note that there are some marketing entities that are consistently abusing the current policy and recommends that the Commission consider more severe penalties for continuous carelessness in tagging or a repeated pattern of unreserved use of the transmission system. Southern believes the transmission provider should be permitted to charge increased unreserved use penalties if a transmission customer consistently uses transmission services it has not reserved. TDU Systems disagree on reply comments, arguing that a penalty equal to twice the applicable charge is sufficient to deter unreserved use of transmission service.

\521\ E.g., NRECA, Nevada Companies, and Southern.

Commission Determination

846. We will continue giving transmission providers discretion in setting their unreserved use penalty rates, although those rates will need to be consistent with this Final Rule. Penalty charges must be based on the period of unreserved use rather than the period for which service is reserved, subject to the following principles. First, the unreserved use penalty for a single hour of unreserved use will be based on the rate for daily firm point-to-point service, even if the transmission provider has a rate for hourly firm point-to-point transmission service on file. Second, as a general rule, more than one assessment for a given duration (e.g., daily) will increase the penalty period to the next longest duration (e.g., weekly). The unreserved penalty charge for multiple instances of unreserved use (i.e., more than one hour) within a day will be based on the rate for daily firm point-to-point service. The unreserved penalty charge for multiple instances of unreserved use isolated to one calendar week would result in a penalty based on the charge for weekly firm point-to-point. The unreserved use penalty charge for multiple instances of unreserved use during more than one week during a calendar month will be based on the charge for monthly firm point-to-point.\522\

\522\ There are a number of possible permutations of these principles. For instance, a transmission customer that has 25 MW of unreserved use in two hours on one day during the first week of the month and 50 MW of unreserved use in two hours on one day during the last week of the month will pay an unreserved use penalty based on the rate for 25 MW of daily firm point-to-point service and 50 MW of daily firm point-to-point service. A transmission customer that has 25 MW of unreserved use on two separate days during the first week of the month and 50 MW of unreserved use in two hours on one day during the last week of the month will pay an unreserved use penalty based on the rate for 25 MW of weekly firm point-to-point service and 50 MW of daily firm point-to-point service. A transmission customer that has 25 MW of unreserved use on two separate days during the first week of the month and 50 MW of unreserved use on two separate days during the last week of the month will pay an unreserved use penalty on 50 MWs of monthly firm point-to-point service.

847. Our determination is based, in part, on agreement with those commenters arguing that using the period for which a transmission customer has reserved service rather than the period of unreserved use as the basis for the penalty charge discriminates against transmission customers with longer term transmission service reservations. We are mindful, however, that basing unreserved use penalties on only the period of unreserved use could give the transmission customer an incentive to reserve service for less than its maximum expected use and simply pay unreserved use charges in the hours in which it exceeds that usage. We believe the unreserved penalty regime we articulate in this Final Rule will provide a reasonable incentive to ensure that transmission customers reserve the appropriate level of transmission service without unduly charging a transmission customer for inadvertent unreserved use. In addition, transmission customers will continue to be subject to civil penalties on a case-by-case basis, so attempts to game this penalty regime could result in additional penalties depending on the specific facts at issue. We reject the suggestion in some comments that the transmission provider should only assess unreserved use penalties where a transmission customer repeatedly uses transmission service that it has not reserved. Rather, we find that penalties are appropriate for all unreserved uses of the system. Because we are allowing penalties to be based on the period of unreserved use, not the reservation period, such penalties do not unduly charge a transmission customer for inadvertent unreserved use. This penalty regime will apply to all instances where a transmission customer has an unreserved use of transmission service, regardless of whether the transmission customer had an existing relevant transmission service reservation but for a lesser amount of service.

848. A transmission provider that wants to charge unreserved use penalties must explicitly state the penalty rate in its tariff. The Commission retains the current policy established in Allegheny that the unreserved use penalty rate may not be greater than twice the firm point-to-point rate for the period of unreserved use, as defined above.\523\ We continue to believe that penalties up to twice the relevant firm point-to-point rate are just and reasonable, given the new definition for the penalty period. As a result, we establish a rebuttable presumption that unreserved use penalties no greater than twice the firm point-to-point rate for the penalty period defined above are just and reasonable. As we discuss above, the transmission customer must face a penalty in excess of the firm point-to-point transmission service charge it avoids through unreserved use of transmission service or the transmission customer will have no incentive to reserve the appropriate amount of service.

\523\ Allegheny Power System, Inc., 80 FERC ] 61,143 at 61,545- 46 (1997) (Allegheny).

849. The Commission thus concludes that a penalty of twice the standard rate is not excessively punitive, particularly given the definition of the penalty period established in this Final Rule. Without evidence to the contrary, we

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believe an unreserved use penalty equal to twice the applicable rate should create the appropriate incentive to transmission customers to purchase the correct amount of transmission service. Nonetheless, we will allow transmission providers to make a filing under section 205 of the FPA to propose an unreserved use penalty in excess of twice the relevant firm point-to-point rate for pervasive unreserved use. Transmission providers that propose such a rate must establish that a higher penalty rate is required to combat pervasive unreserved use of transmission. In arguing for such a higher penalty rate, the transmission provider must address why the standard penalty rate that penalizes repeated unreserved use is not adequate to discourage repeated instances of unreserved use of transmission service. b. Distribution of Operational Penalties NOPR Proposal

850. In the NOPR, the Commission proposed to have the transmission provider distribute to non-offending, unaffiliated transmission customers operational penalties incurred by the transmission provider's merchant function or its affiliates.\524\ For those transmission providers subject to operational penalties, the Commission proposed to require the transmission provider to make an annual compliance filing to notify the Commission of the amounts of such operational penalties incurred during the year and to propose a method to identify non- offending, unaffiliated transmission customers to which the transmission provider would distribute penalty amounts. In addition, the Commission also proposed to allow a transmission provider to avoid an annual compliance filing by making a one-time filing to propose a mechanism through which it would identify non-offending, unaffiliated transmission customers and a method by which it would distribute the operational penalties it or its affiliates have incurred to the identified transmission customers. Finally, the Commission proposed to prohibit transmission providers from recovering for ratemaking purposes or through any service or facility under the Commission's jurisdiction any cost it incurs when it or an affiliate pays an operational penalty.

\524\ An operational penalty explicitly defines the charge associated with a set of pre-defined activities (e.g., unreserved use of transmission service, completing request studies outside of the 60-day due diligence deadline) that are not in compliance with specific provisions of the OATT.

Comments

851. Transmission customers along with several other commenters support the Commission's proposal to distribute operational penalties paid by the transmission provider's merchant function to non-offending, unaffiliated transmission customers.\525\ Entegra and Morgan Stanley advocate extending the proposal so that the transmission provider distributes operational penalties paid by all transmission customers to non-offending unaffiliated transmission customers. Entegra also notes that the Commission's policy in the natural gas setting is that pipelines must credit all penalty revenues back to non-offending shippers. Entegra argues that the precedent the Commission cited in proposing that operational penalties paid by the transmission provider be distributed to non-offending, unaffiliated transmission customers applies equally to penalties paid by affiliated and unaffiliated transmission customers.\526\

\525\ E.g., APPA, ELCON, Entegra, TAPS, TDU Systems, Sacramento, and Seattle.

\526\ Entegra cites Carolina Power & Light Co. and Florida Power Corp., 103 FERC 61,209 at P 24 (2003) (Carolina Power & Light).

852. With regard to unreserved use penalties, NRECA and TDU Systems argue that the Commission should encourage transmission providers to supervise inadvertent unreserved use and notify the customer of such occurrence rather than rely on large unreserved use penalties. They argue it is better to prevent unnecessary costs than to approve post hoc penalties for unintentional unreserved use that could have been prevented.

853. A number of transmission providers oppose the portion of the Commission's proposal that would prohibit their non-offending affiliates from receiving a portion of the operational penalties the transmission provider incurs.\527\ For instance, PNM-TNMP asserts that the Commission should allow the transmission provider's non-offending affiliates, which are abiding by the same rules as other transmission customers in accordance with Standards of Conduct, to be eligible to receive a portion of the operational penalties the transmission provider incurs. In the specific case of unreserved use penalties, Southern does not support distributing penalties imposed on a transmission provider's affiliate to other OATT customers. Southern argues that such a proposal is predicated upon the false assumption that such penalties are not of true financial consequence. Southern asserts that penalties paid by an affiliate do, in fact, represent a real cost to the wholesale business of that affiliated entity. In its reply comments, TDU Systems disagrees with comments that suggest that non-offending affiliates should be allowed to receive a load ratio share of penalty revenues when a transmission provider or one of its affiliates incurs an operational penalty. TDU Systems argue that allowing any member of the corporate family to retain any portion of the penalty revenues incurred by another member of the corporate family will dilute the incentive inherent in the Commission's proposal.

\527\ E.g., EEI, MidAmerican, Nevada Companies, and PNM-TNMP.

854. Seattle suggests that compliance monitoring and enforcement to ensure that the transmission provider appropriately assesses penalties to its affiliates will be as important as correctly accounting for and distributing the revenues from penalties collected from affiliates.

855. Most commenters were supportive of the Commission's proposal to have transmission providers notify the Commission of the amounts of all operational penalties they incurred during the year through either an annual compliance filing or a one-time filing.\528\ Several commenters expressed a preference for a one-time filing by transmission providers.\529\ For instance, Ameren states that it prefers the use of a one-time filing to propose a mechanism through which the transmission provider would identify non-offending, unaffiliated transmission customers and a method by which the transmission provider would distribute the operational penalties it or its affiliates have incurred to the identified transmission customers. Ameren believes this would be less burdensome than an annual repeated compliance filing. TDU Systems, on the other hand, prefer the Commission's proposal to require an annual reporting of penalties levied and penalty revenues credited in order to foster greater transparency on this matter. TDU Systems believe greater transparency through improved reporting requirements would provide greater opportunities for detecting abuses by transmission providers or their affiliates, either in imposing inappropriate penalties on transmission customers or in failing to penalize their own or their affiliates' transgressions. In addition, TDU Systems suggest that this reporting requirement should include details on the amount of penalties

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levied, whether on customers or the transmission provider or its affiliates, for all violations. With regard to the annual reporting requirements (for those companies that do not propose a standard mechanism to handle the distribution of penalties), Nevada Companies suggest that a standard template be proposed so that all companies are following the same reporting format.

\528\ E.g., EEI, Suez Energy NA, Sacramento, TAPS, and Wisconsin Electric.

\529\ E.g., Ameren and PNM-TNMP.

856. Several commenters make recommendations that they argue will ease the administrative burden of distributing operational penalties paid by the transmission provider to non-offending, unaffiliated transmission customers. MidAmerican suggests that excluding short-term firm and non-firm transactions from the distribution methodology would avoid the need to develop a costly and administratively difficult program. TVA suggests that the amount of any such operational penalties should simply be a credit against the transmission provider's transmission revenue requirement, thereby more efficiently reducing the cost of transmission service to transmission customers.

857. Several commenters argue that the transmission provider must be made whole before it distributes any penalty revenues. For instance, EEI supports the Commission's proposal to the extent penalty revenues exceed the cost of transmission service. Nevada Companies assert that it is the transmission provider's native load that incurs the cost of correcting for the offending customer's intentional deviation from schedule or for a transmission customer's self-provided reserves being unavailable. Therefore, Nevada Companies contend that any penalties should be returned to the native load to offset its cost of generation.

858. Sacramento and WPS Companies' reply comments support the Commission's proposal to prohibit a transmission provider from recovering any cost it incurs when it or an affiliate pays an operational penalty through jurisdictional rates or services. Commission Determination

859. The Commission agrees with those commenters recommending that we broaden the NOPR proposal, which required transmission providers to distribute to non-offending, unaffiliated transmission customers only the unreserved use penalties the transmission provider's merchant function incurs. Consistent with our conclusion regarding imbalance penalties, we conclude that it would be more appropriate for transmission providers to be required to distribute all unreserved use penalties they collect, whether from the transmission provider's merchant function or other transmission customers. The penalties the transmission provider pays for late studies are penalties that, by their nature, are fully distributed only to non-affiliated transmission customers. Requiring the transmission provider to distribute the unreserved use penalty charges that its merchant function incurs will ensure that the transmission provider faces a meaningful financial consequence when its merchant function incurs an operational penalty. Extending the NOPR proposal to all unreserved use penalty revenues the transmission provider collects maintains the incentive structure of the unreserved use penalty and prevents the transmission provider from retaining revenues above those it should reasonably be allowed to earn.\530\ This determination is consistent with the Final Rule for imbalance penalties and the Commission's decision in Order Nos. 637 and 637-A.\531\

\530\ As we explain further below, the transmission provider will be allowed to retain the base firm point-to-point transmission service charge when it assesses an unreserved use penalty.

\531\ Regulation of Short-Term Natural Gas Transportation Services, and Regulation of Interstate Natural Gas Transportation Services, Order No. 637, 65 FR 10156 (Feb. 25, 2000), FERC Stats. & Regs. ] 31,091 at 31,309 (2000) (``* * *to effectively shift pipelines to the use of the non-penalty mechanisms described above to solve and prevent operational problems, it will be necessary to eliminate the pipelines' financial incentive to impose penalties and OFOs. Thus, the Commission is requiring pipelines to credit the revenues from penalties and OFOs to shippers.''); order on reh'g, Order No. 637-A, 65 FR 35706 (Jun. 5, 2000), FERC Stats. & Regs. ] 31,099 at 31,609 (2000) (``The goal of the Commission's new policy on penalties is to encourage pipelines to rely less on penalties and more on non-penalty mechanisms to manage their systems* * *.'').

860. We agree with those commenters that suggest that non-offending affiliates of the transmission provider, including the transmission provider's native load customers, should be eligible to receive a portion of the unreserved use penalties that the transmission provider collects. Unreserved use penalties are assessed against transmission customers and should, therefore, be distributed to all non-offending transmission customers, whether affiliated with the transmission provider or not. Given the distribution of unreserved penalties articulated above, the transmission provider's corporate profit is reduced if one of the transmission provider's wholly-owned marketing affiliates pays an operational penalty to the transmission provider. This is so because the corporate shareholders ultimately pay the marketing affiliate's penalty, while the transmission provider distributes the revenues to non-offending transmission customers.

861. The Commission requires the transmission provider to make an annual compliance filing and to propose in that filing a mechanism through which it will identify non-offending, transmission customers and a method by which it will distribute the unreserved use penalties revenue it receives to the identified transmission customers. This rule is consistent with our determination regarding the distribution of imbalance penalties. The transmission provider must also indicate in its compliance filing how it will distribute late study penalties to unaffiliated transmission customers. In addition, the transmission provider is required to make an annual filing with the Commission, described further below, that provides information regarding the penalty revenue the transmission provider has received and distributed. We will not allow the transmission provider to make an annual filing to propose a distribution method for unreserved use and late study penalties, as proposed in the NOPR. We agree with Ameren that restricting the transmission provider to proposing a distribution method through the transmission provider's compliance filing will reduce the administrative burden of distributing operational penalties. We believe that we can accomplish the goals underlying a mandatory annual filing to propose a distribution method--to detect inappropriate penalties and failure to penalize the transmission provider's affiliates--by requiring an annual informational filing. As suggested by Seattle, compliance monitoring and enforcement by Commission staff will provide a measure of assurance that the transmission provider appropriately assesses penalties.

862. All point-to-point and network transmission customers, including the transmission provider's native load, will be eligible to receive a portion of the penalty revenues distributed by the transmission provider. As a result, we will not adopt MidAmerican's proposal that we exclude short-term firm and non-firm transmission customers to reduce the burden to the transmission provider. Given the steps we have taken to manage the transmission provider's burden of distributing penalty revenues, we believe it more equitable to allow all transmission customers subject to operational penalties to be eligible to receive a portion of the distributed penalty revenues. In response to TVA's suggestion that the amount of any such operational penalties be credited against

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the transmission provider's transmission revenue requirement, we note that the transmission provider is free to propose this mechanism, with assurances that offending customers will not benefit, and we will decide the appropriateness of the proposal on a case-by-case basis.

863. We agree with those commenters that assert that the transmission provider must be made whole before it distributes any penalty revenues. With regard to unreserved use penalties, we will allow the transmission provider to retain the base firm point-to-point transmission service charge, but require it to distribute any revenue collected above the base firm point-to-point transmission service charge. For instance, if a transmission customer has unreserved use that results in a penalty equal to twice the rate for firm weekly point-to-point service, then the transmission provider can retain an amount equal to the rate for firm weekly point-to-point transmissions service. A transmission provider will be required to distribute the entire amount it pays for completing service request studies on an untimely basis.

864. We will not require transmission providers that make an annual compliance filing to use a standard template, as suggested by Nevada Companies. Transmission providers are in the best position to determine the least burdensome way to present the information required. We will provide guidance, however, on the information that transmission providers must provide in their annual informational filings. Transmission providers must provide: (1) A summary of penalty revenue credits by transmission customer, (2) total penalty revenues collected from affiliates, (3) total penalty revenues collected from non- affiliates, (4) a description of the costs incurred as a result of the offending behavior, and (5) a summary of the portion of the unreserved penalty revenue retained by the transmission provider.

865. Transmission providers are prohibited from recovering for ratemaking purposes or through any service under the Commission's jurisdiction any amount it or an affiliate pays as an operational penalty. This will ensure that the transmission provider faces a true financial consequence when it or an affiliate incurs an operational penalty. c. Applicability of Operational Penalties Proposal to RTOs and Other Independent or Non-Profit Entities

866. The Commission did not address the degree to which RTOs and other independent entities would be subject to operational penalties in section V.C.4 (Operational Penalties) of the NOPR. For the most part, the discussion in that section of the final rule addressed how a transmission provider should distribute operational penalties it incurs when it takes transmission service under its own tariff. In the section V.D.5 (Acquisition of Transmission Service) of the NOPR, the Commission separately addressed whether RTOs should pay operational penalties for failure to complete request studies on a timely basis. Comments

867. Several RTOs and RTO members asked that the Commission clarify that RTOs are not subject to any operational penalties.\532\ Entergy opposes the Commission's proposal to assess operational penalties against non-RTO transmission providers, but not RTOs. However, if the Commission maintains this distinction, Entergy asks that it clarify that independent entities--such as Entergy's Independent Coordinator of Transmission--and the transmission providers that allow independent entities to process transmission service requests will have the same protection from operational penalties as RTOs. PGP argues that, in the case of non-profit transmission providers, requiring the transmission provider to pay ``non-offending'' customers when the provider incurs operational penalties is self-defeating, because there is no one other than the customers to bear the cost of the penalty. PGP cites Bonneville as an example and notes that Bonneville must recover all costs from its customers.

