Preventing Undue Discrimination and Preference in Transmission Service

Federal RegisterJun 6, 2006

Ask Donna

What actually matters in this document.

Text

DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Parts 35 and 37

[Docket Nos. RM05-25-000 and RM05-17-000]

Preventing Undue Discrimination and Preference in Transmission Service

May 19, 2006.

AGENCY:

Federal Energy Regulatory Commission, DOE.

ACTION:

Notice of proposed rulemaking.

SUMMARY:

The Federal Energy Regulatory Commission is proposing amendments to its regulations adopted in Order Nos. 888 and 889, and to the

pro forma

open access transmission tariff, to ensure that transmission services are provided on a basis that is just, reasonable and not unduly discriminatory or preferential.

DATES:

Comments are due August 7, 2006. Reply comments are due September 5, 2006.

ADDRESSES:

You may submit comments, identified by Docket Nos. RM05-25-000 and RM05-17-000, by one of the following methods:

• Agency Web site:

http://www.ferc.gov.

Follow the instructions for submitting comments via the eFiling link found in the Comment Procedures section of the preamble.

• Mail: Commenters unable to file comments electronically must mail or hand deliver an original and 14 copies of their comments to: Federal Energy Regulatory Commission, Office of the Secretary, 888 First Street, NE., Washington, DC 20426. Please refer to the Comment Procedures section of the preamble for additional information on how to file paper comments.

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.

Kathleen Barro

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

David Withnell (Legal Information), Office of the General Counsel—Energy Markets, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426. (202) 502-8421.

SUPPLEMENTARY INFORMATION:

Table of Contents

I. Introduction

II. Background

A. Historical Antecedent

B. Order No. 888 and Subsequent Reforms

C. EPAct 2005 and Recent Developments

III. The Need for Reform of Order No. 888

A. Opportunities for Undue Discrimination Continue To Exist

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

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

D. A Consistent Method of Measuring ATC Has Not Been Established

E. A Number of Transmission Pricing Policies May Impede the Use of the Grid

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

IV. Summary, Scope and Applicability of the Proposed Rule

A. Summary of Proposed Reforms .

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

1. Federal/State Jurisdiction

2. Native Load Protection

3. The Types of Transmission Services Offered

4. Functional Unbundling

C. Applicability of the Proposed Rule

1. Public Utility Transmission Providers

2. Non-Public Utility Transmission Providers/Reciprocity

V. Proposed Modifications of the OATT

A. Consistency and Transparency of ATC Calculations

B. Transmission Planning—Coordinated, Open and Transparent Planning

C. Transmission Pricing

1. Imbalances

2. Credits for Network Customers

3. Capacity Reassignment

4. “Operational” Penalties

a. Unauthorized Use Penalties

b. How Transmission Providers Should Pay Operational Penalties

5. “Higher of” Pricing Policy

D. Non-Rate Terms and Conditions

1. Potential Modifications to Long-Term Firm Point-to-Point Service

2. Hourly Firm Service

3. Rollover Rights

4. Modification of Receipt or Delivery Points

5. Acquisition of Transmission Service

a. Processing of Service Requests

b. Queue Processing Business Practices

c. Reservation Priority

6. Designation of Network Resources

a. Qualification as a Network Resource

b. Documentation for Network Resources

c. Undesignation of Network Resources

7. Clarifications Related to Network Service

8. Transmission Curtailments

9. Standardization of Rules and Practices

10. OATT Definitions

E. Enforcement

1. General Policy

a. Compliance Review Regime

b. Use of Independent Third Party Audits

2. Civil Penalties

a. Background

b. Whether Civil Penalties Should Be Specified in the OATT

c. Whether Transmission Providers Should Be Subject to Revocation of Their Market-Based Rates for OATT Violations.

d. Whether Certain OATT Violations Should Be Considered Market Manipulation Under the Market Behavior Rules and Section 1283 of EPAct 2005

VI. Information Collection Statement

VII. Environmental Analysis

VIII. Regulatory Flexibility Act Analysis

IX. Comment Procedures

X. Document Availability

Appendix A: Commenter Acronyms

Appendix B:

Pro Forma

Open Access Transmission Tariff

I. Introduction

1. Ten years have passed since the Commission issued its landmark Order No. 888.

Named after our new headquarters in Washington, DC, Order No. 888 sought to eradicate undue discrimination in the provision of transmission service in interstate commerce. It did so by requiring that each public utility that owns, operates, or controls facilities used for transmission in interstate commerce offer unbundled transmission service pursuant to a standard Open Access Transmission Tariff (

pro forma

OATT) and separate its transmission and merchant generation functions pursuant to a companion order issued that same day, Order No. 889.

These remedies reduced barriers to entry, led to greater competition in bulk power markets and provided the foundation for subsequent regulatory reforms at both the federal and state level.

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. ¶ 31,036 (1996),

order on reh'g

, Order No. 888-A, 62 FR 12274 (Mar. 14, 1997), FERC Stats. & Regs. ¶ 31,048 (1997),

order on reh'g

, Order No. 888-B, 81 FERC ¶ 61,248 (1997),

order on reh'g

, Order No. 888-C, 82 FERC ¶ 61,046 (1998),

aff'd in relevant part sub nom. Transmission Access Policy Study Group

FERC

, 225 F.3d 667 (D.C. Cir. 2000) (

TAPS

FERC

aff'd sub nom. New York

FERC

, 535 U.S. 1 (2002).

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).

2. 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.

The Commission in Order No. 2000 thus encouraged utilities to voluntarily join independent regional transmission organizations (RTOs) that would operate their transmission facilities on a non-discriminatory basis and administer the OATT. The Commission based Order No. 2003 on a similar finding, explaining that the interconnection process includes opportunities for undue discrimination that may lead to delays that benefit generation-owning transmission utilities and undermine competition.

While many regions of the country now have independent grid operators, not all do, and changes to the pro forma OATT are necessary to reduce the opportunity for transmission providers to engage in undue discrimination. In the past ten years new investment has faltered and many regions now experience chronic transmission congestion and inadequate infrastructure. Congress, through the Energy Policy Act of 2005 (EPAct 2005),

recognized this problem and provided the Commission not only new tools to encourage infrastructure but also made clear that the Commission should use its existing authority to ensure an adequate infrastructure to support a vibrant economy.

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

FERC

, 272 F.3d 607 (D.C. Cir. 2001).

Order No. 2000 at 31,015.

See

Order No. 2003 at P 11-12.

Pub. L. 109-58, 119 Stat. 594 (to be codified in scattered itles of the U.S.C.).

3. The reforms we propose today are intended to address deficiencies in the

pro forma

OATT that have become apparent since 1996 and to facilitate improved planning and operation of transmission facilities. We summarize these reforms in Part IV.A below, but note the major focus of this reform effort here. As a general matter, 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. We propose to achieve this goal by increasing the clarity and transparency of the rules applicable to the planning and use of the transmission system and by addressing ambiguities and the lack of sufficient detail in several important areas of the pro forma OATT. The lack of specificity in the pro forma OATT creates opportunities for undue discrimination as well as making the undue discrimination that does occur more difficult to detect. First, we propose to improve transparency and consistency in several critical areas, such as the calculation of available transfer capability (ATC).

We propose to direct public utilities, under the auspices of the North American Electric Reliability Council (NERC) and the North American Energy Standards Board (NAESB), to provide for greater consistency in ATC calculation. By reducing unnecessarily broad discretion in this and other areas, we will reduce the ability of transmission providers to unduly discriminate and provide them greater certainty to facilitate compliance with our regulations. Second, we propose to reform the transmission planning requirements of the

pro forma

OATT to eliminate potential undue discrimination and support the construction of adequate transmission facilities to meet the needs of all load-serving entities. The

pro forma

OATT contains only minimal requirements regarding transmission planning, which have proven to be inadequate as the Nation faces inadequate transmission investment in many areas. We propose to require public utilities to engage in an open and transparent planning process at both the local and regional levels. Third, we propose to remedy certain portions of the

pro forma

OATT that may have permitted utilities to discriminate against new merchant generation, including intermittent generation. For example, we propose to modify the energy imbalance provisions of the

pro forma

OATT and adopt certain other tariff modifications. Fourth, we provide for greater transparency in the provision of transmission service to allow transmission customers better access to information to make their resource procurement and investment decisions, as well as to increase our ability to detect any remaining incidents of undue discrimination. Finally, we provide for reform and greater clarity in areas that have generated recurring disputes over the past 10 years, such as rollover rights, “redirects,” and generation redispatch.

We note that 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 is proposing to revise the

pro forma

OATT to adopt the term “Available Transfer Capability.”

4. Although the reforms being proposed in these areas are significant, we wish to underscore that we propose to maintain many of the core elements of Order No. 888. For example, we are retaining the comparability requirement under which each public utility must treat third parties in a manner comparable to its service to bundled customers. We are retaining the basic nature of the services being offered—network service and point-to-point service. We are retaining the protection of native load customers embodied in Order No. 888, consistent with EPAct 2005's new requirement that load-serving entities be provided transmission rights to meet their service obligations.

We are retaining our decision to exercise jurisdiction over unbundled transmission service, but not transmission service provided as part of a bundled retail service. We are retaining the use of functional unbundling to address undue discrimination, rather than requiring corporate unbundling. We are retaining the use of an OATT to facilitate the development of competitive wholesale markets by reducing barriers to entry through the control of transmission assets, not imposing any particular market structure on the industry.

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

5. In proposing to reform Order No. 888, we have relied heavily on the comments received in response to our notices of inquiry in the above-captioned dockets.

We appreciate the time and thoughtfulness of all sectors of the industry in preparing comments on these notices of inquiry. We have found them very informative and useful and this Notice of Proposed Rulemaking (NOPR) incorporates many of the commenters' suggestions. We invite further comments on this NOPR. We also are scheduling technical conferences to more fully address the topics of ATC calculation and transmission planning.

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

6. 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 other 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 due primarily to the cost and technological limitations on the distance over which electricity could be transmitted.

7. 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),

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.

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

Pub. L. 95-617, 92 Stat. 3117 (1978) (codified in U.S.C. titles 15, 16, 26, 30, 42, and 43 (2000)).

