[Federal Register Volume 61, Number 92 (Friday, May 10, 1996)]
[Rules and Regulations]
[Pages 21540-21736]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-10694]




[[Page 21539]]


_______________________________________________________________________

Part II





Department of Energy





_______________________________________________________________________



Federal Energy Regulatory Commission



_______________________________________________________________________



18 CFR Parts 35, 37 and 385



Electric Utilities (Federal Power Act); Promoting Wholesale Competition 
Through Open Access Non-Discriminatory Transmission Services by Public 
Utilities; Recovery of Stranded Costs by Public Utilities and 
Transmitting Utilities; Final Rules and Proposed Rule

Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and 
Regulations

[[Page 21540]]



DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Parts 35 and 385

[Docket Nos. RM95-8-000 and RM94-7-001; Order No. 888]


Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery of 
Stranded Costs by Public Utilities and Transmitting Utilities

    Issued April 24, 1996.

AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Final rule.

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SUMMARY: The Federal Energy Regulatory Commission (Commission) is 
issuing a Final Rule requiring all public utilities that own, control 
or operate facilities used for transmitting electric energy in 
interstate commerce to have on file open access non-discriminatory 
transmission tariffs that contain minimum terms and conditions of non-
discriminatory service. The Final Rule also permits public utilities 
and transmitting utilities to seek recovery of legitimate, prudent and 
verifiable stranded costs associated with providing open access and 
Federal Power Act section 211 transmission services. The Commission's 
goal is to remove impediments to competition in the wholesale bulk 
power marketplace and to bring more efficient, lower cost power to the 
Nation's electricity consumers.

EFFECTIVE DATE: This Final Rule will become effective on July 9, 1996.

FOR FURTHER INFORMATION CONTACT:

David D. Withnell (Legal Information--Docket No. RM95-8-000), Office of 
the General Counsel, Federal Energy Regulatory Commission, 888 First 
Street NE., Washington, DC 20426, (202) 208-2063
Deborah B. Leahy (Legal Information--Docket No. RM94-7-001), Office of 
the General Counsel, Federal Energy Regulatory Commission, 888 First 
Street NE., Washington, DC 20426, (202) 208-2039
Michael A. Coleman (Technical Information), Office of Electric Power 
Regulation, Federal Energy Regulatory Commission, 888 First Street NE., 
Washington, DC 20426, (202) 208-1236.

SUPPLEMENTARY INFORMATION: In addition to publishing the full text of 
this document in the Federal Register, the Commission also provides all 
interested persons an opportunity to inspect or copy the contents of 
this document during normal business hours in the Public Reference Room 
at 888 First Street, NE., Washington, DC 20426.
    The Commission Issuance Posting System (CIPS), an electronic 
bulletin board service, provides access to the texts of formal 
documents issued by the Commission. CIPS is available at no charge to 
the user and may be accessed using a personal computer with a modem by 
dialing 202-208-1397 if dialing locally, or 1-800-856-3920 if dialing 
long distance. CIPS is also available through the Fed World system (by 
modem or Internet). To access CIPS, set your communications software to 
19200, 14400, 12000, 9600, 7200, 4800, 2400, or 1200 bps, full duplex, 
no parity, 8 data bits and 1 stop bit. The full text of this order will 
be available on CIPS indefinitely in ASCII and WordPerfect 5.1 format. 
The complete text on diskette in Wordperfect format may also be 
purchased from the Commission's copy contractor, La Dorn Systems 
Corporation, also located in the Public Reference Room at 888 First 
Street NE., Washington, DC 20426.

Table of Contents

I. Introduction/Summary
II. Public Reporting Burden
III. Background
IV. Discussion
    A. Scope of the Rule
    1. Introduction
    2. Functional Unbundling
    3. Market-based Rates
    4. Merger Policy
    5. Contract Reform
    6. Flow-based Contracting and Pricing
    B. Legal Authority
    1. Bases for Legal Authority
    2. Response to Commenters Opposing our Legal Authority
    C. Comparability
    1. Eligibility to Receive Non-discriminatory Open Access 
Transmission
    2. Service that Must be Provided by Transmission Provider
    3. Who Must Provide Non-discriminatory Open Access Transmission
    4. Reservation of Transmission Capacity by Transmission 
Customers
    5. Reservation of Transmission Capacity for Future Use by 
Utility
    6. Capacity Reassignment
    7. Information Provided to Transmission Customers
    8. Consequences of Functional Unbundling
    D. Ancillary Services
    1. Definitions and Descriptions
    2. Obligations of Transmission Providers and Transmission 
Customers with Respect to Ancillary Services
    3. Unbundling and Bundling Ancillary Services
    4. Reassignment of Ancillary Services
    5. Pricing of Ancillary Services
    6. Accounting for Ancillary Services
    E. Real-Time Information Networks
    F. Coordination Arrangements: Power Pools, Public Utility 
Holding Companies, Bilateral Coordination Arrangements, and 
Independent System Operators
    1. Tight Power Pools
    2. Loose Pools
    3. Public Utility Holding Companies
    4. Bilateral Coordination Arrangements
    G. Pro Forma Tariff
    1. Tariff Provisions That Affect The Pricing Mechanism
    2. Priority for Obtaining Service
    3. Curtailment Provisions
    4. Specific Tariff Provisions
    H. Implementation
    I. Federal and State Jurisdiction: Transmission/Local 
Distribution
    J. Stranded Costs
    1. Justification for Allowing Recovery of Stranded Costs
    2. Cajun Electric Power Cooperative, Inc. v. FERC
    3. Responsibility for Wholesale Stranded Costs (Whether to Adopt 
Direct Assignment to Departing Customers)
    4. Recovery of Stranded Costs Associated with New Wholesale 
Requirements Contracts
    5. Recovery of Stranded Costs Associated with Existing Wholesale 
Requirements Contracts
    6. Recovery of Stranded Costs Caused by Retail-Turned-Wholesale 
Customers
    7. Recovery of Stranded Costs Caused by Retail Wheeling
    8. Evidentiary Demonstration Necessary--Reasonable Expectation 
Standard
    9. Calculation of Recoverable Stranded Costs
    10. Stranded Costs in the Context of Voluntary Restructuring
    11. Accounting Treatment for Stranded Costs
    12. Definitions, Application, and Summary
    K. Other
    1. Information Reporting Requirements for Public Utilities
    2. Small Utilities
    3. Regional Transmission Groups
    4. Pacific Northwest
    5. Power Marketing Agencies
    6. Tennessee Valley Authority
    7. Hydroelectric Power
    8. Residential Customers
V. Environmental Statement
VI. Regulatory Flexibility Act Certification
VII. Information Collection Statement
VIII. Effective Date
    Regulatory Text
    Appendices (These Appendices will not appear in the Code of 
Federal Regulations)
    A. List of Section 211 Applications
    B. List of Commenters in Docket Nos. RM95-8-000 and RM94-7-001
    C. Allegations of Public Utilities Exercising Transmission 
Dominance
    D. Pro Forma Open Access Transmission Tariff
    E. List of Group 1 Public Utilities
    F. List of Group 2 Public Utilities
    G. Legal Analysis of Commission Jurisdiction Over the Rates, 
Terms and Conditions of Unbundled Retail Transmission In Interstate 
Commerce
    H. U.S. NO<INF>X Emissions

[[Page 21541]]