\532\ E.g., ISO New England, PJM, MISO, SPP, and Ameren.

Commission Determination

868. This section of the Final Rule primarily addresses how transmission providers should distribute operational penalties they incur when taking transmission service under their own tariff. RTOs and independent transmission coordinators do not take transmission service, so most of the discussion in this section of the Final Rule is simply not applicable to either RTOs or independent transmission coordinators. RTOs and independent transmission coordinators are bound however by the requirement to distribute revenues they receive when they assess operational penalties. We address whether RTOs or independent transmission coordinators are subject to operational penalties due to processing transmission service request studies on an untimely basis in section V.C.5.a of this Final Rule. We address whether RTOs are subject to civil penalties in section 0 of this Final Rule.

869. We do not agree with those arguing that a non-profit transmission provider should be exempt from the requirement to distribute unreserved use penalties it pays when taking service under its own tariff. To the extent that a not-for-profit transmission provider incurs an operational penalty as a result of its activities as a transmission customer, it is still required to distribute penalties to non-offending customers. A non-profit transmission provider would only incur an operational penalty as the result of its wholesale marketing operations. As such, a non-profit transmission provider would pay for any operational penalty it incurs by using the profit it has earned through its wholesale marketing operations. 6. ``Higher of'' Pricing Policy

870. As noted in the NOPR, the Commission is concerned that some transmission providers may not be applying our existing pricing policies consistently and, as a result, customers may be quoted prices that are not consistent with the ``higher of'' policy.\533\ The practice of quoting customers an incremental rate as a lump sum payment is inconsistent with our ratemaking policy and has the potential to discourage customers from proceeding with service requests.\534\ Under the Commission's ``higher of'' pricing policy, when the requested transmission service requires network upgrades, the transmission provider should calculate a monthly incremental cost transmission rate using the revenue requirement associated with the required upgrades and compare this to the monthly embedded cost transmission rate, including the expansion costs.\535\ This incremental rate should be established by amortizing the cost of the upgrades over the life of the contract.\536\

\533\ In Order No. 888, the Commission stated that system expansions should be priced at the higher of the embedded cost rate (including the expansion costs) or the incremental cost rate, consistent with the Transmission Pricing Policy Statement. See Inquiry Concerning the Commission's Pricing Policy for Transmission Services Provided by Public Utilities Under the Federal Power Act, Policy Statement, 59 FR 55031 at 55037 (Nov. 3, 1994), FERC Stats. & Regs. ] 31,005 at 31,146 (1994), order on reconsideration, 71 FERC ] 61,195 (1995) (Transmission Pricing Policy Statement).

\534\ Southwest Power Pool, Inc., 100 FERC ] 61,096 (2002) (designing a rate to include a balloon payment is not a substitute for a properly designed rate).

\535\ Southwest Power Pool, Inc., 112 FERC ] 61,319 at P 33 (2005).

\536\ See Southwest Power Pool, Inc., 98 FERC ] 61,256 at 62,026, reh'g denied in pertinent part, 100 FERC ] 61,096 (2002) (``We agree with SPP that the amortization period for upgrade costs should match the contract period * * * As the customer is only obligated to take service for the term of the contract, it is reasonable that the costs only be amortized over the term of the contract.'').

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NOPR Proposal

871. As a result of the Commission's concerns regarding application of the ``higher of'' pricing policy, the Commission sought comments in the NOPR on whether changes to the pro forma OATT are necessary to ensure that incremental cost transmission rates are presented as monthly rates for service. Comments

872. Several commenters agree that incremental cost rates must be expressed as monthly rates, but do not believe that imposing this requirement requires changes to the pro forma OATT.\537\ To ensure transparency, Bonneville recommends that transmission providers post on their OASIS the methodology used to calculate incremental rates. APPA suggests that the Commission simply state in the preamble to the Final Rule that the transmission provider must include a proposed incremental rate in its offer of service.

\537\ E.g., APPA, Bonneville, and Public Power Council.

873. Other commenters see no need for clarification at this time. Southern states that it is not aware of problems regarding the calculation of incremental rates. Southern requests that the Commission consider allowing deviations to the Commission's ``higher of'' pricing policies and to allow all transmission providers, not just RTOs, to utilize participant funding. MidAmerican suggests the Commission defer consideration of possible changes to the pro forma OATT regarding this issue until the Commission undertakes comprehensive transmission pricing reform.

874. Other commenters support changes to the pro forma OATT that will ensure that incremental costs are presented as monthly rates for service.\538\ EPSA suggests that the Final Rule include an example of an appropriate monthly revenue requirement calculation and the upgrade costs included in the monthly rate. Suez Energy NA supports this proposed change but requests that the transmission provider be required to provide in a clear format the existing transmission rate, the lump sum cost of the upgrades, and the incremental rate.

\538\ E.g., ELCON, Constellation, FirstEnergy, NorthWestern, PGP, TDU Systems.

875. Some commenters ask the Commission to further clarify, or establish additional requirements, regarding incremental rates. Entegra states that the incremental rate should be stated as both a monthly unit rate and a lump sum representing the net present value of the upgrade costs with all inputs and assumptions in the calculation disclosed. Entegra further contends that the customer should be allowed to choose between paying the incremental rate, the lump sum, or some combination of the two (e.g., to pay an incremental rate over some period of time and then to pay the balance of the upgrade costs as a lump sum). While Morgan Stanley supports the Commission's clarification that the transmission provider may not demand a lump sum payment as a condition of providing the requested service, it asks that transmission providers not be precluded from offering a lump sum payment option, or any other mutually agreeable approach, to customers.

876. MidAmerican, EEI and Allegheny recommend that the Commission clarify that the transmission provider is not currently limited to charging the customer the rate per MW-month specified in the facilities study for the entire term of service if the customer pays the incremental cost of the network upgrades. These commenters explain that the transmission provider's revenue requirement with respect to the incremental cost of network upgrades will vary over the customer's term of service in the same way as its embedded cost of service will vary, including the cost of capital, operations and maintenance expense and administrative and general expense. EEI argues that the transmission provider should have the same right to modify a rate based on incremental costs pursuant to section 205 that it has to modify embedded cost rates and that the transmission provider should be permitted to present an incremental cost rate as a formula rate.

877. Seattle states that incremental costs may require more rigorous treatment than simply stating a monthly rate, since the cost of expansion is very path specific and often the expansion will affect multiple beneficiaries. According to Seattle, the ``higher of'' pricing policy will often hinge on contestable assumptions regarding the beneficiaries of discrete expansion projects and the grey area that separates reliability related aspects of new transmission projects from projects intended to provide commercial benefits.

878. Great Northern requests that the Commission clarify that a transmission customer may adjust the term of its requested transmission service contract to provide a longer period for amortizing the cost of necessary system upgrades once the incremental cost of expansion is disclosed by the transmission provider, as the Commission seems to suggest in the NOPR.\539\ In contrast, Allegheny states that the amortization period for the cost of an upgrade should not exceed the requested term of the contract, even if exercise of the rollover option by the customer is anticipated because transmission providers must have assurances of cost recovery for upgrades necessitated by customer decisions.

\539\ See NOPR at P 285 (``Presenting the incremental charge in the form of a monthly rate allows a customer seeking a lower rate to choose to request a longer transaction term.'').

879. TAPS and EEI recommend that the Commission modify sections 19.3 and 19.4 of the pro forma OATT to specify that the transmission provider must present the incremental costs of transmission service on a $/MW month basis contemporaneous with providing the facilities study to the customer. TAPS further states that similar changes should be made to sections 32.3 and 32.4 of the pro forma OATT, to ensure that network customers are not scared off by inappropriate presentations of network upgrade costs. TAPS explains that, while more complex, it believes that ``higher of'' pricing can work in the context of network service if applied in a comparable manner to the transmission provider's treatment of the upgrades needed for service to its retail native load.\540\

\540\ Citing Midwest Indep. Transmission Sys. Operator, Inc., 109 FERC ] 61,085, P 57 (2004) (applying Order 2003 crediting mechanism to network customers).

880. ISO New England and PJM state that the Commission's pricing concerns are not present for their respective markets and, therefore, any rule promulgated in this proceeding should not apply to these RTOs.

881. TAPS argues that creditworthiness or security requirements associated with network upgrades for a transmission customer (in sections 19.4 and 32.4 of the pro forma OATT) must be distinguished from the incremental cost or pricing of the upgrade. Otherwise, the customer may mistake a demand for security for a request for upfront payment of the entire cost of the upgrade.

882. In reply comments, EEI states that it continues to support the Commission's proposed modification to the way in which the transmission

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provider presents information on the incremental cost of network upgrades and asserts that nothing in the initial comments justifies a change in the Commission's policies with respect to the pricing of transmission service. EEI states that changes in transmission pricing policy, such as NRECA's proposal to require rolled-in pricing for network customers and TAPS's proposal to exempt network customers from security for the payment of costs related to network upgrades, are outside the scope of this proceeding. Commission Determination

883. In the NOPR, the Commission sought comments on the narrow issue of whether changes to the pro forma OATT are necessary to ensure that, consistent with our ``higher of'' policy, incremental cost transmission rates are presented as monthly rates for service. The Commission did not propose any changes to the underlying pricing policy. Commenters' proposals to change or clarify the Commission's transmission pricing policy are therefore outside the scope of this proceeding.\541\ Other comments are directed toward the application of our ``higher of'' policy in individual cases. These include the comments of Seattle (on the need to accurately identify the beneficiaries of the network upgrades), TAPS (on the use of ``higher of'' pricing in the context of network service), and EPSA (asking the Commission to present an example calculation of costs and rates). We will not address those comments here because they involve issues that are largely fact-specific that are best addressed on a case-by-case basis.

\541\ Comments that fall into this category include those of Entegra, Suez Energy NA, Morgan Stanley, MidAmerican, EEI (regarding the right to modify incremental rates) and Allegheny.

884. Based on the remaining comments received, the Commission concludes that changes to the language of the pro forma OATT to address this matter are not needed at this time. We believe that the existing pricing policy provides sufficient information for transmission customers to make an informed decision regarding a request for service.\542\ Transmission providers must continue to include a proposed monthly incremental rate with their offer of service whenever the transmission provider proposes to charge the customer an incremental rate, as well as cost support indicating the derivation of the rate calculation consistent with the cost support that the transmission provider would provide to the Commission in a section 205 rate filing. Because transmission providers are required to explain the calculation of their incremental rate, we conclude that the transmission provider need not post on its OASIS the calculation methodology, as recommended by Bonneville. Similarly, in response to TAPS's concern about security payments, the transmission provider's explanation should allow the customer to clearly distinguish between any security requirements associated with the service and the incremental cost of the service.

\542\ Because the Commission declines to adopt changes to the pro forma OATT regarding the ``higher of'' pricing policy, the requests of ISO New England and PJM to exempt ISOs and RTOs from tariff changes related to that policy are moot. Procedures regarding implementation of the Final Rule by ISOs and RTOs are otherwise discussed in section IV.C.

885. We will not adopt Great Northern's recommendation to require the transmission provider to permit the customer to opt for a longer contract term (to obtain a longer amortization period and a lower rate) once the incremental cost of the upgrades has been determined. The specific upgrades required to provide transmission service may depend on the time period over which the service is provided; therefore, allowing the customer to opt for a longer contract term may trigger a need for additional, or different, upgrades. 7. Other Ancillary Services

886. Other than the pricing of imbalances, the NOPR did not address pricing issues related to ancillary services required under the pro forma OATT. A few commenters nonetheless proposed revisions to the pro forma OATT regarding the pricing and procurement of, and other issues related to, ancillary services. a. Demand Response Comments

887. Alcoa submits that load resources (i.e., demand response) should be permitted to self-supply and, under certain circumstances, sell ancillary services to third parties. Alcoa states that large customers such as aluminum smelters are capable of providing, for themselves and third parties, some ancillary services so long as they are not required to subrogate their aluminum business functions to the needs of the ancillary service markets. In Alcoa's view, demand resources such as Alcoa's smelter loads should be appropriately compensated as providers of ancillary services, recognizing their ability to contribute significantly to the operational flexibility of energy markets and the stability of the grid. Alcoa asserts that industrial loads' contribution to the reliability of the grid was demonstrated during the August 2003 Blackout, when Alcoa's smelters remained in operation and facilitated the restoration of the system. Accordingly, Alcoa asks the Commission to require transmission providers to recognize that demand response resources can be a substitute for ancillary services such as Energy Imbalance, Operating Reserve and Spinning Reserve. Commission Determination

888. With respect to Alcoa's concern regarding a transmission customer's own use of ancillary service, we note that the existing pro forma OATT requires transmission providers to permit transmission customers to purchase ancillary services from third parties or make alternative comparable arrangements for the provision of all ancillary services except for scheduling, system control and dispatch service and reactive supply and voltage control service. Regarding the sale of other ancillary services including energy imbalance, operating reserve and spinning reserve by load resources, we agree that such sales should be permitted where appropriate on a comparable basis to service provided by generation resources. Comparable treatment of load resources is consistent with Staff's August 2006 Assessment of Demand Response & Advanced Metering Report \543\ as well as provisions of EPAct 2005.\544\ We note that some RTOs and ISOs already allow demand response resources to participate in certain ancillary services markets, while participation of such resources in other ancillary services markets is being studied. We therefore modify Schedules 2, 3, 4, 5, 6, and 9 of the pro forma OATT to indicate that Reactive Supply and Voltage Control, Regulation and Frequency Response, Energy Imbalance, Spinning Reserves, Supplemental Reserves and Generator Imbalance Services, respectively, may be provided by generating units as well

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as other non-generation resources such as demand resources where appropriate.

\543\ In the Demand Response Report, staff recommended that federal and state regulators consider whether to allow appropriately designed demand response resources to provide all ancillary services including spinning reserve, regulation, and any new frequency responsive reserves. Demand Response Report at 97-100.

\544\ Section 1252 (f) of EPAct 2005 states: ``It is the policy of the United States that time-based pricing and other forms of demand response, whereby electricity customers are provided with electricity price signals and the ability to benefit by responding to them, shall be encouraged, the deployment of such technology and devices that enable electricity customers to participate in such pricing and demand response systems shall be facilitated, and unnecessary barriers to demand response participation in energy, capacity and ancillary service markets shall be eliminated.''

b. Procurement and Pricing of Ancillary Services Generally Comments

889. Steel Manufacturers Association contends that the pro forma OATT's approach to other generation-based ancillary services should recognize that regional ancillary services markets do a better job of ensuring system reliability and holding down ancillary services costs than ancillary services provided on a control area by control area basis. Steel Manufacturers Association cites to MISO and SPP reports that provide evidence that ancillary services provided across large geographical regions are more effective and economical than when those services are provided by single utilities. For example, Steel Manufacturers Association notes that the SPP report concluded that, if a single Area Control Error were used for SPP, energy used for regulation service could be reduced by approximately 30 percent. Steel Manufacturers Association contends that, although ancillary services markets in the organized markets have proven successful at ensuring reliability and at keeping ancillary services costs low and predictable, utilities outside of the RTO and ISO markets continue to provide ancillary services primarily from their own limited pools of generation resources.

890. Occidental and Steel Manufacturers Association propose that transmission providers should be required, if feasible, to competitively procure ancillary service products if there are suppliers of such services other than the vertically integrated merchant function. Occidental argues that such procurement will result in just and reasonable rates for these generation-related ancillary services that reflect their cost-effective market-based competitive supply. In Occidental's view, competitive procurement of ancillary services will also help assure non-discriminatory treatment of transmission customers since transmission providers will have less incentive to favor their merchant function in the provision of generation-related ancillary services. Occidental notes that such procurement should be conducted in a manner consistent with reliability.

891. Alcoa argues that the transmission provider's costs of providing ancillary services for the network as a whole should not be socialized on a MWh basis without regard to the relative cost burden that specific customers impose on the transmission system. Alcoa contends that, while a particular consumer may use a considerable quantity of energy, the cost of serving that customer beyond the per- unit energy cost may be much less than it would be for other individual customers or groups of customers. Commission Determination

892. The Commission recognizes that there can be possible economic and reliability benefits to larger geographic markets for ancillary services, as suggested by Steel Manufacturers Association. However, as stated in the NOPR and repeated above the purpose of this rulemaking is to strengthen the pro forma OATT to ensure that it achieves its original purpose--remedying undue discrimination--not to create new market structures or, as proposed here, to modify existing market structures. We do not believe that altering the scope of the current ancillary services markets is needed to remedy undue discrimination at this time.

893. Similarly, we conclude that a fundamental overhaul of the current procurement and pricing of ancillary services, as proposed by Occidental and Steel Manufacturers Association, is beyond the scope of this proceeding.\545\ The pro forma OATT already permits transmission customers to make alternative arrangements to satisfy certain of their ancillary services obligations. Therefore, transmission customers are free to seek out competitive providers for those ancillary services other than scheduling, system control and dispatch service and reactive supply and voltage control service from third party suppliers. We also find Alcoa's contention that the transmission provider's costs of providing ancillary services for the network as a whole should not be socialized on a MWh basis without regard to the relative cost burden that specific customers impose on the transmission system, to be beyond the scope of this Final Rule.

\545\ We note, however, that the rates charged for these ancillary services must be just and reasonable under the Commissions standard of review. Thus, if less expensive options to supply ancillary services (including from demand side resources) are available, we would expect the transmission provider to examine such options.

c. Pricing and Procurement of Reactive Power Comments

894. Several commenters \546\ suggest that the Commission consider the need for reform of the methods of compensation for the provision of reactive power.

\546\ E.g., SPP, Alcoa, and Occidental.

895. Alcoa argues that ancillary services pricing should recognize the efficiency contributions made by load as a result of their demand response capabilities and the contribution that load located near generators makes to the provision of reactive power in particular. Alcoa states that the localized supply of reactive power near load centers can alleviate transmission constraints and allow cheaper real power to be delivered into a load center, as the provision of such reactive power increases the available flow for real power between two points. Alcoa argues that the pro forma OATT should recognize and credit the manner in which certain loads' location and load profile allows for the provision of reactive power and contributes to real power transfer capability.