Section 211 of the FPA, 16 U.S.C. 824j (2000). 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

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

Florida Power and Light Company

, 839 F. Supp. 1563 (M.D. Fla. 1993).

8. 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 possessed.

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.

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.

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).

See

Order No. 888 at 31,644 n.52.

9. 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).

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.

EPAct 1992 also expanded the Commission's authority to approve applications for transmission services under sections 211 and 212 of the FPA. 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.

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 (2000)).

15 U.S.C. 79a (2000),

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).

B. Order No. 888 and Subsequent Reforms

10. 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.

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).

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 and 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 which conditions the use by non-public utilities of public utilities' open access services on an agreement to offer open access services in return.

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 retain ownership over both functions.

See infra

Part IV.B.4.

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 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).

11. 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 “have the potential to provide significant benefits (

e.g.

, to help provide regional efficiencies, to facilitate economically efficient pricing, and, especially in the context of power pools, to remedy undue discrimination and mitigate market power) and will further our goal of achieving a workably competitive market.”

While the Commission declined to mandate ISOs, it set forth eleven principles for assessing ISO proposals submitted to the Commission.

Order No. 888 at 31,655.

Id.

at 31,730-32.

12. Order No. 888 also clarified the Commission's interpretation of the federal/state jurisdictional boundaries over transmission and local distribution. While it reaffirmed that the Commission has exclusive jurisdiction over the rates, 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.

New York

FERC

, 535 U.S. 1 (2002).

13. The same day it issued Order No. 888, the Commission issued a companion order, Order No. 889, addressing both 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.

14. Among the information required to be posted by Order No. 889 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.”

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.

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.

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.”

Order No. 889 at 31,605.

Id.

at 31,607.

Id.

15. 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.

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.

See Energy Information Administration, Retail Unbundling—U.S. Summary (2005),

http://www.eia.doe.gov/oil_gas/natural_gas/restructure/state/us.html.

16. In the wake of these changes, in December 1999, the Commission adopted Order No. 2000.

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.

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.”

See supra

note 3.

Order No. 2000 at 31,015.

Id.

at 30, 993.

17. Following Order No. 2000, RTOs were approved in several regions of the country including the Northeast (PJM Interconnection, Inc.; ISO New England), 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.

C. EPAct 2005 and Recent Developments

18. EPAct 2005,

enacted on August 8, 2005, added a number of new authorities and priorities for the Commission and emphasized certain of its existing obligations. Specifically, EPAct 2005 recognized the importance of adequate transmission infrastructure development and its role in facilitating the development of competitive wholesale markets. For example, Congress required the Commission to adopt a rule establishing incentive ratemaking for transmission infrastructure to help promote reliability and reduce congestion.

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.”

Congress also gave the Commission certain “backstop” transmission siting authority, and authorized the creation of interstate compacts establishing transmission siting agencies.

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.

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.

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.

Finally, Congress emphasized compliance with the Commission's regulations, increasing the civil and criminal penalties for violations of Commission-administered statutes and regulations.

See supra

note 6.

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

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

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

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

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 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.” EPAct 2005 sec. 1234 (b).

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

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).

19. Recognizing the need for reform of Order No. 888 in light of these developments and those described in the next section, the Commission issued an NOI in September 2005 seeking comments on the reforms needed to the Order No. 888

pro forma

OATT to prevent undue discrimination and preference in the provision of transmission services. 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.

20. 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, our experience in implementing Order No. 888, and the changes in the industry since we adopted it, we conclude that reform of the

pro forma

OATT is necessary, for the reasons we discuss next.

III. The Need for Reform of Order No. 888

A. Opportunities for Undue Discrimination Continue To Exist

21. In Order No. 2000, the Commission found that “opportunities for undue discrimination continue to exist that may not be remedied adequately by [the] functional unbundling [remedy of Order No. 888].”

The Commission made a similar finding in Order No. 2003, holding that opportunities for undue discrimination continue to exist in areas where the

pro forma

OATT leaves transmission providers with substantial discretion.

The Commission has a responsibility under section 206 of the FPA to remedy undue discrimination.

Our action today proposes to fulfill that responsibility by proposing reforms to the

pro forma

OATT that will address remaining opportunities for undue discrimination.

Order No. 2000 at 31,105.

Order No. 2003 at P 11-12.

Associated Gas Distributors

FERC,

824 F.2d 981 (D.C. Cir. 1987), (

AGD

), the court concluded that, like the Natural Gas Act, the FPA “fairly bristles” with concern over undue discrimination. Based on

AGD

, the Commission determined in Order No. 888 that:

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.

22. As the Commission noted 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 themselves.

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.

Transmission customers also have found ways to use the tariffs to their own advantage, particularly in the scheduling and queuing processes.

Finally, tariff provisions have been modified in numerous ways on a company-by-company basis, leading to uncertainties within the industry as to the proper interpretation of those provisions and to unnecessarily inconsistent treatment of transmission customers across public utilities.

Id.

at 31,682.

See, e.g.

, Order No. 2003 at P 11-12.

See, e.g.

, Potomac Economics, Ltd.,

2004 State of the Market Report: Midwest ISO

at 30-31, 34-35 (Jun. 2005) (explaining that the queuing process, by giving customers the opportunity to submit multiple requests for service, 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),

http://www.midwestmarket.org/publish/Document/2b8a32_103ef711180_-7bf20a48324a/2004%20MISO%20SOM%20Report.pdf?action=download&_property=Attachment.

23. Commenters suggest that enhanced clarity and consistency in the

pro forma

OATT would go a long way toward eliminating the opportunities for undue discrimination and the perception that it is occurring.

Calpine notes that undue discrimination is most likely to occur when the transmission provider retains discretion to implement an OATT provision in a manner that favors its affiliated generation. APPA asserts that the success of the OATT regime depends on public utilities' ability to faithfully implement the OATT's provisions. Large transmission providers share this view to some degree. Entergy notes that a lack of clarity is at the heart of many disputes involving the OATT, and urges the Commission to improve the OATT in a manner that will minimize the potential for future violations. Duke posits that tariff terms and conditions that are susceptible to multiple interpretations present opportunities for discrimination and/or the perception thereof. Progress Energy agrees that several OATT provisions can be interpreted differently, leaving room for disagreement as to their meaning.

E.g.,

Calpine, Duke, and MidAmerican. (A list of commenter acronyms may be found in Appendix A). As the Commission noted in Order No. 2000, “[p]erceptions of discrimination are significant impediments to competitive markets. Efficient and competitive markets will develop only if market participants have confidence that the system is administered fairly.” Order No. 2000 at 31,017.

24. Perhaps the most obvious deficiency in this regard is ATC calculation. In Order Nos. 888 and 889, the Commission declined to require a specific methodology for ATC calculation. As a result, there are few clear rules respecting ATC calculation, and transmission providers, therefore, retain unnecessarily broad discretion in this area. On systems where transmission capacity is congested, this lack of consistency, coupled with a lack of transparency, has led to recurring disputes over whether the transmission provider is exercising its discretion to discriminate against its competitors.

25. There is a similar lack of clarity in the transmission provider's planning obligations. Order No. 888 included a general obligation on the part of the transmission providers to plan on a comparable basis (

i.e.

, comparable to the manner in which it would plan for its own needs) to serve network loads and to construct new facilities as necessary to respond to requests for firm service from point-to-point customers. However, there were no clear guidelines with respect to whether transmission customers should be included in the planning process, what standards and criteria should be used in system planning, and whether the planning process should identify potential economic upgrades that could benefit a wide range of customers, as opposed to responding only to customer-specific requests. Here too, this lack of clarity has led to significant disputes over whether transmission providers are planning on a nondiscriminatory basis or are favoring service to their own loads.

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

26. A major focus of comments on the NOI is that increased transparency would aid transmission customers in their participation in the wholesale market.

Constellation explains that the transmission provider's unique position as the owner and operator of the transmission system and often the majority of the generation assets in its control area gives it better information than its transmission customers. Moreover, the transmission provider, Constellation argues, has financial incentives to use the system differently, and more efficiently, to serve its own loads than to serve its other customers under the

pro forma

OATT. TDU Systems urges the Commission to ensure that transmission providers make their actions under the OATT completely transparent on a timely basis to all transmission customers. NARUC posits that enhanced reporting requirements, if sufficiently targeted, would facilitate greater transparency in transmission activities. Alberta Intervenors states that the current

pro forma

OATT provides transmission customers with only a narrow glimpse of how the system is being operated. For example, Bonneville notes that many terms and conditions of native load service are not transparent to OATT transmission customers.

EEI also states that greater transparency, such as with respect to ATC calculation, can increase confidence in open access and potentially reduce claims of undue discrimination.

E.g.,

LG&E, MidAmerican, Midwest SATs, TDU Systems, and Williams.

Bonneville urges the Commission to require load-serving transmission providers to post the same information for bundled retail load that they must post for service to network customers.

27. Calpine argues that undue discrimination is difficult to detect given the lack of access to data, analytical assumptions, and processes used by transmission providers to determine transmission access and service. It recommends that the Commission increase reporting requirements for denials of transmission service, for congestion management mitigation events, including curtailments and redispatch, and for transmission expansion planning decisions. Powerex notes that the Commission already has posting standards, and urges the Commission to enforce them and to increase requirements to provide more meaningful posting of reliable ATC data, curtailment methodology and results, details relating to denials of service, and congestion information. Constellation agrees, urging the Commission to require OASIS posting of service metrics, such as all transmission requests approved, rejected, confirmed and curtailed.

28. A common theme in the comments is that the lack of transparency can lead to claims of undue discrimination and can make such claims more difficult to resolve.

As such, National Grid asserts that greater transparency will allow the Commission and transmission system users to understand when a transmission access decision is

motivated by a legitimate reason rather than an intent to discriminate. If transmission customers have more accurate information about the transmission service request process, National Grid contends, they also will have more accurate expectations and a better understanding of how to expedite the implementation of service. Though NRECA agrees that increased transparency will allow the Commission to deter undue discrimination and facilitate accountability, it urges the Commission to require not just raw data but meaningful, clear and understandable data, in a format that facilitates understanding.