    Statement of Commissioner Hoecker
    Statement of Commissioner Massey

I. Introduction/Summary

    Today the Commission issues three final, interrelated rules 
designed to remove impediments to competition in the wholesale bulk 
power marketplace and to bring more efficient, lower cost power to the 
Nation's electricity consumers.<SUP>1 The legal and policy cornerstone 
of these rules is to remedy undue discrimination in access to the 
monopoly owned transmission wires that control whether and to whom 
electricity can be transported in interstate commerce. A second 
critical aspect of the rules is to address recovery of the transition 
costs of moving from a monopoly-regulated regime to one in which all 
sellers can compete on a fair basis and in which electricity is more 
competitively priced.
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    \1\ These rules are the rules on open access and stranded costs 
in the above dockets (FERC Stats. & Regs. para. 31,036), and an 
accompanying rule on Open Access Same-Time Information System and 
Standards of Conduct (OASIS Final Rule) (FERC Stats. & Regs. para. 
31,037) being issued contemporaneously. The Commission also is 
issuing contemporaneously a notice of proposed rulemaking on 
capacity reservation open access transmission tariffs in Docket No. 
RM96-11-000, FERC Stats. & Regs. para. 32,517. These final rules and 
proposed rule are being published concurrently in the Federal 
Register.
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    In the year since the proposed rules were issued,<SUP>2 the pace of 
competitive changes in the electric utility industry has accelerated. 
By March of last year, 38 public utilities had filed wholesale open 
access transmission tariffs with the Commission. Today, prodded by such 
competitive changes and encouraged by our proposed rules, 106 of the 
approximately 166 public utilities that own, control, or operate <SUP>3 
transmission facilities used in interstate commerce have filed some 
form of wholesale open access tariff. In addition, since the time the 
proposed rules were issued, numerous state regulatory commissions have 
adopted or are actively evaluating retail customer choice programs or 
other utility restructuring alternatives. These events have been 
spurred by continuing pressures in the marketplace for changes in the 
way electricity is bought, sold, and transported. Increasingly, 
customers are demanding the benefits of competition in the growing 
electricity commodity market.
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    \2\ On March 29, 1995, the Commission issued two notices of 
proposed rulemaking concerning open access transmission and stranded 
cost recovery. Promoting Wholesale Competition Through Open-Access 
Non-Discriminatory Transmission Service by Public Utilities and 
Recovery of Stranded Costs by Public Utilities and Transmitting 
Utilities, Notice of Proposed Rulemaking and Supplemental Notice of 
Proposed Rulemaking, 60 FR 17662 (April 7, 1995), FERC Stats. & 
Regs. para. 32,514 (1995). On December 13, 1995, the Commission 
issued a notice of proposed rulemaking on information systems. Real-
Time Information Networks and Standards of Conduct, Notice of 
Proposed Rulemaking, 60 FR 66182 (December 21, 1995), FERC Stats. & 
Regs. para. 32,516 (1995).
    \3\ The Commission's notice of proposed rulemaking in the above 
dockets proposed to apply the proposed requirements to public 
utilities that own and/or control facilities used for the 
transmission of electric energy in interstate commerce. ``Own and/or 
control'' is intended to include public utilities that ``operate'' 
facilities used for the transmission of electric energy in 
interstate commerce. However, we have modified the Final Rule 
regulatory text to remove any ambiguity.
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    The Commission estimates the potential quantitative benefits from 
the Final Rule will be approximately $3.8 to $5.4 billion per year of 
cost savings, in addition to the non-quantifiable benefits that include 
better use of existing assets and institutions, new market mechanisms, 
technical innovation, and less rate distortion. The continuing 
competitive changes in the industry and the prospect of these benefits 
to customers make it imperative that this Commission take the necessary 
steps within its jurisdiction to ensure that all wholesale buyers and 
sellers of electric energy can obtain non-discriminatory transmission 
access, that the transition to competition is orderly and fair, and 
that the integrity and reliability of our electricity infrastructure is 
maintained.
    In this Rule, the Commission seeks to remedy both existing and 
future undue discrimination in the industry and realize the significant 
customer benefits that will come with open access. Indeed, it is our 
statutory obligation under sections 205 and 206 of the Federal Power 
Act (FPA) to remedy undue discrimination.
    To do so, we must eliminate the remaining patchwork of closed and 
open jurisdictional transmission systems and ensure that all these 
systems, including those that already provide some form of open access, 
cannot use monopoly power over transmission to unduly discriminate 
against others. If we do not take this step now, the result will be 
benefits to some customers at the expense of others. We have learned 
from our experience in the natural gas area the importance of 
addressing competitive transition issues early and with as much 
certainty to market participants as possible.
    Accordingly, in this proceeding and in the accompanying proceeding 
on OASIS, the Commission, pursuant to its authorities under sections 
205 and 206 of the FPA:
    <bullet> Requires all public utilities that own, control or operate 
facilities used for transmitting electric energy in interstate commerce
    <bullet> To file open access non-discriminatory transmission 
tariffs that contain minimum terms and conditions of non-discriminatory 
service;
    <bullet> To take transmission service (including ancillary 
services) for their own new wholesale sales and purchases of electric 
energy under the open access tariffs;
    <bullet> To develop and maintain a same-time information system 
that will give existing and potential transmission users the same 
access to transmission information that the public utility enjoys, and 
further requires public utilities to separate transmission from 
generation marketing functions and communications;
    <bullet> Clarifies Federal/state jurisdiction over transmission in 
interstate commerce and local distribution and provides for deference 
to certain state recommendations; and
    <bullet> Permits public utilities and transmitting utilities to 
seek recovery of legitimate, prudent and verifiable stranded costs 
associated with providing open access and FPA section 211 transmission 
services.

Open Access

    The Final Rule requires public utilities to file a single open 
access tariff that offers both network, load-based service and point-
to-point, contract-based service. The Rule contains a pro forma tariff 
that reflects modifications to the NOPR's proposed terms and conditions 
and also permits variations for regional practices. All public 
utilities subject to the Rule, including those that already have 
tariffs on file, will be required to make section 206 compliance 
filings to meet the new pro forma tariff non-price minimum terms and 
conditions of non-discriminatory transmission. Utilities may propose 
their own rates in a section 205 compliance filing.
    The Rule provides that public utilities may seek a waiver of some 
or all of the requirements of the Final Rule. In addition, non-public 
utilities may seek a waiver of the tariff reciprocity provisions.
    The Final Rule does not generically abrogate existing requirements 
contracts, but will permit customers and public utilities to seek 
modification, or termination, of certain existing requirements 
contracts on a case-by-case basis. As to coordination arrangements and 
contracts, the Rule finds that these arrangements and contracts may 
need to be modified to remove unduly discriminatory transmission access 
and/or pricing provisions. Such arrangements and agreements include 
power pool agreements, public utility

[[Page 21542]]

holding company agreements, and certain bilateral coordination 
agreements. The Rule provides guidance and timelines for modifying 
unduly discriminatory coordination arrangements and contracts, and 
specifies when the members of such arrangements must begin to conduct 
trade with each other using the same open access tariff offered to 
others. The Rule also provides guidance regarding the formation of 
independent system operators (ISOs).
    The Rule does not require any form of corporate restructuring, but 
will accommodate voluntary restructuring that is consistent with the 
Rule's open access and comparability policies.
    As discussed in the NOPR, not all owners or controllers of 
interstate transmission facilities are subject to the Commission's 
jurisdiction under sections 205 and 206 of the FPA and therefore are 
not subject to this Rule's open access requirements. Therefore, the 
Final Rule retains the proposed reciprocity provision in the pro forma 
tariff. Without such a provision, non-open access utilities could take 
advantage of the competitive opportunities of open access, while at the 
same time offering inferior access, or no access at all, over their own 
facilities. Thus, open access utilities would be unfairly burdened. We 
note that some non-jurisdictional utilities have expressed an interest 
in a mechanism for obtaining a Commission determination that their 
transmission tariffs satisfy the reciprocity provisions in the pro 
forma tariffs, and we provide such a mechanism in the Rule.
    The Final Rule does not generically provide for market-based 
generation rates. Although the Rule codifies the Commission's prior 
decision that there is no generation dominance in new generating 
capacity, intervenors in cases may raise generation dominance issues 
related to new capacity. In addition, to obtain market-based rates for 
existing generation, we will continue to require public utilities to 
show, on a case-by-case basis, that there is no generation dominance in 
existing capacity. Further, in all market-based rate cases, we will 
continue to look at whether an applicant and its affiliates could erect 
other barriers to entry and whether there may be problems due to 
affiliate abuse or reciprocal dealing.
    Finally, contemporaneously with this Rule the Commission issues an 
NOPR on capacity reservation tariffs as an alternative, and perhaps 
superior, means of remedying undue discrimination.