896. Occidental objects to the existing requirement that transmission customers purchase reactive power service from the transmission provider, arguing that numerous independent generators provide reactive supply and voltage control to support transmission service in competitive wholesale markets. Occidental states that the Commission should formalize the policy of compensating generators on a comparable, non-discriminatory basis for several ancillary services, particularly providing reactive power capability, by requiring changes to the pro forma OATT to mirror the changes accepted by the Commission to the PJM and MISO tariffs. Occidental contends that amending the pro forma OATT to formalize this policy would be consistent with the FPA and achieving non-discriminatory access to transmission. Occidental notes that PJM and MISO amended their tariffs to provide equal compensation to affiliated and non-affiliated generators based on the generation owner's monthly revenue requirement for reactive supply and voltage control as accepted by the Commission. Occidental also notes that, when addressing generator interconnection agreements in Order No. 2003-A, the Commission stated that ``if the Transmission Provider pays its own or its affiliated generators for reactive power within the established [power factor] range, it must also pay [the interconnecting, independent generator].'' \547\

\547\ See Order No. 2003-A at P 416.

897. SPP requests that the Commission reform its reactive power pricing methodology, which has grown

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out of AEP Serv. Corp.\548\ SPP contends that the Commission can reduce uncertainty and litigation surrounding the pricing of reactive power by acting generically in a rulemaking rather than causing the industry to litigate reactive power pricing issues on a case-by-case basis. SPP argues that, based on its studies, it does not expect to call upon IPPs to provide reactive power; and therefore, it should not be required to pay for reactive power. SPP questions whether paying all IPPs a reservation charge, regardless of any determination of need or of the location of the plant and the locational need for reactive power, provides the appropriate siting incentives. SPP contends that the Commission can reduce the uncertainty and litigation by acting generically rather than causing the industry to fully litigate these issues in numerous cases before various courts. In addition, SPP challenges whether the AEP pricing method for reactive power continues to be appropriate. SPP suggests the Commission consider alternative pricing options, such as: Tying compensation to the actual provision of reactive power; eliminating compensation for the ninety-five percent leading/lagging band contained in most interconnection agreements, as such costs may be considered as a cost of interconnection and included in the power sales price; or, allowing compensation only outside of the band or perhaps when a sale is displaced.

\548\ Opinion No. 440, 88 FERC ] 61,141 (1999).

Commission Determination

898. In Order No. 2003 et al., the Commission found that interconnection customers must be treated comparably with the transmission provider and its affiliates in terms of reactive power compensation. The Commission required the transmission provider to pay interconnecting generators for providing reactive power within the specified range if the transmission provider so pays its own generators or those of its affiliates.\549\ Commenters seeking reform of the methods of compensation for the provision of reactive power have not demonstrated that such reforms are needed at this time to remedy undue discrimination or that the current compensation method does not provide a comparable result. Accordingly, we do not believe that acting generically on pricing reactive power is needed at this time and we will continue to resolve compensation issues for reactive power to qualifying generators on a case-by-case basis based on the circumstances presented.

\549\ See Order No. 2003-B at P 119.

899. In response to SPP's specific proposals for the treatment of reactive power, we note that the Commission recently found that it is unduly discriminatory and non-comparable for SPP to apply a ``needs'' test to reactive power capability for independent power producers to receive compensation that is not also applied to all other generating plants in its vicinity.\550\ The Commission also found that parties may make a separate FPA section 205 filing with the Commission with criteria, applied comparably and prospectively, that would determine which generators would receive reactive power compensation.

\550\ See Calpine Oneta Power, L.P., 116 FERC ] 61,282 (2006).

900. Finally, Alcoa's assertion that certain loads' location and load profile allows for the provision of reactive power to the transmission system is consistent with Staff's February 2005 report, Principles for Efficient and Reliable Reactive Power Supply and Consumption,\551\ as well as the above-cited provisions of EPAct 2005. As previously discussed, we have modified Schedule 2 of the pro forma OATT to allow for the provision of Reactive Supply and Voltage Control from demand resources where appropriate.

\551\ See Staff Report: Principles of Efficient and Reliable Reactive Power Supply and Consumption (Docket No. AD05-1-000), available at http://www.ferc.gov/EventCalendar/Files/20050310144430-02-04-05-reactive-power.pdf. Staff noted that in many cases load

response and load-side investment could reduce the need for reactive power capability in the system and that increasing reactive power at certain locations (usually near a load center) can sometimes alleviate transmission constraints and allow cheaper real power to be delivered into a load pocket. See id. at 4, 108. The report also noted that distributed generators have the same reactive power characteristics as large generators, with both producing dynamic reactive power, and that the amount of reactive power does not necessarily decrease when voltage decreases. Id. at 27.

D. Non-Rate Terms and Conditions

1. Modifications to Long-Term Firm Point-to-Point Service a. Planning Redispatch and Conditional Firm Options

901. The current pro forma OATT requires the transmission provider to provide two types of redispatch service: Planning redispatch and reliability redispatch.\552\ Planning redispatch is a product that Order No. 888 required transmission providers to use, in certain circumstances, to create additional transmission capacity to accommodate a request for firm transmission service. Specifically, the existing pro forma OATT requires the transmission provider to expand or upgrade its transmission system or, if it is more economical, plan to redispatch its resources to provide requested firm point-to-point service, provided redispatch does not (1) degrade or impair the reliability of service to native load customers, network customers and other transmission customers taking firm point-to-point service or (2) interfere with the transmission provider's ability to meet prior firm contractual commitments to others.\553\ The transmission provider must first identify planning redispatch options in the system impact study in conjunction with identifying relevant system constraints that impact the service request.\554\ When a system impact study and facilities study identify planning redispatch as a more economical means of relieving a transmission constraint than a transmission upgrade, the customer is obligated to pay the costs of redispatch consistent with Commission policy.

\552\ In Order No. 888, the Commission referred to planning redispatch as economic redispatch. Here we avoid the term economic redispatch because in the last ten years it has taken a different meaning in the industry and because we will no longer require that planning redispatch be capped at the cost of expansion.

\553\ See pro forma OATT section 13.5.

\554\ See pro forma OATT section 19.3.

902. Reliability redispatch is required, when feasible, to relieve system constraints that would otherwise cause curtailment of the network customer or transmission provider loads. To provide reliability redispatch, the transmission provider redispatches all network resources and transmission provider resources on a least-cost basis. The transmission provider and network customers each pay a load ratio share of these redispatch costs.\555\

\555\ See pro forma OATT sections 33.2-33.3.

NOPR Proposal

903. In the NOPR, the Commission stated its belief that current practices for evaluating long-term firm point-to-point service may not be comparable to the manner in which transmission service is planned for bundled retail native load and may no longer be just, reasonable and not unduly discriminatory. The Commission described two potential solutions: modifications to the planning redispatch provisions and conditional firm point-to-point service.\556\ The Commission proposed to modify the existing planning redispatch option by (1) accelerating the study of planning

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redispatch in the transmission request study process, (2) requiring an estimate of the number of hours of redispatch that may be required to accommodate the requested service, (3) requiring a preliminary estimate of the cost of planning redispatch, and (4) pricing planning redispatch services to facilitate increased availability of the service.\557\ The Commission suggested that conditional firm service could also be used to accommodate additional transactions, defining the service as a form of firm point-to-point service that includes less-than-firm service in a defined number of hours of the year when firm point-to-point service is unavailable. The Commission sought comment on its preliminary view that planning redispatch is the superior option because, in part, it is comparable to the way the transmission provider plans for bundled retail native load.

\556\ Conditional firm point-to-point service (hereinafter conditional firm service) and planning redispatch point-to-point service (hereinafter planning redispatch service) are options available under long-term firm point-to-point service.

\557\ The Commission did not propose to modify the reliability redispatch provisions that exist in the network integration transmission sections of the pro forma OATT.

904. The Commission's October 12 Technical Conference focused, among other things, on issues related to the planning redispatch and conditional firm proposals in the NOPR. On November 15, 2006, the Commission issued a notice (November 15 Notice) requesting supplemental comments on a transparent redispatch proposal submitted by Transparent Dispatch Advocates (TDA proposal) and certain aspects of the conditional firm option.\558\ The Commission also requested comments regarding the conditional firm option, including whether it is a complementary service to planning redispatch, whether it should be available for all long-term requests or limited to a request where the customer agrees to pay for upgrades, potential modeling problems, and requirements for defining the conditions under which the service would be curtailable.\559\

\558\ The following summary reflects comments received as initial and reply comments to the NOPR, as well as supplemental comments received in response to the November 15 Notice. Some commenters have changed their positions over time and these summaries reflect the most recent position expressed by commenters.

\559\ Questions relating to the TDA proposal are discussed later in this section.

Comments

905. Some commenters agree with the Commission's preference for modifications to planning redispatch over development of conditional firm service.\560\ They state that the attributes of conditional firm service are not clearly defined and key implementation issues are unresolved. They state that using planning redispatch to the maximum degree feasible, while not interfering with reliability, is inherent in maximizing the efficient use of the transmission system and should be fully evaluated before undertaking expensive expansion of the transmission system. Other commenters state that conditional firm service will create significant complications for transmission providers and disincentives to build transmission in exchange for limited and questionable benefits for new point-to-point customers or LSEs.\561\ EEI, Indianapolis Power and Ameren express doubt that customers would agree to be curtailed during peak usage periods. In response, AWEA contends that existing resources serving load would be able to manage curtailment risks so long as they could reasonably predict the curtailed hours.

\560\ E.g., Exelon, FirstEnergy, ELCON, MidAmerican, Arkansas Commission, MISO, and East Texas Cooperatives.

\561\ E.g., EEI, Indianapolis Power, Ameren, and Northwest IOUs.

906. Most independent power producers and a few other entities support the inclusion of both services in the pro forma OATT, stating that the services are required to remedy undue discrimination and provide for comparable transmission service.\562\ Western Governors believe that the planning redispatch and conditional firm options are important to fully use the existing transmission grid and to enable new intermittent generation resources to reach markets. To build the case for transmission expansion, the Western Governors argue, it is important to demonstrate that the existing grid is being effectively utilized; approval of both options will help make this necessary demonstration. EPSA and AWEA state that, while they believe transmission providers should be required to offer both services, conditional firm service may be simpler and less costly to implement because it involves the transmission provider directing the customer to turn off its resources during a contingency. Similarly, Bonneville suggests that conditional firm service is a reasonable alternative to planning redispatch where a transmission provider cannot provide both options. Commenters state that the Commission should require transmission providers to offer conditional firm service and planning redispatch and allow customers to choose the option that best suits the physical, commercial and economic circumstances of the request.\563\

\562\ E.g., EPSA, AWEA, Entegra, BP Energy, Newmont Mining, Sempra Global, Suez Energy NA, PPM, Utah Municipals, Williams, Morgan Stanley, PPL, Project for Sustainable FERC Energy Policy, California Commission, CREPC, TranServ, South Carolina E&G, Constellation, Barrick Supplemental, Xcel Supplemental, and Bonneville Supplemental.

\563\ E.g., California Commission Supplemental, Williams Supplemental, Constellation Supplemental, and Barrick Supplemental.

907. On the other hand, many commenters argue that the Commission should not require either option because the services are unnecessary, operationally unworkable, and legally unjustified, or because they would harm reliability and the quality of existing network service and provide disincentives for transmission investment.\564\ Several commenters state that these services would make curtailments of existing firm service more likely and limit opportunities for use of secondary network service, thereby harming native load protections and reducing reliability, contrary to FPA sections 215 and 217 respectively.\565\ Others opposing both options put forth primarily reliability, cost causation and comparability arguments. For example, Duke states that the two options are antithetical to reliable grid operation because they would require a transmission provider to grant a long-term request with the prior knowledge that it cannot be accommodated. International Transmission states that the grid is already operating at capacity and that requiring the transmission provider to accommodate additional megawatt-hours of service during periods of system stress would increase the likelihood of system failure. While it recognizes that conditional firm service has been successful in parts of the Western Interconnection, NRECA contends a mandate would undermine responsible planning and expansion of the transmission grid by harnessing the transmission provider's planning and dispatch functions to frame more and more elaborate service conditions for conditional firm service. APPA, Southern and Progress Energy argue that both services may require adoption of a form of organized LMP market, an action that raises significant political opposition and would be contrary to the Commission's commitment in the NOPR to avoid such restructuring. Similarly, other commenters contend that the planning redispatch option is only appropriate for transmission providers who are members of an RTO, ISO or

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who have an independent administrator of their transmission system.\566\ Some of the commenters that urge rejection of both options state that a properly structured conditional firm service is preferable to the modified planning redispatch service should the Commission implement one of the services.\567\

\564\ E.g., Ameren, Duke, Entergy, Imperial, International Transmission, LPPC, Progress Energy, Santee Cooper, Salt River, Southern, Tacoma, TDU Systems, Community Power Alliance, Northwest IOUs, NorthWestern, NPPD, NRECA, Public Power Council, TVA, SPP Reply, South Carolina E&G Supplemental, E.ON Supplemental, MISO Supplemental, and APPA Supplemental.

\565\ E.g., Duke, EEI, LPPC, NRECA, NPPD, Progress Energy, Southern, Utah Municipals Reply, and Duke Reply.

\566\ E.g., CREPC, TVA, and East Texas Cooperatives.

\567\ E.g., EEI, Entergy, Ameren, Progress Energy, Santee Cooper, TAPS, E.ON Supplemental, TDU Systems Supplemental, LPPC Supplemental, Tacoma Supplemental, and PNM-TNMP Supplemental.

908. Several commenters prefer the development of conditional firm service over the modifications to the planning redispatch service because of the complexities surrounding redispatch costs and protocols.\568\ For example, in supplemental comments, EEI and Community Power Alliance state that, while not ideal, conditional firm service would provide an opportunity to meet customers' transmission needs and is preferable to Transparent Dispatch Advocates' redispatch proposal.\569\ They also contend that the conditional firm option would provide faster provision of service and relative certainty of timing and costs for a new customer and its lenders, while ensuring reliability and promoting infrastructure expansion, so long as transmission providers are permitted to work with their customers to devise appropriate service parameters. Entergy believes conditional firm service can provide benefits to transmission customers without unfairly socializing costs to native load and network customers of the transmission provider. Overall, a majority of commenters express support for some form of conditional firm service.\570\

\568\ E.g., Manitoba Hydro, Nevada Companies, Sacramento, Pinnacle, East Texas Cooperatives, Barrick Reply, APPA Supplemental, Community Power Alliance Supplemental, Entergy Supplemental, and TAPS Supplemental.

\569\ Section V.D.1.b contains a summary and in-depth discussion of the TDA proposal.

\570\ The following entities expressed some level of support for conditional firm service: EPSA, AWEA, Entegra, BP Energy, Newmont Mining, Sempra Global, Suez Energy NA, PPM, Utah Municipals, Williams, Morgan Stanley, PPL, Project for Sustainable FERC Energy Policy, California Commission, Western Governors, CREPC, TranServ, Constellation, Manitoba Hydro, Nevada Companies, Sacramento, Pinnacle, PNM-TNMP, Bonneville, EEI, Entergy, Ameren, Progress Energy, Southern, Santee Cooper, Seattle, LPPC, Salt River, and TAPS.

909. Several commenters argue that, if the services are required, the Commission should add to the services the following requirements: The services should not adversely affect reliability and service to firm customers or provide unduly preferential service to point-to-point customers; the services should be an interim option until transmission upgrades are in place to provide firm service; and, planning redispatch and conditional firm customers should bear the actual costs of the services received, including costs associated with system operational changes needed to accommodate the services.\571\

\571\ E.g., EEI, Southern, TAPS, Seattle, APPA, LPPC Supplemental, Tacoma Supplemental and E.ON Supplemental. Issues related to pricing of planning redispatch service are addressed in paragraphs V.D.1.a.3.c below.

910. A few commenters believe that the Commission should allow for regional differences in development of the new services.\572\

\572\ E.g., California Commission, PGP, Pinnacle, and Imperial.

Commission Determination

911. The Commission has determined that modifications to the current planning redispatch requirement and creation of a conditional firm option are both necessary for provision of reliable and non- discriminatory point-to-point transmission service. The planning redispatch and conditional firm options represent different ways of addressing similar problems. They can be used to remedy a system condition that occurs infrequently and prevents the granting of a long- term firm point-to-point service. These options also can be used to provide service until transmission upgrades are completed to provide fully firm service. Planning redispatch involves an ex ante determination of whether out-of-merit order generation resources can be used to maintain firm service. Conditional firm involves an ex ante determination of whether there are limited conditions or hours under which firm service can be curtailed to allow firm service to be provided in all other conditions or hours. As we explain below, both techniques are currently used under certain conditions by transmission providers to serve native load and, hence, it is necessary to make comparable services available to transmission customers in order to avoid undue discrimination.

912. We therefore find these options are complementary services that can remedy undue discrimination, facilitate the provision of long- term transmission service and provide customers with greater flexibility in choosing resources to meet their needs. There is support in the comments for development of some type of conditional firm service that would allow for a longer-term use of the grid when transmission is projected to be unavailable for a small portion of the year. Additionally, we note that both options could help integrate new generation more quickly. For example, when there is a lag between the time that a new generation resource becomes operational and the time that transmission upgrades can be built to accommodate the resource, these options allow power to reach customer loads at an earlier date. This can be particularly beneficial to renewable resources, such as wind, that can be constructed more quickly than the transmission upgrades necessary to deliver their power on a firm basis over the long-run.

913. We recognize, however, that both options raise reliability concerns. The proposal in the NOPR for planning redispatch service would require the transmission provider to predict system conditions for the term of the service request, a task that becomes more difficult, and hence less accurate, with longer-term requests. This poses several related problems. Because longer-term forecasts are inherently uncertain and the further into the future the forecasts, the less accurate they are, the provision of planning redispatch service can threaten the reliability of service to native load unless very conservative assumptions are used. This incentive to use conservative assumptions to protect native load, in turn, increases the likelihood that planning redispatch service will be denied. This, in turn, will increase the number of disputes as to whether the denials were discriminatory. Such disputes would pose enforcement problems because they will turn on long-term projections regarding load growth, generation resource additions, etc., that by definition involve some degree of subjectivity. Moreover, as we discuss below, there is evidence suggesting that, while transmission providers use planning redispatch to serve native load, they do not use it as a long-term tool to avoid future upgrades indefinitely.

914. In balancing the foregoing considerations, the Commission will modify the approach proposed in the NOPR in two principal respects. First, given the ability of both services to address similar problems, we have reconsidered the proposal that only one of the options should be required. We find that availability of both planning redispatch and conditional firm in the short-run is necessary to ensure that competitive power suppliers have comparable access to the grid. As discussed below, we will continue to require that transmission providers offer to provide planning redispatch under certain circumstances in which the transmission providers determine that there is insufficient ATC. If customers

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request study of planning redispatch, transmission providers have an obligation to seriously evaluate the provision of planning redispatch from their own resources and provide customers with information on the capabilities of other generators to provide planning redispatch. If planning redispatch is unavailable from the transmission provider's resources or inadequate to meet customers' needs, transmission providers have an independent obligation to offer conditional firm, if available, as part of the firm point-to-point service.\573\ Customers will have the choice of whether to request study of the planning redispatch option, the conditional firm option or both.