E.g.,

Ameren, National Grid, and NRECA.

29. Commenters urge the Commission to improve the transparency of transmission service in a number of areas, particularly the evaluation of ATC and the planning of the transmission system.

Another area often cited as lacking sufficient transparency is the processing of transmission service requests and studies. For example, several commenters note that system impact studies are often not completed within the tariff-prescribed time limits, and that information about that process is not available to transmission customers.

TDU Systems suggests that one way to address the difficulty of determining acceptable delays is to require transmission providers to post statistics on their OASIS sites providing information as to the length of time it might take to process requests for transmission service. Cinergy proposes that adopting such reporting metrics could result in an improved quality of service.

We discuss these specific aspects of the

pro forma

OATT below in Parts V.A. and V.B.

E.g.,

Constellation, EPSA, Powerex, and Williams.

30. We agree that a lack of transparency both increases the potential for undue discrimination and makes it more difficult to detect. We believe this lack of sufficient transparency is caused in part by inadequate compliance with our existing OASIS regulations, and in part by inadequate transparency requirements. Our reforms address both elements of the problem in an effort to increase confidence in open access tariffs and to facilitate compliance with our regulations and our enforcement of them.

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

31. The ability and incentive to discriminate increases as the transmission system becomes more congested. Vertically integrated utilities do not have an incentive to expand the grid to accommodate new entry or to facilitate the dispatch of more efficient competitors. Even with the advent of RTOs, transmission infrastructure development has not kept pace with the increase in demand for electricity. Transmission capacity is being constructed at a much slower rate than the rate of increase in customer demand. Indeed, transmission capacity per MW of peak demand declined at an average rate of 2.1 percent per year during the period 1992 to 2002.

Investment for the most recent year available, 2003, was below 1975 levels,

and projections suggest that this trend will continue through 2012.

As a result, there has been a significant decrease in transmission capacity relative to load in every NERC region.

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.

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.”

These systems were built to meet the vertically integrated utilities' retail native load obligations, not to support the development of a bulk power market.

Eric Hirst,

U.S. Transmission Capacity: Present Status and Future Prospects

(Aug. 2004), available at

http://www.eei.org/industry_issues/energy_infrastructure/transmission/USTransCapacity10-18-04.pdf

(Present Status and Future Prospects).

EEI,

EEI Survey of Transmission Investment: Historical and Planned Capital Expenditures (1999-2008)

at 3 (May 2005), available at

http://www.eei.org/industry_issues/energy_infrastructure/transmission/Trans_Survey_Web.pdf.

Present Status and Future Prospects at v.

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) Transmission Independence and Investment.

Energy Policy Act of 2005: Hearings before the House Subcommittee on Energy and Commerce

, 109th Congress, First Sess. (2005) (Prepared statement of Thomas R. Kuhn, President of EEI).

Present Status and Future Prospects at v.

32. Inadequate expansion of the transmission grid has contributed to increasing transmission 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: (1) From the Midwest to the Mid-Atlantic, (2) from the Midwest to the Tennessee Valley Authority (TVA), (3) into and within California, (4) from TVA and Southern into Entergy, (5) from Mid-America Interconnected Network into Wisconsin-Upper Michigan Systems, and (6) into Florida. The existence of these and other constraints affecting transmission systems can result in an increase in the frequency of denials of requests for transmission service, and an increase in the frequency of transmission service interruptions and/or curtailments of transmission service. While not all congestion needs to be remedied (

i.e.

, if the cost of the congestion is less than the cost to relieve it), it is also true that undue discrimination and preferential treatment also are much more difficult to detect when the transmission grid is constrained, given the lack of transparency in ATC calculations and transmission system planning. Increased congestion also presents additional opportunities for undue discrimination. As a result, it is more difficult for the Commission to carry out its statutory responsibility to ensure that transmission providers provide nondiscriminatory open access transmission service.

33. In recognition of the lack of adequate infrastructure, a broad cross-section of the industry supports greater coordination in the planning and investment in transmission infrastructure between transmission providers, transmission customers and state regulatory agencies. A major focus of comments on our NOI was the need to plan and build infrastructure to facilitate regional electricity markets. For example, AEP argues that the most important issue faced by public utilities and their customers is not day-to-day OATT administration but the planning and expansion of the transmission grid. EEI likewise asserts that the focus should be on the need to develop energy infrastructure necessary to facilitate growth in wholesale electric market transactions. Santa Clara acknowledges that lack of needed infrastructure causes the grid to become constrained and less reliable, which sometimes provides even stronger incentives for owners to restrict access by others. The Nevada Companies urge the Commission to focus on ways Order No. 888 and the

pro forma

OATT can be revised to eliminate disincentives to the construction of additional transmission facilities. Xcel suggests that the

Commission focus its efforts on ways to encourage investment in new energy infrastructure as a way of easing congestion and enabling growth in market transactions. Salt River contends that the Commission should increase incentives to participate in long-term regional planning processes. Midwest SATs argue that increased access for all transmission system users through policies that promote investment in transmission will do more to reduce undue discrimination than policies that seek to uncover and penalize such discrimination.

34. Customers also complain that there is often a lack of transparency in utility transmission planning processes, which the customers claim typically do not include economic system upgrades that would benefit non-affiliate users of the system. Customers also note the lack of clarity in the existing planning obligations required of transmission providers. They assert that these failures have contributed to the inadequate development of the transmission grid.

35. Order No. 888 contemplated that ISOs would enhance infrastructure development through open and regional planning processes, but these efforts have stalled in many regions of the country. Even where RTOs have been established, there have been concerns that the planning process has not always been sufficiently robust, inclusive or transparent to ensure that transmission investment occurs where it is reasonably needed for all users of the grid. For example, in its reply comments, TDU Systems urges the Commission to include RTOs in its planning reforms, contending that many RTO planning processes are not open to all stakeholders, nor are they collaborative and inclusive. Many commenters argue that RTO transmission planning regimes have failed to get needed transmission facilities built.

E.g.,

APPA, TDU Systems Reply Comments, and Williams Reply Comments.

36. We conclude that the inadequacy of the existing obligation to conduct joint and regional transmission system planning, coupled with the lack of transparency surrounding system planning generally, require 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.

D. A Consistent Method of Measuring ATC Has Not Been Established

37. Under Order No. 888, each public utility calculates the amount of transfer capability on its system that is available for sale to third parties.

However, Order No. 888 did not require that the methodology for ATC calculation be standardized across the industry, nor did it impose any specific requirements regarding the disclosure of the methodologies used by each transmission provider. As a result, there are a variety of ATC calculation methodologies in use today. Moreover, there is often very little transparency regarding the nature of these calculations, given that many transmission providers have filed only summary explanations of their ATC methodologies in Attachment C to the OATT. As a result, transmission providers retain unnecessarily broad discretion in calculating ATC. The 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. This discretion, coupled with the lack of transparency, 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.

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

APPA submitted comments in Docket No. RM05-17-000 arguing that the calculation and posting of ATC “sits at the pivot point among reliability, economic regulation and wholesale electric commerce.” APPA at 5.

38. The comments on the NOI and the ATC NOI reflect these underlying problems. Many market participants complain that there is widespread misinformation regarding the actual ATC, which results in missed opportunities for transactions. ATC calculation errors often occur. A lack of transparency leaves transmission customers unaware of why some transmission requests are granted and others are denied.

Several ATC inputs, such as the capacity benefit margin (CBM) or the transmission reliability margin (TRM), can be calculated using overly conservative or otherwise faulty assumptions. Transmission customers often complain that transmission providers designate unreasonably high CBM or TRM levels, which limits the amount of remaining transfer capability available for other users of the system.

See, e.g.,

EEI at 18 (agreeing that the Commission should require transmission providers to make their ATC calculations more transparent).

39. As a result of these uncertainties, the Commission issued the ATC NOI to address the lack of clear and consistent methodologies for calculating ATC. In the ATC NOI, the Commission acknowledged that NERC has been working on specific recommendations for calculating and coordinating ATC and available flowgate capability (AFC).

That NERC effort culminated in a report and a number of recommendations. The Commission asked for comments on those recommendations, as well as comments on whether there should be common transmission calculation methodologies among regions. The Commission has reviewed those comments as part of this proceeding.

See

NERC,

Long-Term AFC/ATC Task Force Final Report

(2005) (NERC Report) at 2, available at

ftp://www.nerc.com/pub/sys/all_updl/mc/ltatf/LTATF_Final_Report_Revised.pdf.

Accordingly, we consolidate Docket No. RM05-17-000 with this proceeding. We will distinguish the comments received in the ATC NOI proceeding by the designation “ATC NOI Comments.” In addition, we also revise the name of the proceeding in Docket No. RM05-17-000 to “Preventing Undue Discrimination and Preference in Transmission Service.”

40. Many commenters support the development of a consistent, industry-wide methodology for calculating ATC.

These commenters maintain that a requirement that all transmission providers use the same methodology to determine ATC would not only remedy the lack of clarity that surrounds these calculations and reservations, but would provide regulatory certainty and assist transmission customers in predicting the outcome of transmission service requests.

E.g.,

Alcoa, AWEA, Constellation, Exelon, Occidental, and Renewable Energy.

41. We agree. Although the industry has sought to pursue greater consistency in ATC calculations through existing NERC processes, those efforts to date have been largely unsuccessful. 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. We therefore propose below a number of reforms to the process of calculating ATC to provide clarity and transparency to users of the grid.

E. A Number of Transmission Pricing Policies May Impede the Use of the Grid

42. Transmission customers often complain about the level and scope of imbalance charges that are levied under the

pro forma

OATT and under individual interconnection agreements.

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. Customers complain that these 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. 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. Generators likewise complain that these 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 penalties, which are imposed to provide an incentive for generators to schedule accurately, are inappropriate given their lack of control and ability to cure deviations.

43. Transmission providers and customers raise a number of concerns related to the pricing of transmission service under Order No. 888, contending that the Commission's pricing policies are in need of reform. For example, under the

pro forma

OATT, network customers can receive a credit toward their transmission charges for new facilities that they jointly plan with the transmission provider. Customers contend that this provision actually acts as a disincentive for joint planning because transmission providers can avoid granting credits if they fail to jointly plan with their transmission customers.