Transmission/Local Distribution

    The Rule clarifies the Commission's interpretation of the Federal/
state jurisdictional boundaries over transmission and local 
distribution. While we reaffirm our conclusion that this Commission has 
exclusive jurisdiction over the rates, terms, and conditions of 
unbundled retail transmission in interstate commerce by public 
utilities, we nevertheless recognize the very legitimate concerns of 
state regulatory authorities as they contemplate direct retail access 
or other state restructuring programs. Accordingly, we specify 
circumstances under which we will give deference to state 
recommendations. Although jurisdictional boundaries may shift as a 
result of restructuring programs in wholesale and retail markets, we do 
not believe this will change fundamental state regulatory authorities, 
including authority to regulate the vast majority of generation asset 
costs, the siting of generation and transmission facilities, and 
decisions regarding retail service territories. We intend to be 
respectful of state objectives so long as they do not balkanize 
interstate transmission of power or conflict with our interstate open 
access policies.

Stranded Costs

    With regard to stranded costs, the Final Rule adopts the 
Commission's supplemental proposal. It will permit utilities to seek 
extra-contractual recovery of stranded costs associated with a limited 
set of existing (executed on or before July 11, 1994) wholesale 
requirements contracts and provides that the Commission will be the 
primary forum for utilities to seek recovery of stranded costs 
associated with retail-turned-wholesale transmission customers. It also 
will allow utilities to seek recovery of stranded costs caused by 
retail wheeling only in circumstances in which the state regulatory 
authority does not have authority to address retail stranded costs at 
the time the retail wheeling is required. The Rule retains the revenues 
lost approach for calculating stranded costs and provides a formula for 
calculating such costs.

Environmental Issues

    The Commission has prepared a Final Environmental Impact Statement 
(FEIS) evaluating the possible environmental consequences of changes in 
the bulk power marketplace expected to occur as a result of the open 
access requirements of this Final Rule. The FEIS focuses, as do most 
commenters, on possible increases in emissions of nitrogen oxides 
(NO<INF>X) from certain fossil-fuel fired generators, which could 
affect air quality in the producing region and in areas to which these 
emissions may be carried.
    In response to comments on the Draft EIS, the Commission performed 
numerous additional studies. The FEIS finds that the relative future 
competitiveness of coal and natural gas generation is the key variable 
affecting the impact of the Final Rule. If competitive conditions favor 
natural gas, the Rule is likely to lead to environmental benefits. Both 
EPA and the Commission staff believe this projected scenario is the 
more likely one. If competitive conditions favor coal, the Rule may 
lead to small negative environmental impacts. However, even using the 
most extreme, unlikely assumptions about the future of the industry, 
the negative consequences are not likely to occur until after the turn 
of the century. Because the impacts will remain modest at least until 
2010, there is no need for an interim mitigation program. In addition, 
even if the data showed more significant negative consequences 
requiring mitigation, the Commission does not have the statutory 
authority under the Federal Power Act or the expertise to address this 
possible far-term problem. The Commission believes, however, that there 
is time for federal and state air quality authorities to address any 
potential adverse impact as part of a comprehensive NO<INF>X regulatory 
program under the Clean Air Act.<SUP>4
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    \4\ 42 U.S.C. 7401, et seq.
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    Despite our conclusions regarding the lack of environmental impacts 
expected to result from the Rule, the Commission has examined a wide 
variety of proposals for mitigating possible adverse effects. We share 
the view of most commenters that the preferred approach for mitigating 
increased NO<INF>X emissions generally is a NO<INF>X cap and trading 
regulatory program comparable to that developed by Congress to address 
sulfur dioxide emissions in the Clean Air Act Amendments of 1990.<SUP>5 
The Commission has examined various means of establishing such a 
program, including use of existing federal authorities under the Clean 
Air Act, cooperative efforts by state and federal air quality 
regulators, and development of a new emissions regulatory program 
administered by the Commission under the Federal Power Act. The 
Commission has concluded that a NO<INF>X regulatory program could best 
be developed and administered under the Clean Air Act, in cooperation 
with interested states, and offers to lend Commission support

[[Page 21543]]

to that effort should it become necessary.
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    \5\ 42 U.S.C.A. 7651b-e.
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Conclusion

    The Commission believes that the Final Rule will remedy undue 
discrimination in transmission services in interstate commerce and 
provide an orderly and fair transition to competitive bulk power 
markets.

II. Public Reporting Burden

    The Open Access Final Rule and the Stranded Cost Final Rule specify 
filing requirements to be followed by public utilities that own, 
control or operate transmission facilities in interstate commerce in 
making non-discriminatory open access tariff filings and filings to 
recover legitimate, prudent and verifiable stranded costs. The 
information collection requirements of the final rules are attributable 
to FERC-516 ``Electric Rate Filings.'' The current total annual 
reporting burden for FERC-516 is 828,300 hours.

A. Docket No. RM95-8-000 (Open Access Final Rule)

    The Open Access Final Rule requires public utilities filing non-
discriminatory open access tariffs to provide certain information to 
the Commission. The Commission estimated that the public reporting 
burden for the information collection would average 300 hours per 
response. This estimate included time for reviewing the requirements of 
the Commission's regulations, searching existing data sources, 
gathering and maintaining the necessary data, completing and reviewing 
the collection of information, and filing the revised information. No 
comments on the burden estimate were received. Because the Final Rule 
adopts essentially the same information requirements that are contained 
in the proposed rule, we believe that the average filing burden is same 
for the Final Rule.
    In the proposed rule, the Commission noted that there are 
approximately 328 public utilities, including marketers and wholesale 
generation entities. We initially estimated that 137 public utilities 
own, control or operate facilities used for the transmission of 
electric energy in interstate commerce, and would be subject to the 
filing requirements of the proposed rule. Upon further review, the 
Commission believes that approximately 166 public utilities will 
respond to the information collection. Accordingly, the public 
reporting burden is estimated to be 49,800 hours.

B. Docket No. RM94-7-001 (Stranded Cost Final Rule)

    In the supplemental notice of proposed rulemaking, the Commission 
estimated that the information requirements of the proposed rule would 
not differ substantially from those contained in the initial proposed 
rule. In that notice, the Commission estimated that the public 
reporting burden for the information requirements contained in the 
proposed rule would be 50 hours per response with 10 responses 
annually. No comments on this filing burden were received. The 
information requirements adopted in the Stranded Cost Final Rule are 
not substantially different from those in the proposed rule. Therefore, 
the Commission concludes that there will be no additional public filing 
burden associated with the Stranded Cost Final Rule.

III. Background

    In the NOPR, we set out a detailed statement of the events leading 
up to this rulemaking. We repeat that background here, updated to 
reflect what has happened since March 1995, and discuss why it is 
necessary to undertake regulatory reform in the electric industry at 
this time. We do so to provide the necessary backdrop to our action in 
adopting this Rule.