\573\ Application of planning redispatch and conditional firm service obligations to RTO and ISO transmission providers is discussed in section V.D.1.a.3.B.i below.

915. Second, we will not impose a planning redispatch or conditional firm obligation over the long run. Such an obligation is not, as described below, necessary to remedy undue discrimination and would otherwise pose reliability problems, put the transmission provider at risk for estimating the costs of long-term redispatch, and undermine incentives to upgrade the transmission grid. Therefore, we will limit the availability of both service options so that their duration is for a time period over which service can be reasonably provided without impairing reliability.\574\ This limitation scales back the existing planning redispatch requirement in section 13.5 of the pro forma OATT that could, in practice, allow for an open-ended obligation to provide planning redispatch in lieu of upgrading the transmission system (e.g., involving forecasts up to 30 years).

\574\ As explained in more detail below, we adopt limitations that are tailored to the two types of customers that may request the options. First, for customers that agree to support the construction of new transmission facilities, redispatch and conditional firm point-to-point service will be available as a bridge until such time as those facilities are constructed and the relevant conditions must be specified in the initial service agreement and are not subject to change. Second, for customers that do not agree to support the construction of new facilities, the transmission provider will be able to re-evaluate the conditions under which services are provided every two years.

916. We discuss in detail the comparability and reliability findings that support these decisions below. (1) Comparability NOPR Proposal

917. In the NOPR, the Commission expressed its preliminary view that current practices for evaluating long-term firm point-to-point service may not be comparable to the manner in which transmission service is planned for bundled retail native load and may no longer be just, reasonable and not unduly discriminatory.\575\

\575\ The Commission did not propose to modify the reliability redispatch provisions that exist in the network integration transmission sections of the pro forma OATT.

Comments

918. Some commenters challenge the Commission's authority to order planning redispatch or conditional firm service as a remedy for potential undue discrimination. EEI and others argue that planning redispatch is not necessary to eliminate actual or perceived undue discrimination because many transmission providers do not rely on redispatch in planning to serve native load.\576\ However, EEI also states that when transmission providers do incorporate redispatch into their system planning, they do so generally only when the cost of redispatch is lower than the cost of network upgrades and system reliability is not impacted. Some transmission providers state that they do not currently use planning redispatch in lieu of transmission construction in order to designate their network resources.\577\ On the other hand, Entergy and Southern state that they currently use or have used planning redispatch of their own resources on the same basis that they allow any network customer to redispatch from the network customer's resources. For example, Southern states that it has used the redispatch potential of its generators during off-peak/shoulder periods on an interim basis until completion of transmission upgrades to designate network resources that otherwise might be undeliverable.\578\ Entergy disagrees that there is undue discrimination because this service is not available to point-to-point customers, stating that network and point-to-point service are not similarly situated services. TDU Systems state that conditional firm service does not ensure comparability among types of transmission service or between transmission providers and transmission customers. NRECA and others argue that the Commission requires a better understanding of the degree to which comparability is a problem in providing point-to-point service before the Commission makes changes to point-to-point service.\579\ In supplemental comments, EEI contends that the record in this proceeding does not demonstrate that conditional firm service is necessary to remedy undue discrimination.

\576\ E.g., EEI, TDU Systems, NRECA, Southern, and Duke Reply.

\577\ E.g., Southern, Duke, and Progress. Duke suggests that the Commission exempt transmission providers from the obligation to provide redispatch if they commit not to use redispatch as a planning tool for native load, network customers or merchant functions.

\578\ Southern states that it offered this service on a comparable basis to a non-affiliated transmission customer.

\579\ E.g., TDU Systems and EEI Reply.

919. Others assert that it is not within the Commission's jurisdiction to order planning redispatch for point-to-point customers because this type of redispatch requires use of the transmission provider's generation resources.\580\ LPPC states that the comparability principle is wrongly applied to the use of generation by a transmission provider. In Salt River's view, the Commission proposal sets up its own form of discrimination by making redispatch of the transmission provider's resources mandatory while making redispatch of generation using firm point-to-point reservations and generation in other control areas voluntary.

\580\ E.g., LPPC, NPPD, Progress Energy, and Salt River.

920. Those that support development of both services support the Commission's statement in the NOPR that ``transmission owners may evaluate transmission availability to serve long-term transmission service requests in a manner that is not comparable with the method they use to evaluate transmission needs for bundled retail native load.'' \581\ They argue that this divergent treatment of internal transmission needs versus external transmission requests is unduly discriminatory and violates the FPA. EPSA states that the fact that point-to-point service requests can be rejected due to a few hours of predicted reliability problems in a year is ``evidence of a poor use of existing transmission capacity and display clear discrimination against non-affiliated generation and its customers.'' \582\ TransAlta states that its actual experience with planning redispatch in the Pacific Northwest demonstrates that planning redispatch is used discriminatorily to the benefit of some customers and the detriment of others.

\581\ E.g., AWEA, Utah Municipals, Project for Sustainable FERC Energy Policy, EPSA, and Barrick Reply citing NOPR at P 300.

\582\ EPSA Reply.

921. In support of conditional firm service, Manitoba Hydro and Tacoma reiterate their experience that long-term transmission service requests are being denied due to constraints occurring during a small percentage of the time within the requested period of service.

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EPSA and AWEA similarly state that a transmission provider will reject a long-term firm service request unless it can satisfy every element of the request. Manitoba Hydro and others state that, in an era of transmission under-investment, optimizing the capacity usage is paramount to system reliability.\583\ EPSA and AWEA further explain that the concept of turning off a generator to avoid system upgrades is not new; Maine Independence Station avoided expensive system upgrades by installing automatic switching devices to take it offline during certain system conditions. Seattle states that, according to the Seams Steering Committee of the Western Interconnection, utilization on most constrained paths is limited to only a few hundred hours per year and, therefore, it is highly likely that service under a conditional firm product could be offered for even a baseload plant without significantly impacting the capacity factor. Santee Cooper states that, unlike the planning redispatch option, conditional firm service is presumptively within the subject matter jurisdiction of the Commission.

\583\ E.g., EPSA, AWEA, and Project for Sustainable FERC Energy Policy.

922. Entergy states that the most comparable service for long-term point-to-point transmission customers is not a requirement that a transmission provider redispatch its own or network customers' resources to grant long-term firm point-to-point transmission service. The most comparable service instead is a service that allows the transmission provider to curtail the service granted, while permitting the point-to-point customer to obtain alternative, deliverable resources if and when such curtailments occur in real-time. Commission Determination

923. We reject arguments that planning redispatch service is unnecessary to remedy undue discrimination as a collateral attack on Order No. 888. The obligation to provide planning redispatch was established in Order No. 888. The modifications proposed in the NOPR did not increase the obligation placed on transmission providers to use their generation resources to provide planning redispatch to point-to- point customers. Rather, the proposed modifications merely added specificity to the redispatch information already required in a system impact study and adjusted the timing of when the transmission provider must study planning redispatch options.\584\ Therefore, many of the arguments raised, including arguments pertaining to the Commission's jurisdiction over transmission provider generation resources, are impermissible collateral attacks on the current planning redispatch obligation in Order No. 888. Entergy's argument that planning redispatch should not be available to point-to-point customers because they are not similarly situated to be able to provide redispatch from their own units thus ignores the current obligation for each transmission provider to provide redispatch from the transmission provider's resources, if available, in evaluating a request for long- term point-to-point service.\585\

\584\ See pro forma OATT section 19.3.

\585\ See pro forma OATT section 13.5.

924. Additionally, information in the comments counters the assertion that transmission providers do not use planning redispatch or service analogous to the conditional firm option for their own loads. Entergy and Southern volunteer that they have planned for redispatch of their own resources in order to designate network resources when ATC was unavailable.\586\ As a caveat, Southern states that it has planned for the use of redispatch only for an interim period until upgrades could be constructed to make the transmission service from the designated resource fully firm. Entergy states that it offers planning redispatch service to network customers that plan to use their own resources to provide redispatch in real time. Contrary to EEI's assertion about the record in this proceeding, commenters, such as EPSA and AWEA, explain that some transmission providers already employ automatic devices, such as special protection systems (SPS), to take resources offline during certain system conditions. In a way that is analogous to the proposed conditional firm service, these protection schemes are used to increase native loads' firm uses of the transmission system until a contingency occurs that reduces available transmission.\587\ This information, taken together, provides ample evidence to support our finding that transmission providers currently evaluate transmission availability to serve long-term firm point-to- point transmission service requests in a manner that is not comparable with the method they use to evaluate their own transmission needs and to integrate their resources to serve bundled retail native load.

\586\ Entergy and Southern. EEI's comments also indicate that at least a few transmission providers do rely on redispatch in planning to serve their native loads.

\587\ SPS, also known as remedial action schemes, are used to varying degrees in every NERC reliability region. For example, there are about 65 SPS in the Western Interconnection. See Western Electricity Coordinating Council Operating Procedures, Index, V-1 to V-5 (revised July 2, 2002). There are 8 SPS used by Florida Power and Light in FRCC. See Florida Power and Light Control Area Readiness Audit Report, 19 (March 10-11, 2004). Two SPS are used in the Southern Subregion of SERC. Reliability Coordinator Readiness Audit Report Southern Subregion Reliability Coordinator, 19 (March 27-30, 2006).

925. Furthermore, we wish to emphasize that, in making these findings in support of a conditional firm option, we are not relying on the findings to create a new service. This Final Rule retains the two services adopted in Order No. 888--point-to-point service and network service. Conditional firm service is not a third service, but rather represents a modification to the existing procedures for granting long- term point-to-point service and the curtailment priorities for that service. The primary purpose of conditional firm is to address the ``all or nothing'' problem associated with the current procedures for requesting long-term point-to-point service. Currently, a request can be denied because firm service is unavailable in a very few hours of the year. For a customer who needs long-term point-to-point service to support a long-term transaction, this leaves the customer in the position of trying to cobble together a collection of shorter-term requests to effectuate its transaction, e.g., arranging firm service in the periods when it is available and non-firm service in the other periods. Such a customer also risks interruption of the non-firm portion of its service for economic reasons, e.g., a day of non-firm service for the customer combining firm and non-firm service could be interrupted for another customer seeking one month of non-firm service. We do not believe such an approach is just and reasonable. It makes little sense to ask the customer to cobble together a collection of firm and non-firm requests when the transmission provider has better information about when the service may be available or unavailable. It is therefore appropriate to require the transmission provider to grant the service on a conditional basis, as we explain further below.

926. We are however modifying the planning redispatch obligation, and similarly limiting the conditional firm option, to better reflect the manner in which redispatch or special protections schemes are used by transmission providers, in recognition of certain legitimate reliability concerns and the inherent difficulty of long-term projections in this area. This Final Rule limits transmission providers' planning redispatch obligations by removing the current obligation to provide planning redispatch for an indefinite period as

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long as the redispatch is cheaper than the relevant transmission upgrades. We also limit the conditional firm option by linking it to the transmission upgrades or a biennial assessment of the conditions.

927. We find such an open-ended obligation to provide this service is not necessary to remedy undue discrimination, nor is it consistent with the need to maintain system reliability. As indicated above, transmission providers temporally limit their use of planning redispatch and curtailment of resources and there is no evidence that transmission providers use these options on a prolonged basis, e.g., for more than a few years, without upgrading their transmission systems. Rather, over the long run, transmission providers generally will construct sufficient transmission to integrate their resources on a firm basis. This is consistent with transmission planning requirements and the emphasis placed upon transmission expansion in this Final Rule. The modifications to long-term point-to-point service we adopt are consistent and comparable to the existing use of these options by transmission providers' bundled retail native loads. Thus, the planning redispatch and conditional firm options will be available primarily as interim measures until transmission systems are upgraded to meet the transmission service request. We believe this limitation will have the added benefit of lessening disincentives to provide the service so that more planning redispatch is offered to transmission customers by transmission providers.

928. We disagree with TDU Systems' statement that conditional firm service does not ensure comparability among types of transmission service or between transmission providers and transmission customers. TDU Systems' assertion is unsupported by any explanation or examples of how the conditional firm service would degrade comparability. Nevertheless, we believe the argument is essentially a collateral attack on Order No. 888. Order No. 888, not this rulemaking, created the distinction between point-to-point transmission service and network integration service. We did so to recognize the different ways in which transmission providers typically use their system. The two services are not precisely the same, nor were they intend to be identical. Nothing in this Final Rule changes these distinctions. Indeed, we are not changing the relative priorities applicable to firm point-to-point service, network integration service and service to bundled native load.\588\ These services do, and will continue to, share the same priority--the highest priority of firm service on the transmission provider's system. The only change, as it relates to the conditional firm option, is to allow the customer to elect to have its long-term firm transmission service interrupted under certain defined circumstances. This does not harm other firm customers. Indeed, it has precisely the opposite effect: it permits an interruption to maintain firm service to other customers. Moreover, we find, as indicated above, that conditional firm service is necessary to remedy undue discrimination.

\588\ See supra section V.D.5.b.

929. The addition of conditional firm service therefore does not significantly alter the existing balance between the point-to-point and network service. Customers of network service retain flexibility that is not enjoyed by point-to-point customers. Moreover, conditional firm does not reduce the availability of secondary network service or the ability of network customers to temporarily undesignate network resources any more than short-term firm point-to-point service already reduces the availability of these network customer options. We therefore reject TDU Systems' arguments and find that the addition of conditional firm service is necessary to remedy undue discrimination and will otherwise increase utilization of the grid without impairing system reliability. (2) Reliability (A) Ability to Predict Redispatch Opportunities and System Conditions in the Long Run Comments

930. Some commenters state that redispatch, used as a planning tool rather than as a short-term operational tool, is overly complex, prone to causing disputes, reduces reliability and thus should not be included in the pro forma OATT.\589\ Southern asserts that planning redispatch should not be required where it reduces reliability by reducing a utility's reserve margin, shifting the operational, reliability and economic risks from the new customer to native load, or causing a single contingency to overload the system. Additionally, Xcel states that pledging a network resource to support planning redispatch carries a risk of penalties for inadequate resources in some areas. MISO states that contingency conditions must be considered and respected when evaluating planning redispatch options so that there is no reliance on curtailment of service. MidAmerican and Progress Energy conclude that the customer must accept the risk of selecting planning redispatch service over transmission construction.

\589\ E.g., Duke, Entergy, WAPA, NRECA, NPPD, LPPC, and Southern.

931. Several commenters request modification of the existing planning redispatch provisions of the pro forma OATT.\590\ They state that the Commission should clarify that the current section 13.5 does not require planning redispatch when it would adversely affect system reliability or service to native load, network customers and other firm point-to-point customers or impair other contractual obligations. Indianapolis Power states that the Commission should modify section 13.5 to require all reasonable redispatch options be examined by the transmission provider.

\590\ E.g., EEI, Indianapolis Power, Public Power Council, Southern, Seattle, Sacramento, and LPPC.

932. In its reply comments, Southern explains that transmission providers fail to provide the currently required planning redispatch service to point-to-point customers because the service is impractical and would harm reliability. Southern contends that a redispatch scenario identified in a transmission plan may not be available in real time due to outages or loop flow. Southern is also concerned about the complications in planning and modeling that would occur if the transmission provider is required to redispatch multiple resources in order to accommodate multiple planning redispatch customers.

933. Similar to their arguments in favor of conditional firm, EPSA and AWEA state that planning redispatch is necessary because a transmission provider will reject a long-term firm service request unless it can satisfy every element of the request, even if reliability violations occur in only a few hours of the year. In its reply comments, EEI responds that there is no evidence to support the assertion that a transmission provider will reject a long-term firm service request unless it can meet every element of that request. EEI states that in such a situation the transmission provider must offer partial service, offer to perform a system impact study, and exercise due diligence in constructing needed upgrades to accommodate the request. EEI adds that the potential customer can also request short- term service. Finally, EEI states that there is no evidence that transmission providers are refusing to redispatch in response to customer request when redispatching resources would have no impact on reliability. In

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its reply comments, MISO states that denial of service complained of by EPSA and AWEA is a consequence of the customer's economic decision not to build upgrades.

934. Many transmission providers assert that the costs and inequities of achieving the proposed planning redispatch outweigh any new benefits for point-to-point customers.\591\ They state that the Commission's proposal is based on an erroneous assumption that redispatch is nearly always feasible; instead when redispatch is most desirable, generators operating at peak would not be available for redispatch.\592\ Southern also explains that problems of insufficient transmission capacity cannot be avoided by redispatching generation because there is no guarantee that a redispatch solution will be available during real-time operations. Imperial argues that the personnel and modeling costs to transmission providers of calculating planning redispatch costs prior to a facilities study are too excessive. Xcel concludes from a NERC experiment on market redispatch that redispatch involving non-market-based or bilateral coordination with third parties to protect a delivery path is cumbersome, inefficient, and does not promote reliability.

\591\ E.g., Duke, Entergy, Imperial, International Transmission, Salt River, Seattle, Southern, Tacoma, Northwest IOUs, Sacramento, Progress Energy, E.ON, Xcel, TVA, and EEI Reply.

\592\ E.g., Sacramento and TVA.

935. Xcel states that its estimate of hours of planning redispatch is unlikely to be accurate given that it uses a static power flow that is created for a specific peak hour and a specific off-peak hour in a given year. Commenters state that planning redispatch service should not be a guaranteed service because generation or transmission availability, system loads, loop flows from adjoining systems, weather, and fuel availability all entail a component of risk that should not be pushed back on the transmission provider or its native load.\593\

\593\ E.g., Progress Energy, E.ON, WAPA, Entergy, and MidAmerican.

936. Operators of systems that rely primarily on hydroelectric resources argue that planning redispatch should not be considered a viable option for their systems and they should be exempt from OATT planning redispatch obligations because hydroelectric operators are unable to make long-term commitments that a resource will be available to relieve transmission constraints.\594\ Bonneville states that the variability in water flows and the interdependence of the generating units contribute to the inability to predict future redispatch ability. Bonneville, WAPA and Bureau of Reclamation state that planning redispatch can conflict with federal obligations to operate federal dams and reservoirs in a manner that does not impact project purposes and provide preference in the sale of hydropower to its preference customers. Tacoma states that planning redispatch must be linked to market price indexes to work in a hydro-based system. Seattle states that in hydro-dominant systems fuel availability and fuel price risk undermine the feasibility of providing long-run redispatch cost estimates that reasonably reflect future costs. Seattle adds on reply that planning redispatch fails to address costs pertaining to fish species preservation, recreation and flood control impacts, increased risk of spill, or replacement power that are associated with hydroelectricity.