44. Finally, there is also concern about the appropriate rate for transmission capacity that has been resold by the original transmission customer. Under Order No. 888, such capacity may be priced at the higher of the original rate, the transmission provider's maximum stated firm rate, or the assignor's opportunity costs capped at the cost of expansion. Customers complain that this policy does not work when opportunity costs exceed the embedded cost rate, because the assignor must make a FPA section 205 filing with the Commission that estimates its opportunity cost over the term of the reassignment as well as the cost of system expansion. The time and effort required to complete the regulatory process appears to inhibit such reassignments.

45. Although Order No. 888 was primarily directed at establishing the non-rate terms and conditions of open access, the rule did adopt certain pricing policies that were associated with the form of open access being ordered. After reviewing the comments, we believe certain reforms are appropriate because some of the pricing policies associated with the

pro forma

OATT are no longer just and reasonable or are otherwise unduly discriminatory. However, we do not intend to pursue generic reform of other pricing policies that are better addressed on a region-or case-specific basis, such as the pricing of new transmission facilities.

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

46. The reforms we propose today also are consistent with the policies and priorities embodied in EPAct 2005, in which Congress emphasized many of the principles reflected in this NOPR.

47. First, Congress in EPAct 2005 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.”

FPA section 219 requires the Commission to “promot[e] 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.”

Congress also gave the Commission certain “backstop” transmission siting authority, and authorized the creation of interstate compacts establishing transmission siting agencies.

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 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.”

Although these provisions are, or will be, addressed primarily in other proceedings, our NOPR is consistent with these provisions because it supports new infrastructure by reforming the transmission planning process to ensure that it is open, transparent and nondiscriminatory.

EPAct 2005 sec. 1241 (to be codified at section 219 of the FPA, 16 U.S.C. 824s). The Commission issued a NOPR implementing such an incentive rate program in November 2005.

See Promoting Transmission Investment through Pricing Reform

, 70 FR 71409 (Nov. 29, 2005), FERC Stats. & Regs. ¶ 32,593 (2005).

FPA Sec. 219(b)(1).

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

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

We note that we also have proposed to implement FPA section 217(b)(4) in a separate rulemaking in Docket No. RM06-8-000.

48. 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.”

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.” Our NOPR similarly seeks to promote greater transparency in the provision of transmission service in many important areas, including ATC calculation and transmission planning.

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

49. Finally, Congress emphasized compliance with the Commission's regulations, increasing the civil and criminal penalties for violations of Commission-administered statutes and regulations.

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 Enforcement Policy Statement, 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.

The NOPR is fully consistent with these principles because it seeks, in many areas, to clarify our rules to facilitate compliance by transmission providers.

EPAct 2005 sec. 1284(e)(1) (to be codified at section 316(A) of the FPA, 16 U.S.C. 825o-1 (2000).

Enforcement of Statutes, Orders, Rules and Regulations,

Policy Statement on Enforcement, 113 FERC ¶ 61,068 (2005) (Enforcement Policy Statement).

IV. Summary, Scope and Applicability of the Proposed Rule

50. This section provides: (1) A summary of the major components of the NOPR, (2) a description of the core elements of Order No. 888 that we propose to retain, and (3) a discussion of the applicability of the proposed rule to various entities.

A. Summary of Proposed Reforms

51.

Consistency and transparency of ATC calculations.

The Commission finds 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 and, therefore, may be unjust, unreasonable, unduly discriminatory and preferential. As a result, we propose to give the industry specific guidance and a firm deadline to develop certain requirements to make the process of calculating ATC and the process of exchanging data between transmission providers about ATC more consistent. In addition, we propose to amend

pro forma

OATT requirements as well as our OASIS regulations to increase the transparency in how ATC is calculated.

52.

Requirement for coordinated, open and transparent transmission planning.

The Commission finds that Order No. 888 does not contain sufficient protections to guard against undue discrimination in transmission system planning. This, in turn, can affect a customer's ability to obtain transmission service and the price it pays for transmission. Specifically, Order No. 888 does not require sufficient coordination, openness, and transparency in transmission planning to ensure that new infrastructure is constructed to meet the needs of all eligible customers on a not unduly discriminatory basis. 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 propose to 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 propose eight planning principles 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.

53.

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 intend to initiate broad reform of transmission pricing policy through this NOPR. 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 existing energy and generator imbalance charges may be excessive and otherwise unrelated to the cost of providing the service and, therefore, propose to reform energy and generator imbalance pricing. We propose to require that all such imbalance charges 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 may no longer be just and reasonable and, therefore, propose to 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. We seek comment on this proposal and, in particular, the nature of the reporting obligations that should be imposed as part of lifting the cap on reassignment.

•

Crediting of Customer-Owned Facilities.

We propose to 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 propose to eliminate the requirement that new facilities can receive credits only if they are “jointly planned” because this requirement may provide a disincentive to coordinated planning. Rather, we propose that such new facilities be eligible for credits if: (1) Such facilities are integrated into the operations of the transmission provider's facilities, and (2) such facilities would be eligible for inclusion in the transmission provider's annual transmission revenue requirement if owned by the transmission provider.

54.

Improvements to Point-to-Point Service.

The Commission concludes that the existing methods for evaluating requests for long-term firm point-to-point service may no longer be just, reasonable and not unduly discriminatory. 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. 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 time-consuming and costly facilities studies does the transmission provider evaluate redispatch options, including whether they are less expensive than the upgrade options. The Commission proposes to address this problem by clarifying that a transmission provider must use all of its available redispatch options to satisfy a request for firm point-to-point service and, at the transmission customer's option, these redispatch options must be studied before the customer is obligated to incur the costs and time delays associated with a facilities study. The Commission also seeks comment on whether this remedy is adequate or, alternatively, whether the Commission should modify the nature of point-to-point service to require that transmission providers offer a “conditional firm” service that would be subject to curtailment prior to firm service only a limited number of hours of the year.

55.

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 “rollover” their contracts, is in need of reform. The Commission proposes to revise that provision to apply to contracts that have a minimum term of five years, rather than the current minimum term of one year. We conclude that this reform will ensure that the rollover right is enjoyed by transmission customers that have made a significant commitment to (and investment in) the transmission grid. In addition, the Commission proposes that a transmission customer eligible for rollover rights must provide notice of whether or not it will exercise its right of first refusal to renew the contract no less than one year prior to the expiration date of the transmission service agreement, rather than within the current 60-day period.

56.

Increases in transparency to lessen the opportunities to discriminate and reduce transaction costs.

In addition to the increased transparency we propose to require regarding the calculation of ATC and transmission planning, we propose to increase the transparency of transmission service provided under the

pro forma

OATT in several other respects. For example, we propose to require transmission providers and their network customers to use the transmission provider's OASIS to request designation of a new network resource and to terminate the designation of an existing network resource. In addition, we propose to require the transmission provider to modify its OASIS so that requests to designate and terminate a network resource can be queried. We also propose 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. Finally, we propose to 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.

57.

Strengthening enforcement of the pro forma OATT.

Our proposed reforms include several clarifications of the terms and conditions of the

pro forma

OATT that have made undue discrimination difficult to detect and otherwise frustrated enforcement of the obligation to provide open access, non-discriminatory transmission service. 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. In addition, we propose 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 propose to 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 propose to require transmission information kept on OASIS to be retained for audit purposes for five years. Finally, we make a number of proposals relating 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.

58. Miscellaneous OATT improvements. We propose 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:

Hourly Firm.

We propose to require transmission providers to offer hourly firm service under the

pro forma

OATT.

Designation of network resources.

We propose to make a number of clarifications related to 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 propose to require customers to submit an attestation with each application to designate a new network resource.

Reservation priorities.

We propose to change the priority rules to give priority to pre-confirmed transmission service requests submitted in the same time period. We also propose to 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 propose to clarify that a network customer may not use secondary network service to bring energy onto its system to support an off-system sale if the purchased power does not displace the customer's own higher cost generation. We also propose clarifications related to use of network service on an “as available basis” and to “redirects” of network service.

Definitions.

In addition to some minor revisions, we propose to add a definition of “non-firm sales” to the

pro forma

OATT and propose to amend the definition of Good Utility Practice to reference the definition of “reliable operation” adopted in EPAct 2005.

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

59. Although we are proposing many important reforms to Order No. 888 and the

pro forma

OATT, we also wish to emphasize that we propose to retain many of the core elements of Order No. 888. We note that many of these core elements enjoy broad support across many sectors of the industry. In their comments, APPA, EEI, and NARUC urge the Commission to proceed carefully in reforming Order No. 888, focusing on incremental reforms not industry restructuring. We share the view that Order No. 888 can be strengthened without discarding its fundamental structure. We discuss below the core elements that are being retained and, where appropriate, respond to the comments on these points that were received in the NOI.

1. Federal/State Jurisdiction

60. 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.

Though the Commission adopted a test for determining which facilities were used for retail transmission, as opposed to local distribution to end-users,

the Commission stated that it generally would defer to determinations by state regulatory authorities concerning where to draw the jurisdictional line under that test.

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.”

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.

Order No. 888 at 31,781.

Id.

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

Id.

at 31,781.

Id.

See New York

FERC,

535 U.S. 1, 28 (2002).

61. We propose to retain the jurisdictional divide we established in Order No. 888. We also are mindful of the need for heightened cooperation between federal and state regulators in areas where there are overlapping federal and state policy concerns. Moreover, our jurisdictional determination was sustained by the U.S.

Supreme Court and has been accepted by industry and state regulatory authorities. We see no reason to disturb that determination now.

2. Native Load Protection

62. Order No. 888 did not require transmission providers to unbundle transmission service to their retail native load nor did it require that bundled retail service be taken under the terms of the

pro forma

OATT.

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.

As noted above, Order No. 888 granted a rollover right to existing firm service customers,

but allowed transmission providers to restrict that rollover right if the capacity was reasonably forecasted to be needed to serve native load customers, as long as that restriction was specified in the customer's service contract.

Order No. 888 at 31,745.

Id.

at 31,694.

Id.

;

pro forma

OATT section 2.2.

Order No. 888-A at 30,198.