A. Structure of the Electric Industry at Enactment of Federal Power Act

    The Federal Power Act was enacted in an age of mostly 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 (delivered electric 
energy) 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 (IOUs) 
connected to each utility's transmission system. Each system covered 
limited service areas. This structure of separate systems arose 
naturally due primarily to the cost and technological limitations on 
the distance over which electricity could be transmitted.
    Through much of the 1960s, utilities were able to avoid price 
increases, but still achieve increased profits, because of substantial 
increases in scale economies, technological improvements, and only 
moderate increases in input prices.<SUP>6 Thus, there was no pressure 
on regulatory commissions to use regulation to affect the structure of 
the industry.<SUP>7
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    \6\ Paul L. Joskow, Inflation and Environmental Concern: 
Structural Change in the Process of Public Utility Regulation, 17 J. 
Law & Econ. 291, 312 (1974); see also Charles F. Phillips, Jr., The 
Regulation of Public Utilities 11 (1988).
    \7\ See Joskow, supra at 312; see also Phillips, supra at 12.
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B. Significant Changes in the Electric Industry

    In the late 1960s and throughout the 1970s, a number of significant 
events occurred in the electric industry that changed the perceptions 
of utilities and began a shift to a more competitive marketplace for 
wholesale power.<SUP>8 This was the beginning of periods of rapid 
inflation, higher nominal interest rates, and higher electricity 
rates.<SUP>9 During this time, consumers became concerned about higher 
electricity rates and questioned any price increases filed by 
utilities.<SUP>10
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    \8\ See Joskow, supra at 312; see also Phillips, supra at 12-13.
    \9\ See Joskow, supra at 312-13; see also Phillips, supra at 13. 
The Arab oil embargo resulted in significantly higher oil prices 
through the 1970s. See Richard J. Pierce, Jr., The Regulatory 
Treatment of Mistakes in Retrospect: Canceled Plants and Excess 
Capacity, 132 U. Pa. L. Rev. 497, 501 (1984).
    \10\ See Joskow, supra at 313; see also Phillips, supra at 13.
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    During this same time frame, the construction of nuclear and other 
capital-intensive baseload facilities--actively encouraged by federal 
and some state governments--contributed to the continuing cost 
increases and uncertainties in the industry.<SUP>11 These investments 
were made based on the assumptions that there would be steady increases 
in the demand for electricity and continued large increases in the 
price of oil.<SUP>12 However, due to conservation and economic 
downturns, the expected demand increases did not materialize. Load 
growth virtually disappeared in some areas, and many utilities 
unexpectedly found themselves with excess capacity.<SUP>13 In addition, 
by the 1980s, the oil cartel collapsed, with a resulting glut of low-
priced oil.<SUP>14 At the same time, inflation substantially increased 
the costs of these large

[[Page 21544]]

baseload generating plants.<SUP>15 Surging interest rates further 
increased the cost of the capital needed to finance and capitalize 
these projects and completion schedules were significantly extended by, 
in part, more stringent safety and environmental requirements.<SUP>16
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    \11\ See generally Jersey Central Power & Light Company v. FERC, 
810 F.2d 1168, 1171 (D.C. Cir. 1987).
    \12\ Id.
    \13\ See Pierce, supra at 503. By 1983, the Department of Energy 
had estimated that the sunk costs for canceled nuclear plants alone 
amounted to $10 billion. Id. at 498.
    \14\ Id.
    \15\ See Bernard S. Black & Richard J. Pierce, Jr., The Choice 
Between Markets and Central Planning in Regulating the U.S. 
Electricity Industry, 93 Col. L. Rev. 1339, 1346 (1993) (``Actual 
costs of nuclear power plants vastly exceeded estimates, sometimes 
by as much as 1000%.'').
    \16\ See Phillips, supra at 13. Fossil fuel-fired plants became 
subject to increased regulation as a result of the Clean Air Act of 
1970, and its 1977 amendments. 42 U.S.C. 7401-7642. In 1971, nuclear 
plant licensing became subject to the environmental impact statement 
requirements of the National Environmental Policy Act of 1969. 42 
U.S.C. 4332. Following the 1979 accident at the Three Mile Island 
nuclear plant, nuclear plants also became subject to additional 
safety regulations, resulting in higher costs. See Energy 
Information Administration, The Changing Structure of the Electric 
Power Industry 1970-1991 (March 1993) 35. Between 1976 and 1980, 
most states and many localities instituted laws governing power 
plant siting.
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    As a result, expensive large baseload plants for which there was 
little or no demand, came onto the market or were in the process of 
being constructed. Accordingly, between 1970 and 1985, average 
residential electricity prices more than tripled in nominal terms, and 
increased by 25% after adjusting for general inflation.<SUP>17 
Moreover, average electricity prices for industrial customers more than 
quadrupled in nominal terms over the same period and increased 86% 
after adjusting for inflation.<SUP>18 The rapidly increasing rates for 
electric power during this period, together with the opportunities 
provided by the Public Utility Regulatory Policies Act of 1978 (PURPA) 
(discussed infra), also prompted some industrial customers to bypass 
utilities by constructing their own generation facilities. This further 
exacerbated rate increases for remaining customers--primarily 
residential and commercial customers.
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    \17\ Based on retail prices reported in Energy Information 
Administration (EIA), Monthly Energy Review, January 1995, Table 9.9 
(Prices adjusted for inflation using the GDP Deflator (1987 = 100)).
    \18\ Id.
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    Consumers responded to these ``rate shocks'' by exerting pressure 
on regulatory bodies to investigate the prudence of management 
decisions to build generating plants, especially when construction 
resulted in cost overruns, excess capacity, or both. Between 1985 and 
1992, writeoffs of nuclear power plants totalled $22.4 billion.<SUP>19 
These writeoffs significantly reduced the earnings of the affected 
utilities.<SUP>20 Delays in obtaining rate increases to reflect the 
effects of inflation further reduced investor returns. Thus, many 
utilities became reluctant to commit capital to long-term construction 
decisions involving large scale generating plants.<SUP>21
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    \19\ See Black & Pierce, supra at 1346 (These writeoffs were 
``about 17% of the book value of total 1992 utility investment.'').
    \20\ Id.
    \21\ Id. (``The high perceived risk of future disallowances 
reversed utilities' incentives to overinvest, and made utilities 
extremely reluctant to build new power plants.'').
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    In addition to economic changes in the industry, significant 
technological changes in both generation and transmission have occurred 
since 1935. Through the 1960s, bigger was cheaper in the generation 
sector and the industry was able to capitalize on economies of scale to 
produce power at lower per-unit costs from larger and larger 
plants.<SUP>22 As a result, large utility companies that could finance 
and manage construction projects of larger scale had a price advantage 
over smaller utility companies and customers who might otherwise have 
considered building their own generating units. Scale economies 
encouraged power generation by large vertically-integrated utility 
companies that also transmitted and distributed power. Beginning in the 
1970s, however, additional economies of scale in generation were no 
longer being achieved.<SUP>23 A significant factor was that larger 
generation units were found to need relatively greater maintenance and 
experience longer downtimes.<SUP>24 The electric industry faced the 
situation ``where the price of each incremental unit of electric power 
exceeded the average cost.'' <SUP>25 Bigger was no longer better.
---------------------------------------------------------------------------

    \22\ See Preston Michie, Billing Credits for Conservation, 
Renewable, and Other Electric Power Resources: an Alternative to 
Marginal-Cost-Based Power Rates in the Pacific Northwest, 13 
Environmental Law 963, 964-65 (1983).
    \23\ Id. at 965.
    \24\ Energy Information Administration, The Changing Structure 
of the Electric Power Industry 1970-1991 (March 1993) 37 (``As 
larger units were constructed, however, utilities discovered that 
downtime was as much as 5 times greater for units larger than 600 
megawatts than for units in the 100-megawatt range.'')
    \25\ Id.; see also George A. Perrault, Downsizing Generation: 
Utility Plans for the 1990s, Pub. Util. Fort. 15-16 (Sept. 27, 1990) 
(``The large base-load generating units that form the backbone of 
utility systems are almost totally absent from capacity plans for 
the 1990s.'').
---------------------------------------------------------------------------