\594\ E.g., Bonneville, Seattle, Public Power Council, and WAPA.

937. Morgan Stanley argues on reply that the Commission should not exempt hydroelectric system operators from providing planning redispatch; instead, factors unique to hydroelectric systems should be taken into account in determining how much planning redispatch a transmission provider can provide. In supplemental comments, PPM agrees with Morgan Stanley and adds that hydro-based systems, such as Bonneville's, are flexible enough for a transmission provider to use planning redispatch to create additional firm capacity.

938. In their reply comments, Utah Municipals and EPSA state that planning redispatch would not impair reliability because the OATT provisions do not require transmission providers to permit intentional overloading of lines. Since transmission providers are already required to provide planning redispatch now, Utah Municipals contend that any change in the sequence for studying the option cannot have an impact on reliability. EPSA argues that claims of adverse reliability impacts should be dismissed because transmission providers do not make these same claims when they redispatch to enable transmission service to meet their own load obligations. Utah Municipals state that reliability would be most enhanced by completely restricting access to the grid, a policy that Utah Municipals do not recommend because it would be extraordinarily costly and promote discrimination. In its reply comments, Entegra states that customers seeking planning redispatch are not seeking to shift a disproportionate share of the risks or costs to native load or other users of the system.

939. In its reply comments, EPSA further argues that the Commission should place the burden of showing unreliability in a particular instance on the transmission provider. EPSA also argues that transmission providers should not be allowed to delay service through feasibility studies. EPSA contends that planning redispatch will not delay needed system upgrades and, instead, will ensure optimized use of the existing system that will provide additional information about the system's capabilities to regional planning initiatives. In its reply comments, Morgan Stanley states that the Commission should establish clear standards as to the degree of expected reliability that appends to a firm transmission sale and allow transmission providers to sell as much of the system as can be sold on a firm basis, consistent with maintaining the reasonable standard.

940. EEI and some transmission providers add that the conditional firm product could result in an oversubscription of a transmission system in violation of NERC reliability standards that require the transmission system to be planned to meet all firm needs.\595\ ELCON states that conditional firm service may not truly support long-term contracts for firm power but may lead to a greater volume of short-term trading.

\595\ E.g., Ameren, Southern, and EEI.

Commission Determination

941. Many commenters are concerned that the options described in the NOPR will impair system reliability. We have taken these comments into account and have tailored the modifications to long-term point-to- point service so as to not impair system reliability. There are two important limitations that provide such protections. First, we make clear that transmission providers are not required to offer planning redispatch or conditional firm service if doing so would impair system reliability.\596\ Second, as explained above and discussed in further detail below, we are limiting the time period under which either option is offered. We do so because forecasts of potential redispatch or interruption options become more

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speculative over time and to require a transmission provider to commit for a substantial period of time, subject to the uncertainty inherent in such long-term projecting, has the potential to degrade reliability. With these two limiting conditions, we find that neither the planning redispatch nor conditional firm option will degrade reliability and, as discussed above, that both are necessary to remedy undue discrimination.

\596\ A transmission provider may not be able to provide conditional firm service without impairing the reliability of its system if it is required, for example, to manage many conditional firm point-to-point reservations across the same path. The ability of system operators to track, tag and manage curtailment of multiple conditional firm reservations is necessarily limited by time, human resources and other reliability-related duties of the operators.

942. We agree with a majority of commenters that over the long term, new resources should be supported by sufficient transmission capacity to deliver their output reliably. Imposing a planning redispatch or conditional firm obligation over the long-run would not be consistent with the need to increase the reliability of the grid or otherwise necessary to remedy undue discrimination. Rather, it would tend to degrade reliability over time, contrary to the public interest and the underlying goals of EPAct 2005. Projections of planning redispatch options and conditional firm conditions are more accurate in the near term and, hence, should facilitate the efficient use of existing resources without impairing reliability.

943. We therefore impose limits on the transmission provider's current planning redispatch obligations. We do so by removing the obligation to provide planning redispatch for an indefinite period as long as the redispatch is less expensive than the relevant transmission upgrades. Section 13.5 of the pro forma OATT could, in conjunction with rollover rights, allow for an extremely long-term obligation to provide planning redispatch in lieu of upgrading the transmission system. We find that this existing obligation may unreasonably harm reliability and provides incorrect incentives to delay necessary grid expansion. We emphasize that the obligation to provide planning redispatch applies only when the service can be provided reliably.

944. We also limit the time period over which a transmission provider must predict the system conditions or conditional hours that would apply to customers using the conditional firm option. We do so in recognition of the difficulty in attempting to forecast curtailment options over the long-term and the fact that there is no evidence that transmission providers perform similar forecasts for their native load customers. We do not, however, eliminate entirely the risk of predicting future system conditions or shift it in whole to the requesting transmission customer as requested by certain commenters. We believe that the transmission provider should retain responsibility for incorporating reasonable assumptions into its transmission models so that it can manage this risk, just as it currently manages the prediction risk in its ATC models.

945. We will now turn to certain clarifications and other issues raised by the commenters. We acknowledge that planning redispatch to support annual service may require redispatch of generation during the peak month or months. Since transmission providers plan their generation to meet their peak native load plus reserves, the transmission provider's resources may, in some cases, be fully employed to meet the needs of bundled retail native load and thus may not be available to provide redispatch during the peak period.\597\ In such an instance, the unavailability of such resources to provide redispatch service will constitute a legitimate basis for denying planning redispatch service. However, we will not excuse the existing obligation that requires transmission providers to study any available planning redispatch, including redispatch that might provide some but not all of the service requested. Given that some transmission providers have acknowledged their own use of planning redispatch for their network resources,\598\ the service must continue to be available to those seeking point-to-point service to ensure comparability.

\597\ See, e.g., Arizona Public Service Co. v. Idaho Power Co., 95 FERC ] 61,081 at 61,241 (2001) (resources projected to be unavailable during system peak month to provide planning redispatch).

\598\ E.g., Entergy.

946. We reiterate that the transmission provider remains obligated to provide planning redispatch from its resources as long as the planning redispatch does not (1) degrade or impair the reliability of service to native load customers, network customers and other transmission customers taking firm point-to-point service or (2) interfere with the transmission provider's ability to meet prior firm contractual commitments to others.\599\ We continue to believe these are the appropriate exceptions and will not adopt a broad and undefined reasonableness standard as suggested by Indianapolis Power. We agree with Southern that the transmission provider may consider the impact of the planning redispatch service in reducing its reserve margin below that necessary to maintain reliability or causing a single contingency to overload the system in determining whether the service can be reliably provided.

\599\ See also Order No. 888 at 31,739.

947. Further we will not excuse transmission providers from the obligation to manage multiple planning redispatch or conditional curtailment obligations simply because some commenters express concerns about planning and modeling impacts. While we do not take these concerns lightly, we believe they can be managed by transmission providers. The planning redispatch obligation has existed for ten years, and with it the potential for multiple planning redispatch requests. We have no evidence that transmission providers have been unable to manage the process. Moreover, by scaling back the time period for which transmission providers must plan for provision of redispatch, we have greatly reduced any planning and modeling impacts. We believe that whatever additional work the options cause with regard to planning and modeling, it is small and more than offset by the considerable value of the options which allow for more efficient use of the transmission system, expansion of long-term uses of the grid and remedying of undue discrimination.

948. Finally, we recognize the difficulty of predicting, over prolonged periods, whether hydroelectric resources will be available to provide redispatch. We agree with Morgan Stanley that factors unique to hydroelectric systems should be taken into account in determining how much planning redispatch a transmission provider can provide. For example, transmission providers operating hydro-based systems must predict both system load growth and water availability in order to determine whether resources will be available in the next few years to provide redispatch. We acknowledge that certain circumstances may in fact limit long-term redispatch on these systems due to increased prediction risks. We reiterate, however, that all transmission providers, including those operating hydro-based systems, are required to make a determination, regarding whether planning redispatch service can be provided consistent with system reliability based on the specific facts of a particular request for service. The fact that hydro-based systems may not be able to provide planning redispatch service under many circumstances should not necessarily limit the availability of conditional firm service on these systems. We expect that transmission providers with hydro-based systems will focus on provision of the conditional firm option in a manner consistent with their system conditions.

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949. We also repeat that planning redispatch service does not need to be provided if doing so would impair the firmness of service to existing transmission customers. For example, pre-existing federal obligations, such as those described by Bonneville, WAPA and Bureau of Reclamation, would qualify as the type of firm commitments to others that would excuse transmission providers from the planning redispatch obligation to the extent that redispatch impaired service to these customers. (B) Impact on Network Customers and Native Load

950. Several commenters argue that the use of planning redispatch may remove the ability to use reliability redispatch in real-time operations to respond to system contingencies, resulting in more curtailment of network and native load.\600\ In addition to reducing availability of redispatch as an operational tool, NRECA contends that planning redispatch will reduce ATC for network service and the incentive to build new transmission. Several commenters state that planning redispatch may unfairly shift costs to network and native load customers.\601\ Progress Energy argues that such a mandate places the power grid in serious jeopardy because the system has not been designed to handle the redispatch planning model. Progress Energy and Nevada Companies state that the planning redispatch option could conflict with transmission providers' state resource planning obligations to reliably serve load at least cost. Exelon replies, however, that planning redispatch could increase flexibility for network customers by increasing the availability of point-to-point service across adjacent transmission systems to bring generation to network loads.

\600\ E.g., EEI, Duke, Imperial, LPPC, PNM-TNMP, Public Power Council, NRECA, NPPD, Southern, and Progress Energy.

\601\ E.g., EEI, TAPS, LDWP, MidAmerican, Southern, Community Power Alliance, and MISO Reply.

951. Some commenters argue that the conditional firm option would adversely impact system reliability by subjecting firm customers to additional curtailments once conditional curtailment hours are exceeded.\602\ NRECA and Utah Municipals state that the conditional firm service will reduce the flexibility of network customers by preventing network customers from using secondary network service, a right that NRECA argues is protected by FPA section 217.

\602\ E.g., Duke, LPPC, NRECA, NPPD, Progress Energy, Southern, APPA, and South Carolina E&G.

Commission Determination

952. We reiterate that transmission providers are not required to offer planning redispatch and conditional firm point-to-point service if doing so would impair the reliable service to firm customers, including native load and network customers. The concerns of the commenters regarding the impacts on native load, network and other existing firm uses are therefore misplaced.

953. Transmission providers are already obligated to provide planning redispatch service pursuant to Order No. 888 and thus arguments that the planning redispatch option will harm existing customers is equally misplaced. Indeed, under the limitation on the duration of planning redispatch service imposed in this Final Rule, transmission providers will be able to better manage the risks of curtailment for current users of the transmission grid. This is because the obligation to redispatch will no longer be an open-ended obligation. Customers will need to commit to upgrade the system or to have their service reassessed periodically. Both of these allow the transmission provider to better plan to serve needs reliably because it reduces the unknowns. With regard to NRECA's argument that planning redispatch will cause less flexibility in real-time and more potential for curtailments of network customers and bundled retail native load, all sales of point-to-point service could to some extent cause more curtailments of network customers and bundled retail native load. Our decision today limits the existing planning redispatch obligation for point-to-point service, rather than expanding it.

954. Similarly, the conditional firm option does not reduce the availability of secondary network service or the ability of network customers to temporarily undesignate network resources any more than short-term firm point-to-point service already reduces the availability of these network customer options. We see no reason to reject the conditional firm option so that transmission providers avoid offering higher-quality service such as conditional firm point-to-point service in order to retain the ability to offer lower-quality service such as secondary network service.

955. Finally, we believe that network customers can benefit from the use of the planning redispatch and conditional firm options available in a point-to-point transmission service request. As described below, long-term point-to-point service that employs the planning redispatch or conditional firm option would qualify as a network resource on any adjoining system importing that resource. (3) Implementation of Planning Redispatch and Conditional Firm Options

956. Commenters raise various concerns regarding specific implementation issues associated with the planning redispatch and conditional firm options. We address those concerns below, but first provide an overview of the planning redispatch and conditional firm service required in this Final Rule in order to outline the new rights and obligations of transmission providers and customers. Following this overview, we address specific comments relating to the service.

957. Pursuant to the modified obligations adopted in this Final Rule, where a request for long-term point-to-point firm transmission service is made and cannot be satisfied out of existing capacity, the transmission provider shall, at the request of the customer and in the system impact study, identify (1) the transmission upgrades necessary to provide the service, and (2) the options for providing service during the period prior to completion of those transmission upgrades. Additionally, if upgrades cannot be completed prior to expiration of the requested service term, the transmission provider shall, at the request of the customer and in the system impact study, identify options for providing the service during the requested term. The options studied by the transmission provider must include planning redispatch and conditional firm options.\603\ The transmission provider, at its discretion, may study and offer a mix of planning redispatch and conditional firm options for a single service request. We provide further detail on each required option below.

\603\ Although partial interim service is not addressed in this rulemaking, we note that the OATT continues to require this service, on an as available basis, if a multi-year service request is denied.

958. If the transmission provider determines that planning redispatch is available, it shall provide the customer with non-binding estimates of the incremental costs of redispatch and identify the relevant constrained flowgates for which redispatch will be provided. For the conditional firm option, the transmission provider shall identify the conditions and hours pursuant to which the service may be curtailed, using a secondary network curtailment priority, to maintain reliability. Specifically, the transmission provider shall identify (1) the specific

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system condition(s) when conditional curtailment may apply and (2) the annual number of hours when conditional curtailment may apply. Customers agreeing to take conditional firm service must choose one of these options, conditions or hours.

959. Where the customer requests firm service for more than two years, but is unwilling to commit to a facilities study or the payment of network upgrade costs, the transmission provider shall identify and provide the planning redispatch or conditional firm options subject to the following limitation. The transmission provider shall have a periodic right to reassess (1) the planning redispatch required to keep the service firm or (2) the conditions or hours under which the transmission provider may conditionally curtail the service. This reassessment may occur every two years during the term of the service, i.e., at the end of year two, year four, year six, and year eight of a ten-year service. The transmission provider may not implement reassessments during intervening periods nor may it reassess the conditions in order to amend the service agreement in an intervening year should it forego any biennial reassessment.\604\

\604\ For example, if a transmission provider opts to forego the reassessment at the end of year two, the transmission provider may not reassess the conditions of the service again until the end of year four of service for imposition of new conditions starting in year five.

960. The service agreement shall specify the relevant congested transmission facilities and whether the transmission provider will provide planning redispatch, a mix of planning redispatch and conditional firm, or conditional firm in order to provide the point-to- point transmission service. For the conditional firm option, customers must choose among and the service agreement must specify either (1) specific system condition(s) during which conditional curtailment may occur or (2) annual number of conditional curtailment hours during which conditional curtailment may occur. We deem that any service agreement that incorporates planning redispatch or conditional firm options is a non-conforming agreement and must be filed by the transmission provider pursuant to section 205 of the FPA. Additionally, transmission providers must file with the Commission any amendments to these service agreements that result from reassessments. If a transmission provider proposes to change the redispatch or conditional curtailment conditions due to a reassessment, the transmission provider must provide the reassessment study to the customer along with a narrative statement describing the study and reasons for changes to the curtailment conditions or redispatch requirements no later than 90 days prior to the date for imposition of these new conditions or requirements. The transmission provider shall assess the conditions based on two years of service or the continuation of the term of service, whichever is less.

961. In situations in which the customer commits to paying the costs associated with upgrades necessary to provide the service on a fully firm basis, the conditions or hours identified by the transmission provider shall remain in effect until such time as the upgrades have been completed. Also, for such customers, the service agreement shall specify the upgrade costs as determined through the facilities study. (A) Eligibility for and Timing of Planning Redispatch and Conditional Firm Options NOPR Proposal

962. In the NOPR, the Commission proposed that customers who request long-term firm point-to-point transmission service and have the service denied because of lack of ATC would be eligible to receive planning redispatch service or, if the Commission chose to adopt the conditional firm service option, conditional firm service. The Commission also proposed earlier evaluation of the planning redispatch option in the system impact study rather than in the facilities study. The Commission proposed that, if it were to adopt conditional firm service, the evaluation of conditional firm availability should occur prior to a system impact study or facilities study. Comments

963. If the conditional firm option is required by the Commission, many commenters believe it should be a bridge product to span the gap between when the relevant transmission service request is being studied and when the relevant upgrades become operational.\605\ These commenters state that a bridge product is appropriate because it would not depress funding for new transmission infrastructure and would better meet the NOPR's and Congress' grid expansion objectives. In their view, use of a bridge product would avoid equity and free rider problems that may occur if a conditional firm customer is taking long- term service and the transmission system is upgraded during that service. They also argue that the bridge product would better allow for transmission providers to judge the likelihood of curtailment and avoid complicated system modeling and planning issues; as well as protect existing long-term transmission customers. Duke and Ameren state that an annual re-determination of the conditional period is necessary for a bridge product. If the upgrade has not been completed within a three year period, NRECA suggests that the customer be required to make a new long-term firm service request so the provider can update to reflect system conditions at that time.

\605\ E.g., Progress Energy Supplemental, PNM-TNMP Supplemental, LPPC Supplemental, APPA Supplemental, TAPS Supplemental, TDU Systems Supplemental, NRECA Supplemental, EEI Supplemental, Entergy Supplemental, Ameren Supplemental, Powerex Supplemental, and MISO Supplemental.

964. Several commenters suggest that transmission providers should offer conditional firm service as both a bridge product and as a stand- alone long-term firm service.\606\ Where not used as a bridge service, several commenters state that it should be limited to reservations that do not have rollover rights.\607\ Duke argues that the service duration for non-bridge service should be one year, but with renewal rights that give the conditional firm customer a priority over other non-bridge conditional firm service customers seeking capacity. APPA supports one to two-year service offers.

\606\ E.g., Bonneville Supplemental, PPL Supplemental, EPSA and AWEA Supplemental, EEI Supplemental, Barrick Supplemental, and Constellation Supplemental.

\607\ E.g., Xcel Supplemental, Duke Supplemental, and EEI Supplemental.