63. 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. It allows load-serving entities to use their own and contracted-for transmission capacity to the extent required to meet their service obligations, without being subject to charges of unlawful discrimination. Among other things, FPA section 217 states that it does not require the abrogation of any contract or service agreement for firm transmission service or rights in effect as of the date of enactment.

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

64. In the NOI, the Commission stated that it was not proposing to change the protection of native load embodied in Order No. 888.

The Commission sought comment on whether the approach the Commission took in Order No. 888 is the same as that set forth in FPA section 217.

NOI at P 9.

Comments

65. Several commenters argue that the approach the Commission took in Order No. 888 is largely consistent with the treatment of native load preference in FPA section 217.

They state that Order No. 888 makes clear that native load has a priority right to a transmission providers' capacity and that transmission providers may reserve a portion of their capacity for native load growth.

E.g.

, Memphis Light, Newmont Mining Reply Comments, Progress Energy, and TDU Systems.

66. Other commenters perceive varying degrees of difference between Order No. 888 and FPA section 217.

EEI states that FPA section 217 extends native load protection to all load-serving entities that have direct or indirect service obligations to end-users for terms of one year or more, while Order No. 888 does not. Nevada Companies and TAPS argue that the FPA section 217 requirement that the Commission exercise its authority to facilitate the planning and expansion of transmission facilities to satisfy the service obligations of load-serving entities necessitates changes to Order No. 888.

E.g.

, Duke, EEI, Metropolitan Water District, and Southern.

67. Several commenters argue that FPA section 217 requires the Commission to revisit its rollover rights policy.

Duke maintains that the current Commission approach is not the same as set forth in either Order No. 888 or FPA section 217 because the Commission's current approach to rollover rights does not meaningfully recognize the native load preference. Commission decisions since Order No. 888, according to Duke, have weakened the native load preference envisioned in Order No. 888 to the point where the Commission's treatment of the native load preference is not what Congress provides in FPA section 217. LPPC argues that FPA section 217 reverses Commission precedent that makes it impossible to recall capacity for native load once it is subject to a rollover right.

E.g.

, Duke, Energy, LPPC, Progress Energy, Salt River, Santee Cooper, and Southern.

68. EEI states that in order to harmonize Order No. 888 rollover rights with the native load protections contained in FPA section 217, the Commission should revise the

pro forma

OATT to require a notice period for rollover rights that is consistent with the time needed to plan for and construct transmission facilities to serve native load customers and the rollover customer. EEI and Salt River argue that FPA section 217 requires that the Commission permit load-serving entities to implement curtailment procedures that recognize native load service priorities.

69. Metropolitan Water District argues that the mandate to preserve native load preference is complicated further when a transmission owner has transferred operational control to an ISO or RTO. In such a scenario, to honor the native load preference in FPA section 217, Metropolitan Water District contends that the Commission either should reconsider its prior rulings rejecting the allocation of physical rights to serve native load or should require ISOs and RTOs to issue financial rights options, in addition to financial right obligations, so that load-serving entities have a greater ability to avoid congestion costs in serving their native load.

Discussion

70. The Commission concludes that the protection of native load embodied in Order No. 888 is consistent with FPA section 217, and we reaffirm our commitment to the protection of native load. Order No. 888 gave public utilities the right to reserve existing transmission capacity needed for native load growth reasonably forecasted within the utility's current planning horizon. It also allowed transmission providers to restrict rollover rights based on a reasonably forecasted need at the time the contract is executed. This approach 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. Though commenters appear to believe FPA section 217 would support the cancellation of contracts that include rollover rights, FPA section 217 by its terms does not contemplate abrogation of existing transmission service contracts.

However, to the extent commenters argue that the terms of service and notice periods associated with the OATT rollover rights are too short to protect native load adequately, we note that we are proposing to extend them in this NOPR.

See

FPA section 217(f) (explaining that section 217 does not abrogate any firm service agreements or rights in effect as of the date of enactment).

71. In response to Metropolitan Water District, the Commission finds that the issue of firm transmission rights in organized markets is best addressed as part of the long-term firm transmission rights rulemaking in Docket Nos. RM06-8-000 and AD05-7-000. We further note, in response to the comments of Nevada Companies and TAPS, that we are proposing a coordinated and regional planning process to facilitate the planning and expansion of transmission facilities pursuant to FPA section 217.

3. The Types of Transmission Services Offered

72. 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 NOI, the Commission sought comments on whether the Commission should require transmission providers to offer transmission services in addition to, or in place of, the point-to-point and network services prescribed in the OATT.

73. Among other questions, the Commission asked whether network service alone or both network and point-to-point services should be converted into a single contract demand service.

Generally speaking, contract demand service is a hybrid of point-to-point and network services that is reservation-based and allows transmission customers to receive a firm entitlement to integrate multiple resources and deliver energy to multiple points, without paying a separate charge for each point of receipt or delivery. Contract demand service would allow current point-to-point customers to avoid having to arrange and pay for separate reservations for each point of receipt. And current network customers would be allowed to pay for transmission based on the amount of their reservation rather than customer loads at a delivery point.

For examples of contract demand service, the Commission cited

Florida Power Corp.

, FERC ¶ 61,248 (1995);

Wisconsin Electric Power Co.

, 72 FERC ¶ 61,033 (1995); and

Florida Power Corp.

, 81 FERC ¶ 61,247 (1997).

Comments

74. Most commenters argue against requiring that network service alone or in combination with point-to-point service be converted into contract demand service.

Some warn that the imposition of this service would interfere with efficient transmission system planning and operation due to increased capacity reservations that would go unused.

They also argue that it would result in significant cost shifts among transmission customers if not priced correctly. FP&L argues that the current services are a better match for the actual use of the transmission system and thereby permit more ATC to be available.

E.g.

, Ameren, APPA, Bonneville, Calpine, EEI, EPSA, Fallon Reply Comments, FP&L, NRECA, PacifiCorp, Southern, Suez Energy NA, TVA, TAPS, and TDU Systems.

E.g.

, EEI, FP&L, KCP&L, and TVA.

75. Some commenters ask that the Commission require transmission providers to offer contract demand service as an additional transmission service option in the

pro forma

OATT.

AMP-Ohio argues that, as long as Commission policy requires network customers to pay load-ratio network transmission charges for load served with behind-the-meter generation, contract demand network service is essential to avoid unduly discriminatory transmission charges. Midwest Municipals and FMPA argue that the Commission should order contract demand service where the transmission provider does not plan and operate its system to meet total customer load because, as the Commission stated in Order No. 888, full network service is essential for achieving comparability and efficient integration of power supply and load. FMPA contends that where a customer needs network service from another system for only part of its load, it would benefit from being able to buy system power from multiple designated resources for part of its load. In this way, FMPA continues, the transmission provider would not have the planning obligation for the customer's entire load, perhaps avoiding or delaying expensive transmission additions. FMPA claims that such service would tend to benefit all transmission users because it would allow a more efficient use of the grid and provide additional transmission revenues.

E.g.

, AMP-Ohio, APPA, Cogeneration Association of California Reply Comments, Constellation, EPSA, FMPA Reply Comments, Midwest Municipals, PacifiCorp, and Public Power Council.

76. Other commenters state that transmission providers should have the option whether to offer contract demand or other customized transmission services.

LPPC argues that the Commission should allow a transmission provider to voluntarily provide alternative forms of transmission service where circumstances support their implementation, with the caveat that such service must not place any market participant at a disadvantage or increase transmission rates for network or point-to-point customers. Southern proposes that the

pro forma

OATT be modified to include a process through which a transmission provider may propose to adopt new services that customers specifically request.

E.g.

, LPPC, NRECA, and Southern.

77. Commenters also raise general concerns regarding the use and potential abuse of network contract demand service. For example, MidAmerican argues that contract demand service should not be used as a means for transmission customers with behind-the-meter generation to avoid paying for a load-ratio share of a system that was built to support their entire load and on which they rely for service. Rather, MidAmerican continues, network contract demand service should be limited to situations in which deliverability is physically limited, such as where the integrated transmission system does not have the capacity to serve all the load at a designated point of delivery. EEI argues that the Commission should not convert network service to network contract demand service because conversion would result in a substantial reduction in ATC as it would provide contract rights on the transmission system on an around-the-clock basis that are equal to network load's monthly or annual peak loads.

Discussion

78. We propose to retain the services we ordered in Order No. 888: firm and non-firm point-to-point service and firm network service. We do not propose requiring 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. The Commission continues to believe that network and point-to-point services are the appropriate base-line service offerings in the OATT. Although forms of contract demand service have been approved by the Commission, and the service may provide benefits to certain customers, sufficient potential drawbacks exist that prevent us from concluding that it is a necessary transmission service that should be included in the

pro forma

OATT. 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. While the Commission concludes that it will not require all transmission providers to offer this service, we acknowledge that the introduction of this service on a voluntary basis may be appropriate in certain circumstances.

79. Although we are not proposing to require that transmission providers adopt contract demand service, we note that the commenters who support this service appear concerned principally with inequities in the pricing of network integration service. The Commission is addressing certain of these concerns elsewhere in the NOPR. For example, in this NOPR, we propose to modify our treatment of transmission credits for new transmission facilities and clarify that the transmission provider must satisfy the comparability requirement when including transmission facilities in its rate base for

pro forma

OATT purposes. We also address concerns regarding the linkage between how the transmission provider plans and

operates its system through proposed revisions to planning and ATC.

4. Functional Unbundling

80. When the Commission proposed the open access policy that culminated in Order No. 888, there was considerable debate about whether corporate unbundling (in which a public utility's transmission and generation assets would be placed in separate corporate entities) was necessary to ensure non-discriminatory open access transmission service. The Commission decided to mandate functional, rather than corporate, unbundling of transmission and generation services. In Order No. 888, 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.

Order No. 888 at 31,654.

81. 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 have operated under the functional unbundling approach.

Comments

82. Retention of Order No. 888's functional unbundling approach is supported by a number of commenters. For example, the LPPC states that vertical integration remains a viable business model for serving customers reliably and at economic rates. LG&E posits that, absent a proven and real level of abuse, major structural changes are unwarranted. NARUC argues that the issue of whether there should be structural separation of generation from transmission is best left to the states. NPPD alleges that mandatory vertical unbundling would do more harm than good by threatening the continued economic operation of those utilities that continue to provide bundled service to their retail native load customers. The North Carolina Commission does not believe the evidence in that state supports the imposition of structural remedies.