    Further dictating against larger generation units were advances in 
technologies that allowed scale economies to be exploited by smaller 
size units, thereby allowing smaller new plants to be brought on line 
at costs below those of the large plants of the 1970s and earlier. Such 
new technologies include combined cycle units and conventional steam 
units that use circulating fluidized bed boilers.<SUP>26
---------------------------------------------------------------------------

    \26\ ``From 1982 through 1991, the average capacity of 
fluidized-bed units increased rapidly to 72 megawatts for 4 units in 
1991. The average capacity for the 19 units planned to begin 
operating in 1992 through 1995 increases to 83 megawatts.'' Energy 
Information Administration, The Changing Structure of the Electric 
Power Industry 1970-1991 (March 1993) 38.
---------------------------------------------------------------------------

    The combined cycle generating plants generally use natural gas as 
their primary fuel. This technology has been made possible by the 
development of more efficient gas turbines, shorter construction lead 
times, lower capital costs, increased reliability, and relatively 
minimal environmental impacts.<SUP>27 Similarly, the circulating 
fluidized bed combustion boilers, fueled by coal and other conventional 
fuels, provide a more efficient and less polluting resource.
---------------------------------------------------------------------------

    \27\ See Charles E. Bayless, Less is More: Why Gas Turbines Will 
Transform Electric Utilities, Pub. Util. Fort. (Dec. 1, 1994) 21.
---------------------------------------------------------------------------

    Today, ``the optimum size (of generation plants) has shifted from 
(more than 500 MW) (10-year lead time) to smaller units (one-year lead 
time) (in the 50- to 150-MW range).'' <SUP>28 Indeed, smaller and more 
efficient gas-fired combined-cycle generation facilities can produce 
power on the grid at a cost ranging from 5 cents per kWh to less than 3 
cents per kWh.<SUP>29 This is significantly less than the costs for 
large plants constructed and installed by utilities over the last 
decade, which were typically in the range of 4 to 7 cents per kWh for 
coal plants and 9 to 15 cents for nuclear plants.<SUP>30 Significant 
changes have also occurred in the transmission sector of the industry. 
Technological advances in transmission have made possible the economic 
transmission of electric power over long distances at higher 
voltages.<SUP>31 This has

[[Page 21545]]

made it technically feasible for utilities with lower cost generation 
sources to reach previously isolated systems where customers had been 
captive to higher cost generation. In addition, the nature and 
magnitude of coordination transactions <SUP>32 have changed 
dramatically since enactment of the FPA, allowing increased coordinated 
operations and reduced reserve margins. Substantial amounts of 
electricity now move between regions, as well as between utilities in 
the same region. Physically isolated systems have become a thing of the 
past.
---------------------------------------------------------------------------

    \28\ Id. at 24. See also Wallace E. Brand, Is Bigger Better? 
Market Power in Bulk Power Supply: From FDR to NOPR, Pub. Util. 
Fort. (Feb. 15, 1996) 23 at 25 (while the optimal baseload unit size 
is about 500 MW for coal-fired steam turbines, the optimal size for 
gas fired combined-cycle units is about 150 to 200 MW).
    \29\ FERC staff calculations based in part on combined-cycle 
plant cost data reported in 1994 FERC Form No. 1 for a sample of 
units placed in service during 1990-94. Costs vary with regional 
fuel and construction costs, among other reasons.
    \30\ Coal and Nuclear plant cost data reported in 1994 FERC Form 
No. 1 and the EIA report, Electric Plant Cost and Power Production 
Expenses 1991, 1993 DOE/EIA-0455(91), for plants placed in service 
during 1986-94; see also The 1994 Electric Executives' Forum, Bakke 
(President and CEO of the AES Corporation), Pub. Util. Fort. (June 
1, 1994) 45 (``New generation can be built at about 3 cents per 
kilowatt-hour (U.S. average). Old generation costs about twice that 
* * *'').
    \31\ See Black & Pierce, supra at 1345 (In the late 1960s and 
1970s, improved transmission efficiency and development of regional 
transmission networks ``made it possible to build power plants up to 
1000 miles from power users.'').
    \32\ Coordination transactions are voluntary sales or exchanges 
of specialized electricity services that allow buyers to realize 
cost savings or reliability gains that are not attainable if they 
rely solely on their own resources. For sellers, these transactions 
provide opportunities to earn additional revenue, and to lower 
customer rates, from capacity that is temporarily excess to native 
load capacity requirements.
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C. The Public Utility Regulatory Policies Act and the Growth of 
Competition

    In enacting PURPA,<SUP>33 Congress recognized that the rising costs 
and decreasing efficiencies of utility-owned generating facilities were 
increasing rates and harming the economy as a whole.<SUP>34 To lessen 
dependence on expensive foreign oil, avoid repetition of the 1977 
natural gas shortage, and control consumer costs, Congress sought to 
encourage electric utilities to conserve oil and natural gas.<SUP>35 In 
particular, Congress sanctioned the development of alternative 
generation sources designated as ``qualifying facilities'' (QFs) as a 
means of reducing the demand for traditional fossil fuels.<SUP>36 PURPA 
required utilities to purchase power from QFs at a price not to exceed 
the utility's avoided costs and to sell backup power to QFs.<SUP>37
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    \33\ Pub. L. No. 95-617, 92 Stat. 3117 (codified in U.S.C. 
sections 15, 16, 26, 30, 42, and 43).
    \34\ See generally FERC v. Mississippi, 456 U.S. 742, 745-46 
(1982).
    \35\ The Power Plant and Industrial Fuel Use Act of 1978. Pub. 
L. No. 95-617, 92 Stat. 3117 (codified in U.S.C. sections 15, 16, 
26, 30, 42, and 43).
    \36\ QFs include certain cogenerators and small power producers. 
PURPA also added sections 210, 211, and 212 to the FPA, providing 
the Commission with authority to approve applications for 
interconnections and, in limited circumstances, wheeling. However, 
under section 211, as enacted in PURPA, the Commission could approve 
an application for wheeling only if it found, inter alia, that the 
order ``would reasonably preserve existing competitive 
relationships.'' Because of this and other limitations in sections 
211 and 212 as originally enacted, the provision was virtually 
ineffective. Only one section 211 order was ever issued pursuant to 
the original provision, and it was pursuant to a settlement. See 
Public Service Company of Oklahoma, 38 FERC para. 61,050 (1987). As 
discussed infra, section 211 was subsequently revised by the Energy 
Policy Act of 1992.
    \37\ 456 U.S. at 750. Congress recognized that encouragement was 
needed in part because utilities had been reluctant to purchase 
electric power from, and sell power to, nonutility generators. Id. 
at 750-51.
---------------------------------------------------------------------------

    PURPA specifically set forth limitations on who, and what, could 
qualify as QFs. In addition to technological and size criteria, PURPA 
set limits on who could own QFs.<SUP>38 Notwithstanding these 
limitations, QFs proliferated. In 1989, there were 576 QF facilities. 
By 1993, there were more than 1,200 such facilities.<SUP>39 For the 
same time period, installed QF capacity increased from 27,429 megawatts 
to 47,774 megawatts.<SUP>40 The rapid expansion and performance of the 
QF industry demonstrated that traditional, vertically integrated public 
utilities need not be the only sources of reliable power.
---------------------------------------------------------------------------

    \38\ For example, PURPA provided that a cogeneration facility or 
small power production facility could not be owned by a person 
primarily engaged in the generation or sale of electric power (other 
than from cogeneration or small power production facilities). See 16 
U.S.C.
    \39\ Energy Information Administration, Electric Power Annual 
1993 (December 1994) 124 (Table 77).
    \40\ Id. EIA data for 1989 through 1991 was for facilities of 5 
megawatts or more and for 1992 and 1993 was for facilities of 1 
megawatt or more. A comparison with Table 74 on page 121 for the 
years 1992 and 1993 reveals that this mixing of data bases is likely 
of minimal effect.
---------------------------------------------------------------------------