965. In supplemental comments, EEI supports a voluntary conditional firm product with three types of service: A one-year product with no rollover rights; a bridge product for a term of more than one year that is provided until upgrades necessary to accommodate a firm service request are completed; and a non-bridge product of more than one year, with no rollover rights or transmission provider obligation to construct upgrades and subject to the transmission provider's periodic review of its system capability to provide such service. EEI contends that the Commission should encourage transmission providers to offer conditional firm service for more than one year without rollover rights to a customer that is not willing to take service of sufficient length to allow recovery of upgrades costs, if such service can be provided without affecting the reliability and quality of service to firm transmission customers.

966. In support of limitations on the term of conditional firm service, many

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commenters state that analyzing and modeling system conditions will always be more accurate in the near term than in the long term.\608\ EEI and Community Power Alliance believe that limitations on system modeling prevent many transmission providers from accurately evaluating their ability to provide conditional firm service over long periods. According to EEI, system conditions change on both the transmission provider's and neighboring systems substantially affecting the ability of the transmission provider to provide conditional firm service and the periods such service is subject to curtailment. While system loads can be predicted with a reasonable degree of accuracy for more than one year, other components of the prediction model, such as transmission and generator outages, typically are not determined more than a year in advance. For example, EEI states that members in the SERC region coordinate transmission and generation outages in a 13-month planning horizon. Duke states that the ability to model the system varies significantly by region. Entergy and MidAmerican believe that system modeling limitations would present serious reliability problems if transmission providers were required to offer a multi-year conditional firm transmission product because even the most advanced modeling software cannot predict long-term conditions that may affect service. Entergy and MidAmerican propose that the Commission allow transmission providers to update the curtailment criteria for a reservation, to reflect, among other things, changing load assumptions and forecasts over time. MidAmerican argues that without annual reevaluation there would be cost shifts to other firm customers. In its reply comments, MidAmerican explains that this reevaluation can only occur when the actual data becomes available for projecting potential curtailment hours.

\608\ E.g., Nevada Companies Supplemental, TDU Systems Supplemental, LPPC Supplemental, Ameren Supplemental, Community Power Alliance Supplemental, MISO Supplemental, PNM-TNMP Supplemental, NRECA Supplemental, and Xcel Supplemental.

967. If a transmission provider offers conditional firm service based on specified system conditions, Bonneville states in supplemental comments that limitations on modeling do not present a problem. If, however, the service is based on a maximum number of conditional curtailment hours per year, Bonneville believes that modeling presents problems in offering longer-term service. Bonneville states that forecasting the number of hours of conditional firm service requires great analysis. To remedy this, Bonneville suggests allowing the transmission provider to make conditional firm offers under which the transmission provider could periodically adjust the number of conditional curtailment hours.

968. In supplemental comments, Constellation proposes that the Commission require transmission providers to offer two types of conditional firm service: service for less than the service term eligible for rollover rights (e.g., five years) if customers do not agree to pay for transmission upgrades; and service for five years or longer with a rebuttable presumption that the customer is obligated to pay for upgrades that are both economic and necessary to relieve the constraint that prevents its service from being fully firm.\609\ EPSA and AWEA maintain that it is critical that the conditions be defined, and remain unchanged, for the term of the service agreement in order to obtain financing of new projects. EPSA and AWEA also propose that, if the contingency is removed during the life of the customer's conditional firm service, the service should convert to traditional firm service. Williams, EPSA and AWEA argue that up-front commitment to continue the conditions for the entirety of a long-term service agreement would take no greater risk than transmission providers take today in committing to other long-term firm transmission service. EPSA and AWEA state that limited term conditional firm service should pose no problems based on system modeling.

\609\ EPSA and AWEA endorse Constellation's approach in defining and delineating the two forms of conditional firm service.

969. Several commenters believe that there is no need for any type of special rules for conditional firm customers taking bridge service and required to pay extremely expensive upgrades.\610\ If the Commission abandons the ``higher of'' pricing principle for upgrades, these commenters suggest that any new pricing policies should be consistent with cost-causation principles and not result in any improper socialization.\611\ Other commenters argue for special rules when upgrades are extremely expensive.\612\ Xcel states that customers should have the option to take short-term conditional firm service that would remain subject to limitation and curtailment if upgrades are too expensive. Constellation proposes that customers taking the longer-term service should have the opportunity to show that upgrades would not be just and reasonable given the relevant circumstances, e.g., the cost of upgrades for a single service request is $300 million. If the Commission determines that the bridge requirement in a particular circumstance is unjust and unreasonable, Constellation proposes that the transmission provider would provide the service for the requested term, but there would be no obligation for the transmission customer to pay for such upgrades, and the service would not be eligible for rollover. NRECA contends that instances in which special rules apply should be extremely rare and are best addressed by the transmission provider and customers on an ad hoc basis.

\610\ E.g., Nevada Companies Supplemental, Duke Supplemental, Bonneville Supplemental, Powerex Supplemental, BP Energy Supplemental, MISO Supplemental, PNM-TNMP Supplemental, Entergy Supplemental, Community Power Alliance Supplemental, and Southern Supplemental.

\611\ Proposals regarding the ``higher of'' pricing policy are discussed below.

\612\ E.g., Xcel Supplemental, Constellation Supplemental, and NRECA Supplemental.

970. Commenters recognize that upgrades required under a bridge conditional firm option could create lumpiness problems,\613\ but most commenters suggest that this problem is not unique to the conditional firm option, nor can it be resolved through use of the option.\614\ These commenters support continuation of the Commission's existing policies with regard to lumpiness issues, and some suggest the need to address the issue as it pertains to all upgrades in a future proceeding.\615\ In contrast, a few commenters suggest that the Commission should address the lumpiness issue with regard to conditional firm service. PPL, EPSA and AWEA state that the transmission provider should be required to pay the costs of any incremental lumpiness associated with upgrades and the service request. BP Energy contends that any lumpy capacity needs to be resolved on a bilateral contractual basis. Powerex suggests using an ``open season'' process to finance expensive and lumpy upgrades. California Commission supports prorating large lumpy

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upgrades over a large base of new customers, to the extent that it is non-discriminatory and fiscally sound.

\613\ In the November 15 Notice, the Commission described an example of lumpy capacity as upgrades to provide a requested 100 MW of point-to-point service that results in 1,000 MW of additional transmission capacity.

\614\ E.g., EEI Supplemental, Xcel Supplemental, APPA Supplemental, Bonneville Supplemental, LPPC Supplemental, NRECA Supplemental, Progress Energy Supplemental, Duke Supplemental, Ameren Supplemental, Entergy Supplemental, Community Power Alliance Supplemental, MISO Supplemental, Williams Supplemental, and PNM-TNMP Supplemental.

\615\ E.g., LPPC Supplemental, Bonneville Supplemental, and EEI Supplemental.

971. In supplemental comments, Nevada Companies urge that the time period of a conditional firm bridge product should be left up to the discretion of each transmission provider. They suggest that most, if not all, transmission providers should be able to offer a conditional firm service for a one-year period and most should be able to offer it for longer periods. Nevada Companies state that they should be able to provide conditional firm service in their control areas for longer periods, possibly for up to five years in some circumstances and in certain locations.

972. BP Energy and Williams disagree that conditional firm service should be a bridge product. They state that such a limitation would provide additional opportunities for undue discrimination and limit competitive alternatives used to serve customer load. According to California Commission, conditional firm service needs to be available for long-term requests unless there exists a valid, proven reason why conditions make it physically or economically impossible to guarantee such service. California Commission states that some limitations on modeling should be accepted as justification for not providing conditional firm or related services only if such provisions for load growth are nondiscriminatory, justified and contractually sound.

973. Commenters take both sides on whether planning redispatch should be evaluated before the customer is obligated to incur the costs and delays of a facilities study. EPSA argues that evaluation prior to a facility study meets nondiscrimination requirements given the methods used by transmission owners to evaluate planning redispatch for their own needs. In its reply comments, Exelon supports the minor changes to planning redispatch proposed by the Commission, including the earlier study of planning redispatch options in the system impact study, and states that these changes will expand choices for customers. EEI states that requiring an offer of planning redispatch prior to completion of a facilities study would be unduly preferential to point-to-point customers because transmission providers consider the costs of network upgrades and the impacts on system reliability before choosing planning redispatch for their native load. Southern points to the internal inconsistencies of the NOPR that on one hand seek to expedite the study process and on the other hand would require a planning redispatch study provision that would slow the study process.

974. EEI states that the vast majority of facilities studies show that the embedded cost of transmission service is higher than the incremental amortized cost of upgrades. Thus, EEI argues that the Commission's proposal to reform planning redispatch could lead to uneconomic decisions by the customer as well as provide disincentives to upgrade and expand transmission infrastructure.\616\ In their reply comments, Utah Municipals respond that most of the time the embedded cost of transmission is higher than the costs of upgrades, adding that customers find requests for a transmission upgrades to be a time consuming and costly impediment to transmission access. Further, Utah Municipals add that limited and occasional redispatch or curtailment, would be more economically efficient than the construction of transmission facilities most of the time.

\616\ E.g., Xcel, PPM, and BP Energy.

975. Several commenters state that it would be extremely burdensome to develop, at the system impact study stage, a reliable estimate of the number of hours of redispatch and the cost of the planning redispatch.\617\ These commenters state that this would require substantial investment in probabilistic studies of equipment availability and extensive training of personnel and expansion of data collection, yet still would not provide reliable estimates of the number of hours or costs of the service. MISO states that at a minimum, this would require two years to implement.

\617\ E.g., EEI, Southern, TVA, SPP, E.ON, and MISO.

976. EEI asserts that conditional firm service should be determined based on system impact studies and facilities studies so that the customer can evaluate the costs of upgrades versus the lack of reliability of the conditional firm service. EEI and others also propose that conditional firm service only be available when upgrades cannot be completed during the term of service or during the period prior to completion of transmission upgrades.\618\ In its reply comments, Bonneville disagrees that conditional firm service should be an interim service available only when the customer has agreed to pay for upgrades, stating that such a requirement would undercut the value of conditional firm service. Bonneville adds that, for example, the costs to build upgrades in order to resolve a constraint in a two-month period could raise the costs of the conditional firm service to a prohibitive level for little additional benefit to the customer.

\618\ E.g., APPA, PNM-TNMP, and Southern.

Commission Determination

977. As we explain above, the Commission finds that both planning redispatch and conditional firm point-to-point service must be offered under certain circumstances for the provision of reliable and non- discriminatory point-to-point transmission service. We set forth below the parameters of this service, keeping in mind the concerns expressed by commenters.

978. First, the planning redispatch and conditional firm options need only be made available to customers who request firm point-to- point service of more than a year in duration. When the requested firm point-to-point service is not available and the customer agrees to a system impact study, the transmission provider must evaluate the planning redispatch and conditional firm option at the customer's request. If the customer requests study of the planning redispatch or conditional firm options, the system impact study must identify the following: (1) The system constraints, identified by transmission facility or flowgate, causing the need for the system impact study; (2) additional direct assignment facilities or network upgrades required to provide the requested service; (3) redispatch options, including an estimate of the incremental costs of redispatch and the relevant congested transmission facilities for which redispatch will be provided; and (4) conditional firm options, including the number of conditional curtailment hours and the specific system conditions during which conditional curtailment may occur. Transmission providers may recover the costs of studying these options through the system impact study agreement.

979. Second, we adopt limitations on the nature of the planning redispatch and conditional firm options to reflect the two different types of customers that may request the service: customers who support the construction of upgrades and those who do not.

980. For customers supporting the construction of upgrades, the planning redispatch or conditional firm options will serve as a bridge until upgrades are constructed to remedy the congested transmission facilities. For these customers, the transmission provider must offer planning redispatch or conditional firm service until the time when the upgrades are constructed. The conditions or redispatch applicable to this period must be specified in the service agreement and are not subject to change. We impose this requirement

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because customers who commit to support transmission upgrades are typically those financing and constructing new resources. These customers require certainty both with regard to upgrade costs and, before upgrades can be constructed, the redispatch requirements or curtailment conditions that may apply to their service. We disagree with Williams and BP Energy that requiring transmission providers to offer this bridge product will present more opportunities for undue discrimination. As we note above, available information on transmission providers' current uses of redispatch and curtailment plans for their retail native load indicates that the mechanisms are used for relatively short periods of time until upgrades are completed to resolve the transmission insufficiencies. Comparable services for long- term point-to-point customers should therefore be similarly limited to shorter time periods or otherwise linked to transmission upgrades.

981. For customers choosing not to support the construction of new facilities, the planning redispatch or conditional firm options also must be made available as a reassessment product, i.e., subject to certain limitations. Although many transmission providers argue that planning redispatch and conditional firm service should be offered only to customers who seek to upgrade the grid, we disagree. We find that there are legitimate circumstances under which customers may not choose to support system upgrades--either because the costs of construction are too high or because the term of service (e.g., less than five years) does not merit the construction of additional facilities. We will therefore make planning redispatch and conditional firm service available to such customers, but subject to certain limitations to reflect the nature of the services. Specifically, we must select a limitation on the term for the conditions that permit interruption or redispatch, given that, for these customers, the term is not circumscribed by the period during which upgrades are constructed. We adopt two years as the appropriate time period to allow the transmission provider to reassess the conditions under which planning redispatch or conditional firm service is provided. The transmission provider will retain the right to reassess the planning redispatch and conditional firm option after the first two years of service, and every two years thereafter. The transmission provider shall reassess (1) the redispatch required to keep the service firm or (2) the conditions or hours under which the transmission provider may conditionally curtail the service. The customer will receive service for the requested term unless the transmission provider determines through its biennial reassessment that the firm point-to-point service can no longer be reliably provided. The customer may also choose to terminate the service at the time of reassessment if the service no longer meets it needs.

982. We select two years as providing a reasonable balance between the concerns of potential customers and transmission providers. We recognize that a shorter period would increase the reliability of predictions, as sought by certain transmission providers, but find that a two-year period is consistent with the bridge concept, given that two years is often less than the typical time to construct new facilities. While this is a shorter period than some transmission customers would desire, customers who require greater certainty over the long-term can obtain that certainty by agreeing to support the construction of new facilities. In the long run, all firm transmission customers, including conditional firm customers, should support the expansion of the grid to reliably serve load.

983. We decline to adopt any of the suggestions to address unique circumstances that may arise in which upgrades are prohibitively expensive. Specifically, we will not adopt Constellation's suggestion that customers be able to rebut the presumption that required upgrades are just and reasonable. In this Final Rule, we provide customers with the option of obtaining planning redispatch or conditional firm service for a long term, with the ability to roll over a five-year or longer reservation, subject to a limitation that the underlying restrictions on the service, i.e., the conditions for redispatch or curtailment, may be reassessed by the transmission provider every two years. We believe that this option is superior to that proposed by Constellation because it will provide the customer with rollover rights while ensuring that transmission providers can reliably operate their transmission systems. Additionally, since issues of lumpy capacity are present in the provision of transmission services generally, we will not address such issues in this Final Rule as they do not present issues unique to planning redispatch or conditional firm options.

984. Contrary to the assertion of several commenters, we believe that transmission providers would take greater risk in committing to conditions for the entire term of a 10-year conditional option than they take today in committing to provide unconditioned firm point-to- point transmission service for a similar period. Planning for reliable service for existing transmission customers is a difficult process, but it is much more difficult to plan over an extended long-term period for reliable service when the service is firm for most of the hours of the year and less firm for other hours. This is because many transmission providers use annual hourly peak load for two to 10-year planning purposes. They would need to substantially change their planning methods to ensure no change in service for a conditional firm customer that is not expected to be served during the peak hour. We therefore adopt a two year assessment window to provide an appropriate degree of flexibility for transmission providers' planning needs.

985. We acknowledge, however, that some commenters, such as Bonneville and Nevada Power, state that they may be able to provide conditional firm service over a period longer than two years, without the need for reassessment. The Commission encourages the provision of planning redispatch or conditional firm service for longer periods where it is practical. In the event a transmission provider is able to extend the assessment period, we will allow the transmission provider to waive or extend its right to reassess the availability of the option, provided that the waiver or extension is provided consistently for all similarly situated service.

986. With regard to timing of the study of planning redispatch and conditional firm options, the Commission finds that study of both options is appropriate in the system impact study. The obligation for the transmission provider to study planning redispatch options in the system impact phase is already present in the existing OATT.\619\ The Commission clarifies in this Final Rule the specific requirements necessary to meet this obligation. Transmission providers, when requested by potential customers, must provide non-binding estimates of the incremental costs of planning redispatch and identify the relevant congested transmission facilities for which redispatch will be provided. Transmission providers will not be required to estimate the number of hours of redispatch that may be required to accommodate the requested service as proposed in the NOPR. The Commission is persuaded by commenters that such an estimate is of limited use to potential customers and is difficult, expensive and time consuming for transmission

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providers to calculate with any accuracy.

\619\ See pro forma OATT section 19.3.

987. Finally, the Commission disagrees that the study of planning redispatch options must necessarily go hand in hand with the study of the costs and construction requirements of facility upgrades. Again, the obligation to study planning redispatch in the system impact study is not new. Our action in reinforcing this existing obligation cannot violate comparability or, in itself, cause the slowing of study processes. We have moved to a later study of conditional firm options so that both options can be studied in tandem. Furthermore, we note that the structure of the reassessment product requires the study of both options at the system impact study phase, since by definition customers opting for the reassessment product are not likely to enter into a facilities study agreement. We acknowledge that the few changes that we are making to the planning redispatch obligation may increase requests for study of the option and certainly the new conditional firm option will need more study than in the past. While we recognize the tension between the adoption of requirements to speed study completion and the increase in studies' complexity caused by the conditional firm option,\620\ we will not forego a beneficial new option for customers because of this tension. We expect that transmission providers will be diligent in completing the system impact studies and in bringing to our attention any difficulties in meeting deadlines caused by the study of the two options.

\620\ In section V.D.5.a, we adopt a requirement that transmission providers post metrics on their performance in processing system impact studies and facilities studies.