83. Some commenters, however, continue to urge the Commission to impose structural separation. National Grid contends that the best way to eliminate the possibility of undue discrimination is to separate the ownership and operation of the transmission system from interests in the market. Calpine urges the Commission to structurally separate the merchant function that is engaged in selling power for resale from those who control access to transfer capability and service, not just those who operate the transmission system. TAPS argues that structural solutions are preferable to behavioral rules.

84. Many commenters favoring structural separation urge the Commission to impose an independent transmission coordinator requirement. These commenters would have transmission providers employ an independent entity to administer their OATTs, performing such functions as maintaining the utility's OASIS, granting or denying service requests, reviewing system impact and facilities study results, and overseeing decisions with respect to line ratings, transmission outages and generation dispatch.

Other commenters oppose the imposition of a potentially costly new layer of bureaucracy, at least on a generic basis.

E.g.,

Arkansas Commission, Calpine, Constellation, EPSA, and PPL.

E.g.,

APPA, NRECA, and TAPS.

Discussion

85. We propose to preserve the functional unbundling approach adopted by Order No. 888. For public utilities that kept transmission and generation assets in the same corporate entity, the Commission imposed strict Standards of Conduct that required separation of the utilities' transmission system operations and wholesale marketing functions.

These Standards of Conduct were replaced by a broader set of rules adopted in Order No. 2004.

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.

Order No. 889 at 31,595.

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 28371 (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),

appeal docketed sub nom.

National Gas Fuel Supply Corporation

FERC,

No. 04-1183 (D.C. Cir. June 9, 2004), codified at 18 CFR Part 358 (2005).

86. The Commission aggressively enforces the Standards of Conduct. 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 function and information restrictions in Order No. 2004 are implemented.

87. The Commission has resolved a number of complaints related to the Standards of Conduct and the accompanying OASIS posting requirements.

In Order No. 888, the Commission noted that the possibility of filing a complaint under FPA section 206 is an additional safeguard if a public utility seeks to circumvent the functional unbundling requirement. The Commission's Enforcement Hotline likewise is available to customers that do not wish to file a formal complaint.

See Aquila Energy Marketing Corp.

Niagara Mohawk Power Corp.,

87 FERC ¶ 61,328 (1999)(finding that off-OASIS communicagtion between utilty and its marketing affiliate led to preferential treatment of the affiliate).

88. In addition, one of the criticisms of the functional unbundling requirement is that Order No. 888 leaves vertically integrated utilities with too much discretion in applying the OATT and gives them an incentive to use this discretion to their advantage. We agree that the existing

pro forma

OATT provides too much discretion in certain important areas. It is for this reason—as explained elsewhere in the NOPR—that we are proposing to require greater clarity and transparency in several areas of OATT administration. We believe these reforms will limit the discretion of transmission providers and make any remaining attempts to discriminate much easier to detect.

89. We believe that this increased clarity and transparency, when coupled with the Standards of Conduct and a rigorous enforcement program, will ensure that the functional unbundling requirement will serve its original purpose. As a result, just as the Commission concluded in Order No.

888 that more intrusive and costly corporate unbundling was not necessary, the Commission again concludes that there is no need to impose a corporate or structural unbundling requirement at this time. We believe that the

pro forma

OATT, if properly clarified and enforced, will enable us to eliminate the opportunity for undue discrimination in the provision of transmission service.

90. For the same reasons, we also decline to mandate an independent transmission coordinator for all transmission providers. We have concluded that such entities may be appropriate in certain circumstances and we support voluntary efforts to rely on them.

We do not agree, however, that there is sufficient basis for requiring them as a generic remedy for undue discrimination.

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 clarificaiton

, 111 FERC ¶ 61,222 (2005),

order conditionally approving filing,

115 FERC ¶ 61,095 (2006).

91. Our proposal to retain the functional unbundling approach of Order No. 888 does not suggest, however, a lack of support for structural changes that may be undertaken on a voluntary basis by each region, such as transmission-only companies, RTOs, or other reforms. We continue to support such efforts as potentially providing significant benefits in several areas, including, but not limited to, increased infrastructure investment and addressing regional issues such as cost recovery, pancaked rates, loop flow, and congestion management. At this time, we believe such efforts are best developed on a voluntary basis.

C. Applicability of the Proposed Rule

1. Public Utility Transmission Providers

92. Pursuant to its authority under FPA sections 205 and 206, the Commission in Order No. 888 required all public utilities that owned, controlled, or operated facilities used for transmitting electric energy in interstate commerce to file open access transmission tariffs that contained minimum terms and conditions of non-discriminatory service. The Commission recognized, however, that there may be circumstances in which a public utility believes that the

pro forma

OATT does not provide sufficient flexibility.

In addition, the Commission acknowledged that a public utility might be willing to offer superior non-rate terms and conditions. As a result, the Commission allowed a transmission provider to justify variations from the non-price terms and conditions of the

pro forma

OATT under two circumstances. First, certain provisions of Order No. 888 specifically allowed public utilities to use alternatives that were justified by “regional differences.” When submitting those provisions, public utilities were permitted to follow regional practices when doing so was “reasonable, generally accepted in the region, and consistently adhered to by the transmission provider,”

as long as the utilities identified the regional practices in their compliance filings. Second, in subsequent FPA section 205 proceedings, public utilities were permitted to propose changes to any

pro forma

OATT provision that were “consistent with or superior to” the terms of the

pro forma

OATT.

Order No. 888 at 31,770.

Id.

93. In the NOI, the Commission expressed the preliminary view that reforms to the

pro forma

OATT and public utilities' OATTs appear necessary and sought comment on how best to accomplish that. In particular, the Commission sought comment on whether reforms to Order No. 888 should be applied to all public utility transmission providers, including those that are approved ISOs, RTOs, or independent transmission coordinators.

Comments

94. Independent system operators such as MISO, CAISO, and ISO New England submit that many of the concerns raised by the Commission in the NOI already have successfully been addressed by the operation of ISOs and RTOs. Similarly, EEI argues that many of the issues addressed in the NOI are not applicable to RTOs and ISOs because RTOs and ISOs are independent of all market participants and therefore are presumed to not engage in undue discrimination or preferential treatment. PJM argues that, because of its independence, the transparency of its procedures, and the progress achieved in developing effective financial and non-financial congestion management tools, PJM structurally addresses the continuing concerns of the Commission regarding persistent undue discrimination and preference in the industry.

95. EPSA states that it may not be necessary to apply all aspects of the new OATT to ISOs or RTOs. However, rather than delineating either each term that would not apply to an RTO or how such terms might be modified in an RTO tariff, EPSA recommends that the Commission require RTOs, ISOs, and independent transmission coordinators to submit compliance filings upon issuance of the new

pro forma

OATT but allow them to propose waivers of the new requirements based upon appropriate justification.

96. EEI argues that, to the extent that the Commission requires RTOs and ISOs to amend their open access transmission tariffs, the Commission should establish flexible procedures that provide the RTOs and ISOs the right to customize their OATTs consistent with their independent status.

97. Other commenters argue that reforms to existing OATTs should be applied to all market entities, including ISOs, RTOs and independent transmission coordinators.

LPPC states that there is little reason for the Commission to be more deferential in considering deviations from the

pro forma

OATT proposed by RTOs or ISOs than it is with respect to investor-owned utilities.

E.g.,

Calpine, LPPC, NRECA, and Santa Clara.

Discussion

98. The Commission proposes to apply the final rule to all public utility transmission providers. The Commission proposes to require all such transmission providers to submit FPA section 206 compliance filings, within 60 days following publication of the final rule in the

Federal Register

, that contain the non-rate terms and conditions set forth in the final rule. We note 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. We seek comment on an appropriate time period in which to require the submission of these attachments.

99. As we did in Order No. 888, after making their FPA section 206 compliance filings, we propose to allow transmission providers to 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.

100. With respect to an RTO or ISO, we recognize that such an entity may already have tariff terms and conditions that are superior to the

pro forma

OATT. Thus, we propose to require RTO and ISO transmission providers to submit FPA section 206 compliance filings, within 90 days following 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. Similarly, after making their FPA section 206 compliance filings, we propose to allow RTOs and ISOs 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.

101. We generally note that the purpose of this NOPR is not to redesign approved, fully-functional RTO or ISO markets. We do not expect that substantial changes to those markets would be required as a result of this NOPR. For example, some RTOs or ISOs have eliminated point-to-point service for internal transactions in favor of a form of more flexible network service. Thus, we would not expect our reforms to ATC to require changes to the way in which such RTOs or ISOs assess whether capacity for traditional network or point-to-point service is available within their footprints. However, there may be elements of the proposed reforms that are superior to what currently exists in some RTOs or ISOs,

e.g.

, transparency, data exchange or planning, which would require the RTO or ISO to conform to the

pro forma

OATT.

2. Non-Public Utility Transmission Providers/Reciprocity

102. 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.

100

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.

100

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.

103. 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 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.

101

See

Order No. 888-A at 30,285-86.

104. In EPAct 2005, Congress authorized, but did not require, the Commission to order non-public utilities (or “unregulated transmitting utilities”) to provide transmission services. Section 1231 of EPAct 2005 establishes a new section 211A in Part II of the FPA, which 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 it can reasonably be read to permit the Commission to order the non-public utility to provide “open access” transmission service,

i.e.

, service to all eligible customers.

105. In the NOI, we sought comment on whether the Commission should exercise the authority granted to it by Congress in FPA section 211A. If so, we asked whether the Commission should impose this requirement on all unregulated transmitting utilities through a rulemaking proceeding, or whether the Commission should instead apply this new law on a case-by-case basis, through complaints, motions seeking enforcement, or sua sponte action by the Commission.

Comments

106. Several non-public utility commenters suggest that the Commission should not use the authority granted by FPA section 211A in a generic fashion.