    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. QFs were limited to 
cogenerators and small power producers.<SUP>41
---------------------------------------------------------------------------

    \41\ Generally, the law has imposed an 80 MW cap on small power 
producers. A limited exception enacted in 1990 permitted small power 
facilities that could exceed 80 MW and still qualify as QFs under 
PURPA. This exception was limited to certain solar, wind, waste, and 
geothermal small power production facilities and only covered 
applications for certification of facilities as qualifying small 
power production facilities that were submitted no later than 
December 31, 1994 and for which construction commences no later than 
December 31, 1999. See Solar, Wind, Waste, and Geothermal Power 
Production Incentives Act of 1990, Pub. L. No. 101-575, 104 Stat. 
2834 (1990), amended, Pub. L. No. 102-46, 105 Stat. 249 (1991).
---------------------------------------------------------------------------

    However, other non-traditional power producers who could not meet 
the QF criteria began to build new capacity to compete in bulk power 
markets, without such PURPA benefits as the mandatory purchase 
requirements. These producers, known as independent power producers 
(IPPs), were predominantly single-asset generation companies that did 
not own any transmission or distribution facilities. While traditional 
utilities were generally reluctant at that time to invest in new 
generating facilities under cost of service regulation, utilities 
increasingly became interested in participating in this new generation 
sector. They organized affiliated power producers (APPs), with assets 
not included in utility rate base, and sought to sell power in their 
own service territories and the territories of other utilities. At the 
same time, power marketers arose. These entities--owning no 
transmission or generation--buy and sell power.<SUP>42
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    \42\ The first power marketer in the electric industry was 
Citizens Energy Corporation. See Citizens Energy Corporation, 35 
FERC para. 61,198 (1986). Power marketers take title to electric 
energy. Power brokers, on the other hand, do not take title and are 
limited to a matchmaking role.
---------------------------------------------------------------------------

    There were two major impediments to the development of IPPs and 
APPs. First, the ownership restrictions of the Public Utility Holding 
Company Act (PUHCA) <SUP>43 severely inhibited these new entities from 
entering the generation business.<SUP>44 Second, these entities needed 
transmission service in order to compete in electricity markets.
---------------------------------------------------------------------------

    \43\ 15 U.S.C. 79 et seq.
    \44\ As discussed infra, Congress eventually provided a means to 
avoid the PUHCA restrictions by creating exempt wholesale generators 
(EWGs) in the Energy Policy Act.
---------------------------------------------------------------------------

    While the Commission had no authority to remove PUHCA 
restrictions,<SUP>45 it encouraged the development of IPPs and APPs, 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. From 1989 through 1993, 
facilities owned by IPPs and other non-traditional generators (other 
than QFs) increased from 249 to 634 and their installed capacity 
increased from 9,216 megawatts to 13,004 megawatts.<SUP>46 Indeed, 
``[i]n 1992, for the first time, generating capacity added by 
independent producers exceeded capacity added by utilities.'' <SUP>47
---------------------------------------------------------------------------

    \45\ The industry was successful to some extent in developing 
ownership structures that permitted such investment. See, e.g., 
Commonwealth Atlantic Limited Partnership, 51 FERC para. 61,368 at 
62,240 and n.20 (1990).
    \46\ Energy Information Administration, Electric Power Annual 
1993 (December 1994) 124 (Table 77).
    \47\ Black & Pierce, supra at 1349 n.25.
---------------------------------------------------------------------------

    Market-based rates helped to develop competitive bulk power 
markets. A generating utility allowed to sell its power at market-based 
rates could move more quickly to take advantage of short-term or even 
long-term market opportunities than those laboring under traditional 
cost-of-service tariffs, which entail procedural delays in achieving 
tariff approvals and changes.
    In approving these market-based rates, the Commission required, 
inter alia, that the seller and any of its affiliates lack market power 
or mitigate any market

[[Page 21546]]

power that they may have possessed.<SUP>48 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.<SUP>49 As we 
have previously explained:

    \48\ See, e.g., Ocean State Power, 44 FERC para. 61,261 (1988); 
Commonwealth Atlantic Limited Partnership, 51 FERC para. 61,368 
(1990); Citizens Power & Light Company, 48 FERC para. 61,210 (1989); 
Orange and Rockland Utilities, Inc., 42 FERC para. 61,012 (1988); 
Doswell Limited Partnership, 50 FERC para. 61,251 (1990) (Doswel); 
and Dartmouth Power Associates Limited Partnership, 53 FERC para. 
61,117 (1990).
    \49\ See, e.g., Doswell, 50 FERC at 61,757.
---------------------------------------------------------------------------

    The most likely route to market power in today's electric 
utility industry lies through ownership or control of transmission 
facilities. Usually, the source of market power is dominant or 
exclusive ownership of the facilities. However, market power also 
may be gained without ownership. Contracts can confer the same 
rights of control. Entities with contractual control over 
transmission facilities can withhold supply and extract monopoly 
prices just as effectively as those who control facilities through 
ownership.<SUP>50
---------------------------------------------------------------------------

    \50\ Citizens Power & Light Corporation, 48 FERC para. 61,210 at 
61,777 (1989) (emphasis in original); see also Utah Power & Light 
Company, PacifiCorp and PC/UP&L Merging Corporation, 45 FERC para. 
61,095 at 61,287-89 (1988), order on reh'g, 47 FERC para. 61,209, 
order on reh'g, 48 FERC para. 61,035 (1989), remanded in part sub 
nom. Environmental Action, Inc. v. FERC, 939 F.2d 1057 (D.C. Cir. 
1991), order on remand, 57 FERC para. 61,363 (1991).
---------------------------------------------------------------------------

    As entry into wholesale power generation markets increased, the 
ability of customers to gain access to the transmission services 
necessary to reach competing suppliers became increasingly 
important.<SUP>51 In addition, beginning in the late 1980s, in order to 
mitigate their market power to meet Commission conditions, public 
utilities seeking Commission approval of mergers or consolidations 
under section 203 of the FPA or 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.<SUP>52 The Commission applied its market rate analysis 
to IOUs, as well as IPPs, APPs, and marketers, and allowed IOUs to sell 
at market-based rates only if they opened their transmission systems to 
competitors.<SUP>53 The Commission also approved proposed mergers on 
the condition that the merging companies remedy anticompetitive effects 
potentially caused by the merger by filing ``open access'' tariffs. 
These early ``open access'' tariffs required only that the companies 
provide point-to-point transmission services, which is a much narrower 
requirement than that being imposed in this Rule and did not require 
transmission owners to provide to others the same quality of service 
that they themselves enjoyed.
---------------------------------------------------------------------------