(B) Who Must Provide Planning Redispatch and Conditional Firm NOPR Proposal

988. In the NOPR, the Commission requested comment on the applicability of these two options to transmission providers who operate as RTOs and ISOs. The Commission also requested comment on which resources should be required in the provision of planning redispatch. First, the Commission proposed that the planning redispatch requirement apply to the redispatch of the transmission provider's own generation resources, but not to obligate transmission providers to purchase new resources to provide the service. If a transmission provider cannot accommodate a long-term firm point-to-point transmission request through planning redispatch, the Commission proposed requiring the transmission provider to identify additional generators in other control areas that could relieve the constraint. The Commission also requested comment on whether the planning redispatch obligation should be expanded to require the use of network customer resources in addition to transmission provider resources or expanded to require that transmission providers contract to purchase off-system resources to facilitate the planning redispatch. (i) Application to RTOs and ISOs Comments

989. RTOs state that reforms regarding planning redispatch and conditional firm services are unnecessary in RTO markets with financial congestion management because these markets already provide sufficient redispatch inside RTOs and sufficient interconnection service for generators located at RTO boundaries to address the Commission's point- to-point service concerns.\621\ Ameren and MISO add that the options could disrupt the distribution of financial transmission rights in RTO markets. Others disagree and argue that planning redispatch should be used by RTOs to define the current and future operational environment to ensure that systems are not overbuilt.\622\ AWEA contends that, since RTOs and ISOs vary considerably in the services they offer, RTOs and ISOs should be required to demonstrate that their services are consistent with or superior to planning redispatch and conditional firm services. In particular, AWEA argues that RTOs that do not provide financial rights should be required to provide both of these services. Exelon states on reply that the Commission has proposed minor changes to the existing planning redispatch requirement that should not be impractical or too burdensome for RTOs to administer.

\621\ E.g., MISO, PJM, California Commission, and ISO New England.

\622\ E.g., AWEA, Indianapolis Power Reply, and Exelon Reply.

990. In its reply comments, California Commission adds that capping the frequency or costs of redispatch in an RTO market would inappropriately shift the costs of congestion to others. Although SPP has successfully used planning redispatch to facilitate short-term firm transmission service and to address interim circumstances associated with long-term firm transmission service,\623\ it argues that the Commission's proposed expanded planning redispatch service would slow its batch processing of transmission service, require significant investment of time to evaluate the options given the scope of an RTO, and create speculative redispatch estimates at best. SPP adds that RTOs should simply assist the customer with identification of planning redispatch options so that the customer can bilaterally contract with the generation owners of its choice.

\623\ Citing Attachment AC of the SPP OATT (Optimal Reservation Processing Method for Short Term Firm Transmission Services).

991. MISO adds that conditional firm is inconsistent with RTO market mechanisms, requires burdensome changes to curtailment protocols and reliability coordinator's procedures, and would impact every tool used in real time for congestion management in RTOs. In its reply comments, MISO adds that adoption of conditional firm service would require revisions to seams agreement protocols. California Commission states on reply that the added administrative complexity of conditional firm service is unnecessary in the CAISO because the ISO's transmission service model makes no distinction between firm and non-firm service and provides prospective new customers with information to objectively estimate curtailments. FirstEnergy and MISO express concern regarding disruption of existing RTO communication protocols if these services are required in RTOs. Commission Determination

992. Notwithstanding the requirements of section IV.C of this Final Rule, the Commission finds that it would be inappropriate to require RTOs and ISOs with real-time energy markets to adopt the provisions for conditional firm point-to-point service. Customers transacting in RTOs and ISOs are able to buy through transmission congestion in the RTOs' real-time energy markets and need no prior reservation in order to access transmission. Voluntary curtailment in order to access transmission is thus not an attractive option given the range of options available for customers transacting in RTOs and ISOs. Further, in RTOs and ISOs with financial transmission rights, conditional firm service may disrupt the distribution of these rights. We therefore believe that there is no need to reform existing RTO and ISO procedures to satisfy concerns underlying the adoption of the conditional firm option.

993. The Commission directs, however, RTOs and ISOs that already

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provide planning redispatch pursuant to section 13.5 of the pro forma OATT to modify the relevant provisions of their tariffs consistent with our directives in this Final Rule.\624\ RTOs and ISOs need not amend their tariffs if the Commission has previously found that these tariffs were just and reasonable without the inclusion of pro forma section 13.5 planning redispatch provisions. We will not require incorporation of the more limited planning redispatch obligations adopted in this Final Rule if RTOs and ISOs have already been excused from the planning redispatch obligations of the existing pro forma OATT.

\624\ This includes the transmission provider's obligation to post monthly redispatch costs for each transmission facility over which planning and reliability redispatch are provided.

(ii) Generation Resources Required for Planning Redispatch Comments

994. Most commenters agree that resources in addition to the transmission provider's resources can and should participate in the provision of planning redispatch. Commenters differ as to whether this participation should be mandatory or voluntary. A few commenters maintain that participation by resources outside the transmission provider's control area could have adverse impacts on reliability in the control area.\625\

\625\ E.g., Ameren, PNM-TNMP, Xcel, and WAPA.

995. In arguing for mandatory participation, EEI and others contend that all generation resources owned or operated by all jurisdictional transmission customers in the control area or balancing authority area should be obligated to redispatch to accommodate new requests for service in order to avoid undue discrimination.\626\ Exelon argues that transmission providers should redispatch resources of its network customers, subject to appropriate compensation. SPP contends that generation affiliated with transmission owners that have transferred functional control of their transmission assets to an RTO should not have any greater planning redispatch obligation than unaffiliated generation. In its reply comments, Entergy states that the Commission at a minimum should continue to allow network customers to request that transmission providers redispatch network customer resources in order for the customer to designate a new network resource.

\626\ E.g., Southern, FirstEnergy, MidAmerican, and Community Power Alliance.

996. Others argue for a least-cost economic dispatch to relieve real-time system constraints, including not only the transmission provider's own resources and those of its network customers, but also all non-affiliated resources both within and outside its footprint that choose to be included.\627\ EPSA explains that this redispatch would: Require transmission providers to solicit offers from resources to provide energy and perhaps ancillary services; be based on a resource's offer of service and take into account generating resource and transmission operating limits; include performance assurance terms, unit commitment procedures, billing, compensation and bidding protocols, confidentiality protections, and information-sharing protocols; and dispute resolution procedures to avoid disputes rising to the level that would require judicial or regulatory intervention. AWEA supports Deseret's OATT provisions that require the transmission provider to relieve constraints by the least cost means, whether by seeking a change in generation output from the transmission provider's merchant function or from any other feasible generator. Williams suggests that independent generators must be allowed to participate in the provision of planning redispatch service through submission of a formulary rate to the transmission provider. If the Commission intends to have non-affiliated generators participate in planning redispatch, PPL states that the Commission should require transmission providers to negotiate agreements with generators on their systems.

\627\ E.g., AWEA, Project for Sustainable FERC Energy Policy, Exelon, Powerex, Constellation, Williams, Sempra Global, PJM, EPSA, and Entegra Reply. Sempra Global contends that the Commission should require transmission providers to offer redispatch of non-affiliated resources both within and outside its footprint, subject to pre- existing contractual commitments.

997. TranServ, MidAmerican, and Nevada Companies support a planning redispatch service similar to that employed by the Mid-Continent Area Power Pool, whereby customers arrange for their own redispatch through bilateral or centralized energy markets and submit plans for approval to their transmission provider and reliability coordinator.

998. Several commenters discuss the need for market development in conjunction with the planning redispatch obligation. TranServ and Xcel state that the planning redispatch option may force transmission providers without generation assets to develop some form of energy market to arrive at the costs of redispatch. Southern and Progress Energy add that forced adoption of such a market would raise significant political opposition and be contrary to the Commission's commitment in the NOPR to avoid such restructuring.

999. EPSA, AWEA and PJM support such market development. When a generator in another control area is called upon to relieve a constraint in regions not administered by an RTO, PJM states that the Commission must direct the development of an alternate LMP pricing scheme to establish ``system marginal costs'' that are consistent with transparent generator pricing in RTO markets. EPSA and PJM argue that vertically integrated utilities in non-RTO areas should turn over functional control of their dispatch function to a disinterested entity or replicate the transparency by publishing generation dispatch. EPSA suggests that the Commission require this transparency to ensure nondiscriminatory redispatch.

1000. A few commenters state that any requirement for the transmission provider to purchase generation from outside the control area to facilitate planning redispatch is functionally unworkable and would adversely impact reliability.\628\ EEI supports the Commission's proposal to have transmission providers identify off-system resources that could provide planning redispatch but requests clarification that no additional investigations or studies are required to identify these additional options. MidAmerican adds that the coordinated, open and transparent planning provisions of the NOPR should provide customers with the ability to identify off-system resources. EEI and Southern state that any redispatch on adjacent systems should be arranged by transmission customers and the service should be curtailed prior to other firm uses of the system if the off-system generator fails to perform. WAPA and Bonneville argue against the use of off-system redispatch, stating that lack of control over these resources could cause reliability problems on the originating transmission system. WAPA also believes that off-system redispatch would not provide the price certainty needed by customers because the redispatched megawatts will differ based on the transmission system parameters, and customers would be required to pay for any loop flow resulting from the off-system redispatch.

\628\ E.g., Xcel, PNM-TNMP, and Public Power Council Reply.

1001. In its reply comments, EEI adds that a requirement for transmission providers to solicit planning redispatch

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proposals from generators inside and outside their control areas would require that transmission personnel become involved in generation and power sales matters in violation of the Commission's Standards of Conduct. Duke argues on reply that such an approach would require that third party generators reveal their costs to the transmission provider and that a means of estimating costs for all generators subject to planning redispatch would need to be set forth in the pro forma OATT.

1002. LPPC, APPA and TAPS oppose any requirement that transmission providers redispatch their network customer's resources as well as their own to provide planning redispatch, stating that this action would appropriate resources beyond the Commission's jurisdiction, result in endless conflict between transmission providers and resource owners, and interfere with network customer's use of their limited resources. Commission Determination

1003. Order No. 888 compelled transmission providers to provide planning redispatch from their own resources.\629\ The Commission declines to expand that obligation to require transmission providers to solicit third party resources in order to provide planning redispatch. We will, however, require transmission providers to identify in the system impact study (1) generation resources located within the transmission provider's control area, including its own resources, that can relieve the congested transmission facility at issue, and (2) the impact of each identified resource on the congested facilities, e.g., the generator shift factor. The resources identified in the system impact study need not be available to provide the redispatch. Customers must simply be provided with the set of generators that could, if available, make a significant contribution toward relieving the constrained facility at issue. This information, in addition to the information provided through congestion planning studies, will provide the necessary information to customers wishing to solicit third party resources to relieve congested facilities in order to accommodate long- term firm point-to-point service. We note that this information is readily accessible by the transmission provider, as it is the same information used to determine pro rata curtailments of firm resources in contingency situations.

\629\ See pro forma OATT section 13.5. With respect to SPP's assertion that transmission owners' affiliated generation should have no greater redispatch obligations than unaffiliated generation in RTOs, we find that relevant redispatch obligations in the RTO tariff and transmission owners' tariffs govern this issue. See Southwest Power Pool, Inc., 110 FERC ] 61,133 at P 17 (2005) (rejecting proposed provisions that would have removed the obligation for transmission owners to provide planning redispatch).

1004. In addition to identifying generation resources within the control area, the Commission also requires identification of resources outside the control area that may be able to relieve congested transmission facilities. To the extent the transmission provider is aware of generation resources outside of its control area that can relieve the constraint, the transmission provider must inform the customer of these resources. To be clear, this does not require the transmission provider to undertake any additional investigation or study to identify generation options located outside of the control area. To the extent the transmission provider has such information, however, it must provide it to the customer.

1005. The Commission will not mandate the use of network customer resources or other third party resources in the provision of planning redispatch.\630\ If they choose, network customers and third parties may voluntarily provide planning redispatch services. A seller is free to post its price to relieve a specific congested transmission facility and its ability to relieve the congestion. To facilitate provision of such service by third parties, we direct transmission providers to modify their OASIS sites to allow for posting of these third party offers. Accordingly, we direct transmission providers to work in conjunction with NAESB to develop this new OASIS functionality and any necessary business practice standards. Transmission providers need not implement this new OASIS functionality and any related business practices until NAESB develops appropriate standards.

\630\ Network customers will continue, however, to be obligated to make their network resources available to the transmission provider for reliability redispatch in real time.

1006. Customers may then contract in advance with these third parties or use their own resources to secure planning redispatch services in lieu of or in addition to service from the transmission provider. In this way, customers can arrange for their own planning redispatch through bilateral markets and submit plans for approval to their transmission provider and reliability coordinator. The arrangements must, however, be sufficiently detailed and coordinated with the transmission provider to ensure that reliability is maintained.

1007. We therefore direct in this Final Rule that transmission providers work with customers to facilitate the use of third party generation, where available, in provision of planning redispatch. This entails review of redispatch plans submitted by customers, coordination between the transmission provider and reliability coordinator, and signaling third party generators when the redispatch is needed. These arrangements will require close coordination between the transmission provider, third party generators and transmission customers. The arrangements must be sufficiently detailed to allow the transmission provider to maintain reliability. Although we will not allow transmission providers to unreasonably deny customers the use of third- party resources to provide planning redispatch, it is the customers' ultimate responsibility to ensure that all the necessary contractual and technical arrangements are in place to maintain reliability. We clarify for Entergy that this would allow transmission providers to continue to provide planning redispatch for network customers from the network customers' resources. We also clarify that transmission providers may curtail transmission customers if a third-party resource fails to perform its contractual redispatch obligation. This or any other remedy for non-performance must be specified in writing between the parties prior to commencement of the service.

1008. For the reasons discussed below regarding the TDA proposal, we decline to adopt the bid-based redispatch model suggested by EPSA. In section V.C.1 of this Final Rule, we similarly reject proposals to impose LMP and independent control of the dispatch function. We believe that a bid-based generation market design is not necessary to remedy undue discrimination in the provision of transmission service. We also believe that our modifications to the planning redispatch requirement, including the OASIS changes directed herein and the requirement that transmission providers make available information on generators capable of providing planning redispatch, will provide potential customers with greater information about redispatch choices and enable greater opportunities for planning redispatch and comparable service.

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(C) Pricing of Planning Redispatch NOPR Proposal

1009. In the NOPR, the Commission sought comment on which type of redispatch pricing would ensure effective use of the planning redispatch option. The Commission described one type of pricing, a formula rate, to include a MW quantity, the incremental cost of fuel at the point of delivery, and the decremental cost of fuel at the point of receipt capped at the price of fuel. The Commission sought further comment on whether it would facilitate planning redispatch to base calculations of the various costs for input into the formula on the difference between the cost of ramping up a generator at the point of delivery and ramping down a generator at the point of receipt. The Commission also described a redispatch pricing proposal to calculate redispatch charges monthly and charge the higher of actual redispatch costs or the OATT rate each month made by PacifiCorp in response to the NOI. Comments

1010. While many specific comments were received on the pricing of planning redispatch service, there is little consensus on this subject. Several commenters state that pricing challenges associated with planning redispatch are difficult if not insurmountable.\631\

\631\ E.g., Powerex, Manitoba Hydro, Seattle, NRECA, Ameren, and E.ON.

1011. MidAmerican and EEI argue that the current cap on planning redispatch at the costs of upgrades should be removed because a customer will always choose planning redispatch and the risks that redispatch costs exceed construction costs falls to the transmission provider and is either unrecoverable or passed on to other customers.

1012. According to several commenters, requiring the transmission provider to establish a standard fee for planning redispatch, either on the overall system or on a path-by-path basis, would accomplish cost certainty for the customer and hold the transmission provider accountable for the accuracy of the studies used to assess redispatch requirements.\632\ These commenters support a standardized formula-rate for planning redispatch or a capped amount at, or close to, the embedded cost rate. Entegra and TransAlta state that the redispatch pricing proposal may allow transmission providers discretion to charge redispatch costs without providing customers a practical way to verify that claimed redispatch costs have actually been incurred. PGP states that the Commission should allow for regional differences in planning redispatch pricing. APPA does not support a departure from the current redispatch pricing approach, while Seattle states that the existing section 13.5 is unworkable because the cost of planning redispatch is difficult to calculate for both historical and near-term operating horizons, much less over a multi-year planning horizon.

\632\ E.g., Utah Municipals, Public Power Council, PPM, Entegra, Constellation, TransAlta and TAPS.

1013. EPSA and AWEA believe that the pricing mechanisms suggested in the NOPR would be open-ended and highly variable over the duration of the reservation and, thus, not meet the needs of customers. EPSA and AWEA assert that, consistent with Commission precedent,\633\ a utility must identify and justify its costs in excess of average system costs before service commences in a manner that meets the customer's needs to charge a rate in excess of average system costs, i.e., some customers may require a firm estimate upfront to obtain financing while others may be willing to negotiate a rate based on estimates.\634\ EEI states on reply that the policy in American Electric Power related to an expansion cost rate, which is inapposite to redispatch costs because the costs of new construction are easier to estimate in advance than are the costs of planning redispatch. EEI contends that the planning redispatch customer's interest in price certainty is not a sufficient basis for shifting costs to other customers or to the transmission provider.

\633\ American Electric Power Service Corp, 64 FERC ] 61,279 (1993) (American Electric Power).

\634\ Id. at 62,976.

1014. EPSA and AWEA suggest that, when the cost of planning redispatch is estimated to exceed the transmission rate, the transmission provider should offer either: a formula rate for incremental redispatch costs with the number of hours of redispatch, the resources to be redispatched and the conditions under which redispatch would occur defined in advance or, an incremental cost rate determined at the time of the reservation to cover the reservation period that may include a risk adder for the transmission provider. Morgan Stanley argues that planning redispatch options should include the following: Redispatch priced at a market index; where market prices are not available, the price should be the incremental costs; full cost pricing should be allowed for ``life of service'' (total dollar cost for unlimited redispatch over the term of a contract) or fixed rate contracts for actual redispatch agreed to at the time of contracting; and redispatch costs provided from a third-party provider. Morgan Stanley opposes ``higher of'' pricing that would allow for monthly charges for redispatch costs or long-term firm transmission service rate.

1015. In contrast, many transmission providers and EEI ask the Commission to allow for recovery of actual costs of redispatch, rather than the estimated costs, with the customer obligated to pay all costs.\635\ Since providing accurate estimates of redispatch costs and hours are difficult, especially with respect to longer-term service requests given the variability of fuel costs, transmission providers contend that they should not bear the risks of inaccurate cost estimates for a service that benefits only the point-to-point customer.\636\ Indianapolis Power adds that planning redispatch should be priced to discourage inefficient dispatch of generation. In its reply comments, PPM agrees that planning redispatch is unworkable without certainty of cost recovery for the transmission provider, but believes that with enough information customers can evaluate the risks and gain certainty required for a workable product.

\635\ E.g., Southern, MidAmerican, Entergy, FirstEnergy, Ameren, Nevada Companies, E.ON, and South Carolina E&G.