102

They argue that there is no need to require unregulated transmitting utilities either to file open access tariffs with the Commission or to require that they adhere to a

pro forma

OATT. APPA asserts that while the Commission may act under FPA section 211A to remedy particular issues that are brought to its attention with respect to lack of access, there is simply no basis for concluding that there currently exists a general problem regarding the provision of transmission service by non-public utility transmission providers which calls for a generic solution. LPPC proposes a regime of voluntary compliance with a set of proposed comparability guidelines.

102

E.g.,

Chelan, Douglas, LDWP, LPPC, Northwest Unregulated TUs, Public Power Council, Rural Utilities Service, Sacramento, Santee Cooper, Snohomish, Tacoma, TAPS, and TVA.

107. Many commenters argue that the Commission should exercise its authority granted by FPA section 211A by establishing a rule to require unregulated transmitting utilities to provide service under the

pro forma

OATT.

103

EEI believes a rulemaking is essential to ensure that all utilities required to provide open access under FPA section 211A do so and that the Commission should, at a minimum, require unregulated transmitting utilities to file and provide service under the

pro forma

OATT. EPSA and Sempra Global suggest an approach that would not require an unregulated transmitting utility to file an OATT with the Commission until it receives a request for service.

103

E.g.,

Ameren, California Commission, Calpine, Cinergy, EEI, First Energy, Memphis Light, Nevada Companies, Northwest IPPs, PNM-TNMP, PPL, Progress Energy, and Suez Energy NA.

108. EEI argues that the Commission should use FPA section 211A to require unregulated transmitting utilities to provide all services they are capable of providing, not just those that they provide to themselves. In contrast, APPA states that FPA section 211A establishes a “comparability” standard applicable to non-public utility transmission owner rates, and a “comparable and not unduly discriminatory or preferential” standard for terms and conditions. APPA further states that FPA section 211A requires that unregulated transmitting utilities provide transmission service to others at

rates, terms and conditions “comparable to those under which the unregulated transmitting utility provides transmission services to itself,” rather than transmission services that they are “reasonably capable of providing.”

109. The Canadian Electricity Association believes that the adoption of FPA section 211A requires the Commission to revisit the reciprocity requirement of Order No. 888. According to the Canadian Electricity Association, EPAct 2005 lowered the bar for domestic unregulated transmitting utilities, requiring them only to provide service under terms and conditions that are comparable to those they apply to themselves, rather than terms and conditions that substantially conform or are superior to those in the

pro forma

OATT. If the Commission does not make corresponding changes to the manner in which the reciprocity requirement currently applies to Canadian entities, it argues, the result will be domestic unregulated transmitting utilities being treated better than Canadian entities, which would violate the national treatment obligations under the North American Free Trade Agreement. The Canadian Electricity Association argues that the reciprocity requirement under Order No. 888 must be modified to require that a Canadian entity that seeks open access in the U.S. must provide access to its own transmission system under terms and conditions that are comparable to those the Canadian entity is subject to itself.

Discussion

110. The Commission proposes 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, which are described above: 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.

104

For non-public utilities that choose to use the safe harbor tariff, we note that its provisions must be substantially conforming or superior to the new

pro forma

OATT. A non-public utility that already has a safe harbor tariff may 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.

111. We do not propose a generic rule to implement the new FPA section 211A.

105

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.

106

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. Further, as we indicate below, we expect unregulated transmission providers to participate in the open and transparent regional planning processes that we propose to order and note that, if there are complaints about such participation, we will address them on a case-by-case basis.

105

We note that LPPC has committed to voluntary compliance with a set of guidelines for the provision of comparable service under FPA section 211A.

106

We do, however, propose to amend our regulations to make clear that an applicant in a 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 a FPA section 211A order should be granted.

See

revised 18 CFR 35.28(e)(1)(ii).

112. We disagree with the position of the Canadian Electricity Association. EPAct 2005 did not repeal the reciprocity obligation in Order No. 888. Rather, it granted a new avenue of authority to the Commission to order comparable transmission service from non-public utilities. We are proposing not to exercise this new authority at this time. Rather, we are proposing to retain our reciprocity policy, which was adopted pursuant to sections 205 and 206 of the FPA. By maintaining the same reciprocity requirement for domestic, non-public utilities as for foreign utilities doing business in the United States, the Commission will ensure that foreign entities will continue to be treated no less favorably than domestic, non-public utilities.

V. Proposed Modifications of the OATT

A. Consistency and Transparency of ATC Calculations

113. In Order Nos. 888 and 889, the Commission directed transmission providers to offer their unused transfer capability to the market and to post the amount of ATC

107

on OASIS. At the time those orders were issued, the Commission noted that formal methods did not exist for calculating ATC, but recognized that there were industry efforts underway to develop a consistent, industry-wide method for calculating it.

108

Instead of prescribing a specific methodology for calculating ATC in Order Nos. 888 and 889, the Commission encouraged the industry efforts and required that transmission providers base their ATC calculation methodologies on current industry practices, standards and criteria.

109

In addition, the Commission directed transmission providers to include a description of their ATC calculation methodologies in Attachment C of their tariffs.

107

See supra

note 7.

108

Order No. 889 at 31,607.

109

Id.

114. Ten years later, however, although some progress has been made, the industry still has not developed a consistent, industry-wide methodology for evaluating ATC. In the intervening years, the industry, working through the North American Electric Reliability Council (NERC), has adopted a general definition of ATC, which establishes a basic methodology for evaluating ATC. NERC also has developed a set of guiding principles for calculating ATC and has encouraged further consistency of ATC calculation methodologies on a regional level. NERC defines ATC as the transfer capability remaining on the system for further commercial activity over and above already committed uses. This value is determined by deducting existing transmission commitments (ETC)

110

(including transmission reservations, network and retail customer service), capacity benefit margin (CBM),

111

and transmission reliability margin (TRM)

112

from total

transfer capability (TTC).

113

However, NERC's calculation methodology is not prescriptive; it establishes a framework for evaluating ATC, which leaves open to each transmission provider's interpretation and discretion the specific algorithm, data inputs and assumptions needed to assess ATC.

114

Consequently, transmission providers have developed numerous ways to evaluate ATC using their own algorithms, data and modeling assumptions.

115

110

NERC does not have a formal definition or standard methodology for ETC.

111

NERC defines CBM as the amount of firm transmission transfer capability preserved by the transmission provider for load-serving entities, whose loads are located on that transmission service provider's system, to enable access by the load-serving entities to generation from interconnected systems to meet generation reliability requirements. Preservation of CBM for a load-serving entity allows that entity to reduce its installed generating capacity below that which may otherwise have been necessary without interconnections to meet its generation reliability requirements. The transmission transfer capability preserved as CBM is intended to be used by the load-serving entities only in times of emergency generation deficiencies.

See

North American Electric Reliability Council,

Glossary of Terms Used in Reliability Standards,

(Effective April 1, 2005), (NERC Glossary) available at

ftp://www.nerc.com/pub/sys/all_updl/standards/sar/Glossary_07Feb06.pdf.

112

NERC defines TRM as the amount of transmission transfer capability necessary to provide reasonable assurance that the interconnected transmission network will be secure. TRM accounts for the inherent uncertainty in system conditions and the need for operating flexibility to ensure reliable system operation as system conditions change.

See

NERC Glossary.

113

NERC defines TTC as the amount of electric power that can be moved or transferred reliably from one area to another area of the interconnected transmission systems by way of all transmission lines (or paths) between those areas under specified system conditions.

See

NERC Glossary.

114

See

NERC,

Available Transfer Capability Definitions and Determination: A Framework for Determining Available Transfer Capabilities of the Interconnected Transmission Networks for a Commercially Viable Electricity Market

(1996) available at

ftp://www.nerc.com/pub/sys/all_updl/docs/pubs/atcfinal.pdf.

115

See supra

note 59.

115. Although transmission providers across the Nation have developed various methodologies, in general, there are two main approaches to calculating ATC used in the industry. The first is the contract path approach, which is more commonly used by transmission providers in the Western Electricity Coordinating Council (WECC) region.

116

The contract path methodology derives ATC directly from predetermined TTC, ETC, CBM, and TRM values derived consistent with contract path transmission rights. The second method is the flowgate

117

approach, which is used more widely in the Eastern Interconnection.

118

The flowgate methodology is based on physical power flow models. The flowgate calculation first determines AFC and then converts AFC into ATC and derives TTC for the OASIS posting. The differences between the two approaches may not result in significantly different ATC values if consistent data inputs and industry acceptable modeling assumptions are used. Without a consistent and transparent approach to evaluating ATC, transmission customers will remain wary when service is denied and transmission providers will be the subject of suspicion and heightened scrutiny, especially given the increasingly congested state of the Nation's electric grid.

116

See, e.g.

, Determination of Available Transfer Capability within the Western Interconnection (June 2001), available at

http://www.wecc.biz/documents/library/procedures/ATC-apprdec01.pdf.

117

A flowgate is a designated point on the transmission system used in the modeling of power flows. While NERC currently does not have a formal definition for AFC, the power industry commonly defines AFC as a measure of the capability remaining on a flowgate for future uses, after considering the effect of prior sales. Mathematically, the industry measures AFC as AFC = Flowgate rating—[(base case flow)—(impacts of existing reservations)]—Flowgate

CBM

—Flowgate

TRM

118

See, e.g.

, PJM Manual 2: Transmission Service Request (April 14, 2005), available at:

http://www.pjm.com/contributions/pjm-manuals/pdf/m02v08.pdf

Consistency

116. Generally, transmission providers calculate ATC by creating a base model of their system using a set of data inputs and assumptions, which are determined by the transmission provider. The transmission provider uses the model to perform various computer simulations of the operations of its system to determine the levels of transfer capability available on the system. The types of data and assumptions used in the models include, for example, facility ratings, the operating status of facilities, and generation dispatch, which might be supported by history, transmission plans, or the judgment of the transmission provider. For example, a transmission provider could use its judgment to reduce a facility rating or model certain facilities as out of service, which would have the effect of calculating a lower TTC value. A transmission provider also may use generation dispatch assumptions to limit transfer capability that otherwise would have been available to independent generators, thereby favoring the transmission provider's own generation. A transmission provider usually assumes that designated network resources are dispatched in economic merit order. However, a transmission provider has the discretion to decide which of the generators that are not designated network resources will be modeled in-service. Assumptions like these influence the loading on transmission lines in the model and heavily influence the resulting ATC. Having standards in place that address the calculation of ATC components, data inputs, and modeling assumptions would help ensure non-discriminatory treatment by limiting a transmission provider's ability to use discretion to the disadvantage of competitors and the market.