    \51\ In earlier years, a few customers were able to obtain 
access as a result of litigation, beginning with the Supreme Court's 
decision in Otter Tail Power Company v. United States, 410 U.S. 366 
(1973). Additionally, some customers gained access by virtue of 
Nuclear Regulatory Commission license conditions and voluntary 
preference power transmission arrangements associated with federal 
power marketing agencies. See, e.g., Consumers Power Company, 6 NRC 
887, 1036-44 (1977) and The Toledo Edison Company and Cleveland 
Electric Illuminating Company, 10 NRC 265, 327-34 (1979). See 
Florida Municipal Power Agency v. Florida Power and Light Company, 
839 F. Supp. 1563 (M.D. Fla. 1993). See also Electricity 
Transmission: Realities, Theory and Policy Alternatives, The 
Transmission Task Force Report to the Commission, October 1989, 197.
    \52\ See, e.g., Public Service Company of Colorado, 59 FERC 
para. 61,311 (1992), reh'g denied, 62 FERC para. 61,013 (1993); Utah 
Power & Light Company, et al., Opinion No. 318, 45 FERC para. 61,095 
(1988), order on reh'g, Opinion No. 318-A, 47 FERC para. 61,209 
(1989), order on reh'g, Opinion No. 318-B, 48 FERC para. 61,035 
(1989), aff'd in relevant part sub nom. Environmental Action Inc. v. 
FERC, 939 F.2d 1057 (D.C. Cir. 1991); Northeast Utilities Service 
Company (Public Service Company of New Hampshire), Opinion No. 364-
A, 58 FERC para. 61,070, reh'g denied, Opinion No. 364-B, 59 FERC 
para. 61,042, order granting motion to vacate and dismissing request 
for rehearing, 59 FERC para. 61,089 (1992), affirmed in relevant 
part sub nom. Northeast Utilities Service Company v. FERC, 993 F.2d 
937 (1st Cir. 1993).
    \53\ See, e.g., Public Service of Indiana, Inc., 51 FERC para. 
61,367 (1990), reh'g denied, 52 FERC para. 61,260 (1990), appeal 
dismissed sub nom. Northern Indiana Public Service Company v. FERC, 
954 F.2d 736 (D.C.Cir. 1992).
---------------------------------------------------------------------------

    Following PURPA, the economic and technological changes in the 
transmission and generation sectors helped give impetus to the many new 
entrants in the generating markets who 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 still favored their 
own generation if and when they provided transmission access to third 
parties, barriers continued to exist to cheaper, more efficient 
generation sources.

D. The Energy Policy Act

    In response to the competitive developments following PURPA, and 
the fact that PUHCA and lack of transmission access remained major 
barriers to new generators, Congress enacted Title VII of the Energy 
Policy Act of 1992 (Energy Policy Act).<SUP>54 A goal of the Energy 
Policy Act was to promote greater competition in bulk power markets by 
encouraging new generation entrants, known as exempt wholesale 
generators (EWGs), and by expanding the Commission's authority under 
sections 211 and 212 of the FPA to approve applications for 
transmission services.<SUP>55
---------------------------------------------------------------------------

    \54\ Pub. L. No. 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.
    \55\ See El Paso Electric Company and Central and South West 
Services Inc., 68 FERC para. 61,181 at 61,914 (1994) (CSW); see also 
Paul Kemezis, FERC's Competitive Muscle: The Comparability Standard, 
Electrical World 45 (Jan. 1995) (``In EPAct, Congress made it clear 
that the electric-power industry was to move toward a fully 
competitive market system, but left most of the implementation to 
FERC.'').
---------------------------------------------------------------------------

    An EWG is defined as

    Any person determined by the Federal Energy Regulatory 
Commission to be engaged directly, or indirectly through one or more 
affiliates as defined in [PUHCA] section 2(a)(11)(B), and 
exclusively in the business of owning or operating, or both owning 
and operating, all or part of one or more eligible facilities and 
selling electric energy at wholesale.<SUP>56
---------------------------------------------------------------------------

    \56\ 15 U.S.C. 79z-5a.
---------------------------------------------------------------------------

    If the Commission, upon an application, determines that a person is 
an EWG, that person will be exempt from PUHCA.<SUP>57 This provision 
removed a significant impediment to the development of IPPs and APPs by 
allowing them to develop projects as EWGs free from the strictures of 
PUHCA or the QF PURPA limitations.
---------------------------------------------------------------------------

    \57\ 15 U.S.C. 79z-5a(e).
---------------------------------------------------------------------------

    While sections 211 and 212, as enacted by PURPA, were intended to 
provide greater access to the transmission grid, the limitations placed 
on these sections made them unusable in virtually all 
circumstances.<SUP>58 However, as amended by the Energy Policy Act, 
these sections now give the Commission broader authority to order 
transmitting utilities to provide wholesale transmission services, upon 
application, to any electric utility, Federal power marketing agency, 
or any other person generating electric energy for sale for resale.
---------------------------------------------------------------------------

    \58\ See supra note 36.
---------------------------------------------------------------------------

    The Energy Policy Act also added section 213 to the FPA. Section 
213(a) requires a transmitting utility that does not agree to provide 
wholesale transmission service in accordance with a good faith request 
to provide a written explanation of its proposed rates, terms, and 
conditions and its analysis of any

[[Page 21547]]

physical or other constraints.<SUP>59 Section 213(b) required the 
Commission to enact a rule requiring transmitting utilities to submit 
annual information concerning potentially available transmission 
capacity and known constraints.<SUP>60
---------------------------------------------------------------------------

    \59\ See Policy Statement Regarding Good Faith Requests for 
Transmission Services and Responses by Transmitting Utilities Under 
Sections 211(a) and 213(a) of the Federal Power Act, as Amended and 
Added by the Energy Policy Act of 1992, 58 FR 38964 (July 21, 1993), 
FERC Stats. & Regs., Regulations Preambles para. 30,975 (1993) 
(Policy Statement Regarding Good Faith Requests for Transmission 
Services).
    \60\ See New Reporting Requirements Implementing Section 213(b) 
of the Federal Power Act and Supporting Expanded Regulatory 
Responsibilities Under the Energy Policy Act of 1992, and Conforming 
and Other Changes to Form No. FERC-714, 58 FR 52420 (October 8, 
1993), FERC Stats. & Regs., Regulations Preambles para. 30,980 
(Order No. 558), reh'g denied, Order No. 558-A, 65 FERC para. 61,324 
(1993), regulations modified, 59 FR 15333 (April 1, 1994), FERC 
Stats. & Regs., Regulations Preambles para. 30,993.
---------------------------------------------------------------------------

E. The Present Competitive Environment

    Following the Energy Policy Act, the Commission established rules: 
(1) For certain generators to obtain EWG status and thus an exemption 
from PUHCA; <SUP>61 and (2) that required transmission information 
availability. The Commission also pursued a number of initiatives aimed 
at fostering the development of more competitive bulk power markets, 
including aggressive implementation of section 211, a new look at undue 
discrimination under the FPA, easing of market entry for sellers of 
generation from new facilities, and initiation of a number of industry-
wide reforms. As stated by the Commission, in recognition of the 
Congressional goal in the Energy Policy Act of creating competitive 
bulk power markets:

    \61\ See Order No. 550, Filing Requirements and Ministerial 
Procedures for Persons Seeking Exempt Wholesale Generator Status, 58 
FR 8897 (February 18, 1993), FERC Stats. & Regs., Regulations 
Preambles para. 30,964, order on reh'g, Order No. 550-A, 58 FR 21250 
(April 20, 1993), FERC Stats. & Regs., Regulations Preambles para. 
30,969 (1993). As recognized by Congress and the Commission, 
availability of transmission information is critical in developing 
competitive markets. See supra notes 59 and 60. This opened the 
``black box'' of information that previously was available only to 
transmission owners.
---------------------------------------------------------------------------

Our goal is to facilitate the development of competitively priced 
generation supply options, and to ensure that wholesale purchasers of 
electric energy can reach alternative power suppliers and vice versa. 
<SUP>62
---------------------------------------------------------------------------

    \62\ See Recovery of Stranded Costs by Public Utilities and 
Transmitting Utilities, Notice of Proposed Rulemaking, 59 FR 35274 
(July 11, 1994), FERC Stats. & Regs., Proposed Regulations para. 
32,507 at 32,866 (Stranded Cost NOPR); American Electric Power 
Service Corporation, 67 FERC para. 61,168, clarified, 67 FERC para. 
61,317 (1994).
---------------------------------------------------------------------------