\636\ E.g., EEI, Entergy, LPPC, NRECA, MidAmerican, Ameren, and FirstEnergy.

1016. Southern argues that the current pro forma OATT language unreasonably places the risk of uncertainty in estimating redispatch costs on the transmission provider and its native load customers, contrary to basic cost causation principles and native load protections in Order No. 888. Southern suggests that the Commission follow the approach in the Deseret and SPP tariffs, which allow for the transmission provider to recover its actual costs of redispatch. Ameren states that a standard per kWh fee is simpler to administer, but should be structured to recover all of the costs of planning redispatch, including opportunity costs.

1017. Various commenters argue that the Commission should allow the following redispatch costs to be recovered: Fuel; variable operations and maintenance; increased maintenance costs due to cycling; start-up and ramp-down costs; emergency purchases; costs of additional operating reserves; environmental costs; and lost opportunity costs.\637\ MidAmerican also argues that a transmission provider should be able to recover the costs of

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redispatch energy purchased in response to a pre-schedule by a planning redispatch customer regardless of schedule changes by the customer and regardless of any pro rata curtailments affecting such customers due to system reliability.

\637\ E.g., LDWP, EEI, Ameren, MidAmerican, and Southern.

1018. EEI and Southern argue that customers that choose planning redispatch should pay the cost of transmission service and the cost of redispatch. EEI asserts that allowing recovery of both costs is not prohibited ``and'' pricing because the services differ, as one is provided by the transmission system and one is provided by generators, and native load and network customers pay pro rata shares of reliability redispatch costs to relieve constraints on the system as well as the basic costs of transmission service. TAPS and TDU Systems take the opposite view and state that the Commission should require planning redispatch pricing consistent with the Commission's ``higher of'' or ``or pricing'' policy. In addition, they state that the redispatch charges must be capped up front at fixed dollars and hours at or close to the embedded cost rate.

1019. Arkansas Commission agrees with the PacifiCorp pricing method in which redispatch costs are recalculated monthly and customers are charged the higher of the redispatch cost rate or the monthly OATT transmission rate. TAPS states that this method avoids ``and'' pricing, but does not address the complexity or risks associated with determining redispatch costs over a long period. APPA argues that the PacifiCorp proposal, if applied after the fact, could lead to uncertainty and disruption of market transactions. Southern opposes any pricing method that caps the total costs that a planning redispatch customer would bear, including the PacifiCorp proposal, stating that caps allow the planning redispatch customer to shift costs to the transmission provider and its native load customers.

1020. E.ON points to an inherent problem in planning redispatch pricing: Transmission providers should be kept whole with regard to actual real-time redispatch costs but customers may not know until after the fact that the planning redispatch was not economic for their purposes. E.ON foresees difficulty in allocating redispatch costs among multiple planning redispatch service customers and requests that the Commission adopt a specific methodology for calculating each request's impact on the system. Commission Determination

1021. Although there is no consensus regarding which form of pricing methodology is most appropriate for planning redispatch service, there is general agreement among the commenters that the current pricing rules fail to meet the needs of either customers or transmission providers and consequently fail to make planning redispatch an attractive means for customers to obtain access to the grid. Transmission providers and customers both express concern regarding the variability of redispatch costs. Customers worry that actual redispatch costs may greatly exceed estimates and thus seek cost certainty over the term of the service. Conversely, transmission providers claim that accurately estimating future redispatch costs for long duration service is extremely difficult. In fact, transmission providers state that the uncertainty in forecasting long-term redispatch costs is much greater than any uncertainty inherent in determining the costs of transmission upgrades.

1022. The Commission has carefully considered these comments and agrees that the current method for pricing planning redispatch service is no longer just, reasonable or not unduly discriminatory. The Commission takes three principal actions to address the concerns of customers and transmission providers.

1023. The Commission therefore adopts a new pricing method for planning redispatch service. We will no longer require the capping of redispatch costs over the term of the service at the costs of expansion. This change is inextricably linked with the change in the obligation to provide planning redispatch, i.e., the removal of the open-ended requirement to provide planning redispatch as long as it is more economical than transmission upgrades. We have shortened the planning redispatch obligation to apply before upgrades are built as a bridge product or to apply as part of a reassessment product. In prior cases, the Commission expressed the view that capping cost recovery for long-term transmission service at the costs of expanding the transmission system provides an incentive for transmission providers to undertake expansion when it is warranted.\638\ The expansion cost cap should not be applied to the bridge product because (1) upgrades will in fact be constructed and should be paid for by the customer under the ``higher of'' policy, and (2) an expansion cost cap does not serve as an incentive for expansion because the transmission provider already will have started the process of building transmission facilities for the customer who opts for the bridge product. If planning redispatch is provided as part of a reassessment product, the customer has chosen not to pay for upgrades and thus, the expansion cost cap cannot provide an incentive for transmission expansion.

\638\ See, e.g., Florida Power & Light Co., 70 FERC ] 61,158 at 61,484 (1995).

1024. We will therefore adopt a new pricing methodology. We believe that the PacifiCorp proposal described in the NOPR is the one that balances the competing concerns of transmission customers and transmission providers. Under this pricing methodology, customers will have the option of paying (1) the higher of (a) actual incremental costs of redispatch or (b) the applicable embedded cost transmission rate on file with the Commission or (2) a fixed rate for redispatch to be negotiated by the transmission provider and customer and subject to a cap representing the total fixed and variable costs of the resources expected to provide the service. If the customer selects the higher of incremental cost or the embedded-cost rate, the transmission provider shall calculate the costs of redispatch monthly and charge the higher of redispatch or the embedded cost rate each month.

1025. We have selected a monthly comparison of embedded costs and redispatch costs on the basis of a number of factors. The Commission has rejected basing the comparison on the life of a long-term firm transmission contract.\639\ For administrative efficiency, a transmission provider should be allowed to close its books and not be subject to possible refunds or surcharges at the end of its billing cycle. The standard billing cycle in the industry is one month. Allowing transmission providers to finalize accounting entries will provide certainty to both the transmission provider with regard to revenue recovery and to the transmission customer with regard to cost exposure. We therefore find that a monthly comparison of embedded and incremental cost is appropriate. This method retains ``higher of'' pricing for customers, but does not subject transmission providers to open-ended liability for refunds and otherwise should make planning redispatch service more attractive for transmission providers to provide. Further, given that redispatch often occurs only in selected time periods within a year (e.g., during

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the peak season, shoulder months, etc.), it is just and reasonable to allow the transmission provider to perform the higher of calculation in each month when the service is provided, not spread those costs over the entire year.

\639\ Id. at 61,483.

1026. For purposes of calculating planning redispatch charges, incremental costs shall include fuel or purchase power costs caused by ramping up generator(s) at the point of delivery and ramping down generator(s) at the point of receipt. Additionally, where applicable, transmission providers may specify in customer service agreements other incremental costs for inclusion in the monthly actual incremental costs, including opportunity costs. Identification and derivation of these costs must be included in the service agreement. We reiterate our existing requirement that all information necessary to calculate and verify opportunity costs must be made available to the transmission customer.\640\ We clarify that the actual costs of redispatch need not be determined annually or at the time that the service agreement is executed; rather, actual redispatch cost should be determined on a monthly basis.

\640\ See Order No. 888 at 31,740.

1027. With respect to MidAmerican's request to be able to recover the purchase power costs for a customer requiring planning redispatch, we reiterate that transmission providers are under no obligation to purchase power to provide planning redispatch services. Should the transmission provider take on the obligation to contract with a third party to provide planning redispatch at the customer's request, however, the customer should be obligated to pay the purchase power costs, including any reservation charge for the power. The flow-through of purchase power costs must be negotiated between customers and transmission providers in a stand-alone agreement if the transmission provider agrees to make purchases on the customer's behalf.

1028. The Commission will not adopt proposals suggested by several transmission providers to allow for recovery of the embedded cost transmission rate and the full costs of redispatch. The Commission's ``higher of'' pricing policy prohibits the transmission provider from charging both embedded costs and incremental costs such as redispatch costs.\641\ We reject EEI's assertion that we should adopt such pricing because native load and network customers pay a load ratio share of redispatch costs and the embedded cost transmission rate. Planning redispatch differs from the reliability redispatch for which transmission providers are only obligated to provide network customers with ability to avoid real-time curtailments. Rather, planning redispatch is a means of creating additional transmission capacity,\642\ not a generation service, and thus planning redispatch is appropriately priced by applying the Commission's ``or'' pricing policy. We decline to revisit that longstanding policy in this rulemaking.

\641\ See Pennsylvania Electric Company, 58 FERC ] 61,278, 62,871-75, reh'g denied, 60 FERC ] 61,034 (1992), aff'd sub nom. Pennsylvania Electric Co. v. FERC, 11 F.3d 207 (D.C. Cir. 1993); see also Entergy Services, Inc., 71 FERC ] 61,139, 61,452 (1995) (regarding the pricing of redispatch service, the Commission stated ``[i]t is a well-settled matter that the Commission will not authorize ``and'' pricing, i.e., embedded cost pricing plus opportunity (incremental) cost pricing.'').

\642\ Order No. 888A at 30,267.

1029. With respect to concerns that the expansion cost cap was adopted to provide rate certainty to customers over the term of the service,\643\ we believe that the modified pricing policy adopted here will continue to provide appropriate certainty to customers, while also allowing transmission providers to recover just and reasonable costs. For customers purchasing the bridge product, the cost of redispatch will be incurred only during the initial term of the service agreement while new facilities are being constructed. During this term, the cost of redispatch service represents a legitimate cost of providing the service and therefore should be fully recoverable under the higher of policy. Although it is true that redispatch costs are difficult to project, and hence create uncertainty for customers, this does not mean that the transmission provider should not be allowed to recover the legitimate and verifiable costs of providing the service. Moreover, if the customer desires greater certainty regarding redispatch costs during this period, it can elect the fixed rate option discussed above and negotiate a fixed redispatch charge with the transmission provider. Once upgrades are constructed, however, the customer will receive the certainty of paying a fixed rate for transmission costs and, importantly, any expansion cost will be fixed at the time the initial service agreement is signed. Finally, for customers who do not select the bridge product because they do not want to fund upgrades, it would be unreasonable to cap the cost of redispatch at the cost of upgrades. In such an instance, the customer has elected to forego the price certainty that can be gained by funding the upgrades to remove the constraint that is causing the transmission provider to incur redispatch costs.

\643\ Florida Power & Light Co., 70 FERC ] 61,158 at 61,483 (1995).

(D) Standards of Conduct and Planning Redispatch NOPR Proposal

1030. In the NOPR, the Commission requested comment on the interaction of planning redispatch requirements with the Commission's Standards of Conduct. Comments

1031. Commenters generally argue that the independent functioning requirement and the information sharing prohibitions under the Standards of Conduct are irreconcilable with the expanded planning redispatch proposal in the NOPR.\644\ Southern, TranServ and Progress Energy contend that the planning redispatch option would require close coordination and communication with market participants including the marketing or energy affiliate, which may create confidentiality and Standards of Conduct problems. For instance, they state that close coordination and sharing of non-public transmission and customer information would be required to determine the generating units that can be redispatched, the impact that planned and forced outages of redispatched generators will have on the availability of transmission service and the transmission line loadings, and the costs of redispatch. Some commenters request that the Commission adopt an exception to the Standards of Conduct to permit communication between transmission providers and marketing and energy affiliates, acting as generation operators, for the transmission provider to instruct the generation operator to vary its generator's output.\645\

\644\ E.g., Nevada Companies, Community Power Alliance, Progress Energy, LPPC, Southern, WAPA, and APPA.

\645\ E.g., E.ON, Ameren, and APPA.

1032. MidAmerican suggests that it is unlikely that any communication protocols could be established that would both comply with the Commission's current Standards of Conduct and permit a transmission provider to coordinate with its marketing affiliate employees to arrange planning redispatch. Rather, MidAmerican argues that the transmission customer would have to waive the Standards of Conduct to enable the transmission function employees to share the necessary information with their marketing affiliate counterparts.

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1033. Other commenters argue that violations of the Standards of Conduct can be avoided by various means. PPM suggests that publication of redispatch costs similar to ancillary service costs and elimination of case-by-case sharing of information between the transmission provider and the generation operators would avoid Standards of Conduct issues. MidAmerican states that sole reliance upon bilateral agreements with third parties to provide planning redispatch would resolve the need to modify the Standards of Conduct. In their reply comments, Utah Municipals state that they do not believe the Standards of Conduct pose a barrier to provision of planning redispatch since transmission providers redispatch to serve their own loads currently, but that if so the Commission should make small modifications to the standards. Commission Determination

1034. The Commission does not believe that any changes to its Standards of Conduct are required for transmission providers to implement the planning redispatch provisions adopted in this Final Rule. The information at issue, e.g., generation redispatch cost, is held by the marketing affiliate and there is no prohibition under our Standards of Conduct on the marketing affiliate transferring such information to the transmission provider. The information sharing prohibitions under the Standards of Conduct are ``one way,'' i.e., they restrict only communications of non-public transmission information from the transmission provider to the marketing affiliate, not vice versa. Therefore, the flow of information from marketing affiliates to transmission providers relating to the costs and availability of generation resources for planning redispatch is not prohibited under the Commission's Standards of Conduct.\646\

\646\ 18 CFR 358.5.

1035. We next turn to the flow of information from the transmission provider to the marketing affiliate. Initially, in order for transmission providers to evaluate planning redispatch options, they must identify the impacted transmission facilities, e.g., flowgates, and determine the marketing affiliate's generators that could provide redispatch over those facilities. Transmission providers already have this information to enable them to provide least cost reliability redispatch. However, transmission providers need not provide information regarding the impacted transmission facilities to its marketing affiliates. Rather, in order for transmission providers to evaluate the future availability of redispatch and estimate the costs of redispatch, they need only tell the marketing affiliate which of its generators would be suitable for redispatch, thus identifying those that require study. This sharing of information relating to the marketing affiliate's generation is not prohibited by the Commission's Standards of Conduct.

1036. In addition, the transmission provider may also need to provide its marketing affiliate with transmission-related information from the transmission customer's service request, such as service quantity and term, to determine the required duration and amount of the redispatch required. We find that such information provided from the transmission provider to the marketing affiliate is not a prohibited transfer of non-public information because such details of the transmission customer's service request are available via OASIS. The only customer transmission request information not readily available via OASIS is the source and sink information.\647\ We see no need for the transmission provider to provide such masked source and sink transmission information to its marketing affiliate as part of this redispatch evaluation process. We do not believe that any further information need be provided by the transmission provider to their marketing affiliates to evaluate the generators available for planning redispatch and their costs. Accordingly, we find there is no need to create an exception to the Standards of Conduct for the sharing of this generation-related information and publicly available transmission customer request information.

\647\ See Open-Access Same-Time Information System and Standards of Conduct, 83 FERC ] 61,360 at 62,456 (1998), reh'g denied, 86 FERC ] 61,139, reh'g denied, 87 FERC ] 61,382 (1999).

(E) Attributes of Conditional Firm NOPR Proposal

1037. In the NOPR, the Commission described conditional firm service as a modified form of point-to-point service that includes non- firm service in a defined number of hours of the year when firm point- to-point service is not available. The Commission proposed that the conditional firm service agreement would identify the conditional curtailment hours and include an annual or monthly cap on those hours. The Commission further proposed that conditional firm service would be curtailed before firm uses until such times as the conditional curtailment hours were exceeded, after which time the service would be treated as firm. The curtailment priority during the conditional period was proposed as the same as secondary network service. The Commission proposed that customers using the conditional firm option would pay the long-term firm point-to-point rate. The Commission also proposed that conditional firm service qualify for rollover rights, provided that it meets the other rollover right conditions proposed in the Final Rule. (i) General Terms and Conditions Comments

1038. Most commenters support pricing conditional firm service at the long-term firm OATT rate and no commenter suggested a different pricing method. Nevada Companies and Bonneville state that the customer seeking conditional firm service should pay the actual costs of the study required to provide the number of conditional curtailment hours.

1039. EPSA and AWEA support the following components of the Commission's conditional firm proposal: Conditional firm is available only to customers that first request long-term service; it would provide a year round, long-term product that is firm during all hours of the year except at well-defined periods when the transmission provider is unable to provide the service; and, in all hours that are not conditional, conditional firm service would be treated as any other firm service with the same curtailment priority as long-term firm network and point-to-point rights.

1040. EEI proposes that conditional firm service be firm in periods when firm service is available according to ATC calculations and non- firm, with a monthly non-firm curtailment priority, for periods when firm ATC is not available. CREPC, Exelon and MidAmerican argue that the Commission should not require conditional firm service until all attributes of the service are clearly defined and key implementation issues are resolved, including modification of NAESB and NERC processes. NAESB states that the Commission can reduce the amount of time required to develop OASIS and transmission loading relief protocols by clearly defining the conditional firm service.

1041. In its supplemental comments, EEI states that the Commission should not require all transmission providers to adopt terms and conditions for conditional firm service that are only workable for some systems, e.g., transmission providers in the Western Interconnection using the rated path

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methodology compared to many in the Eastern Interconnection using a flow-based methodology; rather, the Commission should allow flexibility in the offer of conditional firm service so that transmission providers are not foreclosed from offering the service.

1042. Several commenters state that transmission providers and customers collectively should design the conditional firm service that best accommodates their respective needs.\648\ In supplemental comments, Bonneville states that the transmission provider, not the customer, must determine the conditions to offer in response to a given request. Bonneville also requests that the Commission clarify that there would be no separate queue for conditional firm service.

\648\ E.g., LPPC Supplemental, PPL Supplemental, Williams Supplemental, Community Power Alliance Supplemental, Entergy Supplemental, and Southern Supplemental.

Commission Determination

1043. The Commission adopts the conditional firm option as a modified form of long-term firm point-to-point service that includes less-than-firm service in a defined number of hours of the year or during defined system conditions when firm point-to-point service is not available. The service can be curtailed solely for reliability reasons during the defined system conditions or defined number of hours. We reject EEI's suggestion to use a monthly non-firm curtailment because it would allow for curtailment of the conditional service for economic reasons.

1044. In this Final Rule, we define the minimum attributes of the conditional firm option rather than allow individual transmission providers to develop any form of service that could conceivably be labeled conditional firm service. The Commission has been considering a conditional firm product and has been discussing it with the industry for some time. In early 2005, the Commission held a technical workshop to:

Work with market participants to develop clear definitions for additional wholesale electric transmission services, e.g., conditional firm transmission service, develop applicable pro forma tariff language that could be included in public utilities' open access transmission tariffs and address attendant is