117. As noted above, NERC does not have a formal definition of ETC. Without clear criteria for what should be included in a transmission provider's ETC, a transmission customer might not know whether ETC is being over- or underestimated. For example, a transmission provider could set aside more capacity for native load than is realistically expected to occur. This could happen if a transmission provider includes in ETC excess capacity for a load-serving entity (such as capacity to meet generation reserve requirements) but then also has a CBM component in its calculation of ATC that includes the same capacity. A transmission provider also could overestimate its ETC by double-counting the same transmission reservations in its ATC calculation. For example, this could happen if a transmission provider fails to replace a transmission reservation with the associated real-time schedule, and as a result does not release non-firm ATC. A consistent process for calculating ETC will limit the subjectivity of the transmission provider's decisions and provide a more uniform method for estimating ETC.

118. With respect to the modeling of a particular transaction, when information concerning the source is unknown, a transmission provider has the discretion to select which generator(s) will be used as a source.

119

There are no standards for how that modeling should be done and, consequently, a transmission provider could model a source using single or multiple generators by increasing (scaling up) their output. In general, modeling a transaction using multiple generators as a source is less conservative for the transmission system than modeling a transaction using a single generator as a source. Modeling a transaction using multiple generators as a source typically results in a higher ATC value. Conversely, when a transmission provider models a transaction using a single generator as a source, this can result in a lower ATC value depending on the location of the generator. Modeling of contingency outages used for calculating ATC is another area within the discretion of the transmission provider. Although the type of contingency, such as single contingency (n-1), is determined by governing reliability criteria,

120

the transmission provider determines which specific contingencies will be used for the ATC calculation. The common industry practice is to consider the loss

of each transmission facility at voltage 100 kV and above. However, the lack of standards governing transfer analysis allows the transmission provider to use its discretion to monitor outages only of facilities at 230 kV and above, ignoring the limitations that may exist for the loss of the facilities at lower voltages, such as 115 kV or 138 kV. Consequently, ATC values may vary substantially, with ATC being much higher when monitoring contingencies of facilities at 230 kV and above, and much lower while monitoring the loss of all facilities (voltage 100 kV and above).

119

Transmission providers do not always know the generator used as a source of energy provided under contracts that qualify as designated resources; the only requirement is that the network customer have an executed contract that commits it to purchase noninterruptible power.

See Wisconsin Public Power Inc.

Wisconsin Public Service Corp.,

84 FERC ¶ 61,120 at 61,650-51 (1998).

120

Standard TPL-001-0, Table I. Transmission System Standards—Normal and Emergency Conditions, NERC Reliability Standards for the Bulk Electric Systems of North America (effective April 1, 2005).

119. Furthermore, in calculating ATC, transmission providers set aside a portion of transfer capability in the form of CBM and/or TRM to provide for adequate generation reserves and account for uncertainties or contingencies, respectively. Generally, CBM is the amount of firm transmission transfer capability held back by the transmission provider so that load-serving entities, whose loads are located on the transmission provider's system, can access remote generation reserve from interconnected systems in times of emergency generation deficiencies. Some believe it is necessary for transmission providers to set aside a portion of their TTC to ensure that their ties with other systems remain available for this purpose. There are no consistent industry-wide standards, however, for determining how much transfer capability should be set aside as CBM. There is also no common approach to whether the capacity is set aside for Native Load Customers, as defined in section 1.19 of the

pro forma

OATT, for retail load, or for all load-serving entities. The lack of consistent criteria and clarity with regard to the entity on whose behalf CBM has been set aside has the potential to result in the transmission provider setting aside capacity that it might not otherwise need to, thus increasing costs for native load customers and blocking other firm uses of the transmission system.

121

The Commission has explained that the

pro forma

OATT requires both transmission customers and transmission providers using the transmission system to serve network load (including bundled retail native load) to designate their resources and loads so that the transmission customers and transmission providers would have no incentive to designate network resources above their needs and, in so doing, tie up valuable transmission capacity.

Aquila Power Corp.

Entergy Services, Inc.

, 90 FERC ¶ 61,260,

reh'g denied

, 92 FERC ¶ 61,064 (2000),

reh'g denied

, 101 FERC ¶ 61,328 (2002),

aff'd sub nom. Entergy Services, Inc.

FERC

, 375 F.3d 1204 (D.C. Cir. 2004) (

Aquila

120. Similarly, TRM is the amount of transmission transfer capability reserved by the transmission provider to ensure that the transmission network will be secure under a reasonable range of uncertainties in system conditions. Because TRM and CBM are both maintained in part for the loss of generators, there exists the possibility of double-counting reliability margins for the loss of the same generation.

121. Moreover, a transmission provider also can use more conservative inputs and assumptions for calculating ATC and performing system impact studies (that tend to minimize ATC) when it is assessing a long-term transmission service request, but use less conservative inputs and assumptions (that tend to maximize ATC) when it is performing system planning for retail native load. This creates the potential for undue discrimination where a transmission provider uses one set of data and assumptions to evaluate third party requests and another set of data and assumptions to plan its system to serve its own load.

Data Exchange Among Transmission Providers

122. The lack of a consistent ATC calculation methodology combined with limited coordination between transmission providers can result not only in inefficiencies but unjust and unreasonable terms and conditions of service, especially for a customer seeking contiguous transmission service from multiple transmission providers. The ATC values posted by a transmission provider are often inaccurate for reasons beyond the control of the transmission provider. A transmission provider may post ATC values in good faith and attempt to provide transmission service based on these values only to discover later that the transfer capability that it thought was available no longer exists due to decisions made by other transmission providers that it did not know about at the time it made its calculations. Accurate ATC calculation requires reliable and timely information about such things as load, generation dispatch, facility outages, and transactions on neighboring systems. Transmission providers also may apply differing assumptions and criteria to ATC calculations, which may produce wide variations in posted ATC values for the same transmission paths. All of these considerations make it difficult for an individual transmission provider that operates one part of an interconnected grid to calculate ATC accurately.

123. This lack of communication and coordination between transmission providers of ATC data can also affect reliability. As discussed above, a transmission provider could grant transmission service without being aware of the real impact that service may have on an adjacent transmission provider's system, thus degrading the reliability of the interconnected system. Inaccurate ATC values can cause overselling of transfer capability, which can lead to curtailments or transmission loading relief (TLR) actions to avoid exceeding thermal, voltage, and/or stability limits.

Transparency

124. As discussed, the lack of a consistent, industry-wide methodology for assessing ATC makes undue discrimination difficult to detect. This problem is further exacerbated by a lack of transparency surrounding the calculation methodology used by transmission providers. Although the Commission requires transmission providers to file their methodologies for calculating ATC in their tariffs, transmission providers often have responded by filing very general narrative descriptions of their calculation methodologies (often simply referring to the general NERC definition)

122

without further specification of the mathematical algorithm, data inputs, and modeling assumptions used to perform the calculation.

122

See, e.g.

, the OATTs of Aquila, Inc., Southern, and Tucson Electric Power Company.

125. Other than the description of the ATC methodology provided in transmission providers' tariffs, third parties often have limited access to information concerning the specific algorithms, data and assumptions used by transmission providers to evaluate their ATC, which makes it difficult to verify or challenge a transmission provider's ATC calculations. The Commission requires each transmission provider to calculate and post ATC and TTC values for each posted path.

123

Transmission providers also are required to make publicly available, on request, all data used to calculate ATC and TTC for any constrained path.

124

Additionally, transmission providers are required to make publicly available, on request, system planning studies or

network impact studies performed for customers to determine network impacts. Furthermore, subsequent to Order Nos. 888 and 889, the Commission required each transmission provider to post (and update) the CBM value for each path for which it already posts ATC and TTC, as well as a narrative explanation of its CBM practices.

125

123

See

18 CFR 37.6 (b) (2005). A posted path is defined as any control area to control area interconnection; any path for which service is denied, curtailed or interrupted for more than 24 hours in the past 12 months; and any path for which a customer requests to have ATC or TTC posted.

Id.

37.6 (b)(1)(i).

124

Id.

37.6 (b)(2)(ii). A constrained posted path is defined as any posted path having an ATC value less than or equal to 25 percent of TTC at any time during the preceding 168 hours or for which ATC has been calculated to be less than or equal to 25 percent of TTC for any period during the current hour or the next 168 hours.

Id.

37.6 (b)(1)(ii).

125

Capacity Benefit Margin in Computing Available Transmission Capacity

, 88 FERC ¶ 61,099 (1999) (CBM Order).

126. Yet, despite these requirements, third parties often are unable to gain access to sufficient information surrounding a transmission provider's ATC calculation methodology. As a preliminary matter, we note that while the OASIS requirements regarding the availability of information related to ATC and TTC calculations are still in effect, they have been affected by restrictions that have been placed upon the availability of critical energy infrastructure information (CEII) in the interest of national security.

126

Therefore, system planning and network impact studies and models typically are no longer available on a transmission provider's OASIS. Furthermore, transmission customers are often unable to access other information such as load flow base cases and associated files. In sum, although existing Commission regulations are intended to provide a certain level of transparency, this transparency is undermined by a number of factors, including the absence of detailed descriptions of the data inputs, assumptions, and criteria used to determine the data included in ATC calculations, as well as the inability of customers to access certain of this data because of, among other reasons, security concerns.

126

See Critical Energy Infrastructure Information,

Order No. 630, 68 FR 9857 (Mar. 3, 2003), FERC Stats. & Regs. ¶ 31,140 (2003),

order on reh'g,

Order No. 630-A, 68 FR 46456 (Aug. 6, 2003), FERC Stats. & Regs. ¶ 31,147 (2003),

order on clarification,

Order No. 662, 70 FR 37031 (Jun. 28, 2005), FERC Stats. & Regs. ¶ 31,189 (2005);