1. Use of Sections 211 and 212 to Obtain Transmission Access
    The Commission has aggressively implemented sections 211 and 212 of 
the FPA, as amended by the Energy Policy Act, in order to promote 
competitive markets.<SUP>63 When wheeling requests under sections 211 
and 212 have been made, the Commission has required wheeling in almost 
all of the requests it has processed. To date, the Commission has 
issued orders (proposed or final) requiring wheeling in 12 of the 14 
cases it has acted on.<SUP>64
---------------------------------------------------------------------------

    \63\ 16 U.S.C.A. 824j-824k (West 1985 and Supp. 1994).
    \64\ See, e.g., final orders issued in City of Bedford, 68 FERC 
para. 61,003 (1994), reh'g denied, 73 FERC para. 61,322 (1995); 
Florida Municipal Power Agency v. Florida Power & Light Company, 67 
FERC para. 61,167 (1994), order on reh'g, 74 FERC para. 61,006 
(1996); Minnesota Municipal Power Agency, 68 FERC para. 61,060 
(1994); and Tex-La Electric Cooperative of Texas, 69 FERC para. 
61,269 (1994); see also Appendix A.
---------------------------------------------------------------------------

    As a general matter, section 211 has permitted some inroads to be 
made by customers in obtaining transmission service from public 
utilities that historically have declined to provide access to their 
systems, or have offered service only on a discriminatory basis. Under 
section 211, the Commission has granted requests for the broader type 
of service that most utilities historically have refused to provide--
network service. Although transmission owners have provided limited 
amounts of unbundled point-to-point transmission service, third-party 
customers have not been able to obtain the flexibility of service that 
transmission owners enjoy.
    In Florida Municipal, a section 211 case, the Commission ordered 
``network,'' rather than the narrower ``point-to-point,'' 
service.<SUP>65 Network service permits the applicant to fully 
integrate load and resources on an instantaneous basis in a manner 
similar to the transmission owner's integration of its own load and 
resources. At the same time, the Commission made the generic finding 
that the availability of transmission service will enhance competition 
in the market for power supplies and lead to lower costs for consumers. 
The Commission explained that as long as the transmitting utility is 
fully and fairly compensated and there is no unreasonable impairment of 
reliability, transmission service is in the public interest.<SUP>66
---------------------------------------------------------------------------

    \65\ See Florida Municipal Power Agency v. Florida Power & Light 
Company, 65 FERC para. 61,125, reh'g dismissed, 65 FERC para. 61,372 
(1993), final order, 67 FERC para. 61,167 (1994), order on reh'g, 74 
FERC para. 61,006 (1996). The Commission has ``characterized point-
to-point service as involving designated points of entry into and 
exit from the transmitting utility's system, with a designated 
amount of transfer capability at each point.'' El Paso Electric 
Company v. Southwestern Public Service Company, 68 FERC para. 61,182 
at 61,926 n.9 (1994) (citing Entergy Services, Inc., 58 FERC para. 
61,234 at 61,768 (1993), reh'g dismissed, 68 FERC para. 61,399 
(1994)). Network service allows more flexibility by allowing a 
transmission customer to use the entire transmission network to 
provide generation service for specified resources and specified 
loads without having to pay multiple charges for each resource-load 
pairing.
    \66\ Florida Municipal, 67 FERC at 61,477.
---------------------------------------------------------------------------

    As discussed infra, based on the mounting competitive pressures in 
the industry and rapidly evolving markets, we have concluded that 
section 211 alone is not enough to eliminate undue discrimination. The 
comments received on the proposed rules, discussed in detail infra, 
confirm this conclusion. The significant time delays involved in filing 
an individual service request for bilateral service under section 211 
place the customer at a severe disadvantage compared to the 
transmission owner and can result in discriminatory treatment in the 
use of the transmission system. It is an inadequate procedural 
substitute for readily available service under a filed non-
discriminatory open access tariff. As the Commission noted in Hermiston 
Generating Company, ``[t]he ability to spend time and resources 
litigating the rates, terms and conditions of transmission access is 
not equivalent to an enforceable voluntary offer to provide comparable 
service under known rates, terms and conditions.'' <SUP>67
---------------------------------------------------------------------------

    \67\ 69 FERC para. 61,035 at 61,165 (1994), reh'g denied, 72 
FERC para.  61,071 (1995); see also Southwest Regional Transmission 
Association, 69 FERC para. 61,100 at 61,398 (1994), order on 
compliance filing, 73 FERC para. 61,147 (1995) (SWRTA).
---------------------------------------------------------------------------

2. Commission's Comparability Standard
    In the Spring of 1994, the Commission began to address the problem 
of the disparity in transmission service that utilities provided to 
third parties in comparison to their own uses of the transmission 
system. In the seminal case in this area, American Electric Power 
Service Corporation (AEP), the company voluntarily proposed a tariff of 
general applicability that would offer firm, point-to-point 
transmission service for a minimum of one month.<SUP>68 The Commission 
accepted the proposed transmission tariff for filing and suspended its 
effectiveness for one day, subject to refund.<SUP>69 Rehearing requests 
challenged the Commission's summary approval of the restriction of 
service to point-to-point as being discriminatory and 
anticompetitive.<SUP>70 The rehearing

[[Page 21548]]

requests argued that the tariff should be expanded to include network 
services such as those used by the transmission owner. On rehearing, 
the Commission announced a new standard for evaluating claims of undue 
discrimination.
---------------------------------------------------------------------------

    \68\ 64 FERC para. 61,279 (1993), reh'g granted, 67 FERC para. 
61,168, clarified, 67 FERC para. 61,317 (1994).
    \69\ The Commission explained that AEP could limit the service 
it was offering because it was ``providing the service voluntarily 
under a tariff of general applicability.'' 64 FERC at 62,978.
    \70\ AEP, 67 FERC at 61,489.
---------------------------------------------------------------------------

    The Commission found that a voluntarily offered, new open access 
transmission tariff that did not provide for services comparable to 
those that the transmission owner provided itself was unduly 
discriminatory and anticompetitive.<SUP>71 In reaching that conclusion, 
the Commission broadened its undue discrimination analysis (which 
traditionally had focused on the rates, terms, and conditions faced by 
similarly situated third-party customers) to include a focus on the 
rates, terms, and conditions of a utility's own uses of the 
transmission system:

    \71\ With respect to anticompetitive effects, the Commission 
explained that it has ``adhered to the Supreme Court's determination 
that the Commission's 'important and broad regulatory power * * * 
carries with it the responsibility to consider, in appropriate 
circumstances, the anticompetitive effects of regulated aspects of 
interstate utility operations pursuant to sections 202 and 203, and 
under like directives contained in sections 205, 206 and 207.' Gulf 
States Utilities Company v. FPC, 411 U.S. 747, 758-59 (1972).'' Id. 
at 61,490 (footnote omitted). The Commission reaffirmed that it 
would examine how best to fulfill this responsibility, as well as 
its responsibility to prevent undue discrimination, in light of the 
changing conditions in the electric utility industry. Id.
---------------------------------------------------------------------------

    (A)n open access tariff that is not unduly discriminatory or 
anticompetitive should offer third parties access on the same or 
comparable basis, and under the same or comparable terms and 
conditions, as the transmission provider's uses of its 
system.<SUP>72

    \72\ Id. at 61,490.
---------------------------------------------------------------------------

    Refocusing the analysis was necessitated by the changing conditions 
in the electric utility industry, including the emergence of non-
traditional suppliers and greater competition in bulk power markets. 
Because a transmission provider may use its system in different ways 
(e.g., to integrate load and resources when serving retail native load, 
to make off-system sales or purchases, or to serve wholesale 
requirements customers), the Commission set for hearing the factual 
issues associated with identifying those uses, as well as any potential 
impediments or consequences to providing comparable services to third 
parties.<SUP>73
---------------------------------------------------------------------------

    \73\ Id. at 61,490-91.
---------------------------------------------------------------------------

    After AEP, the Commission applied this comparability standard to a 
proposed open access transmission tariff that was filed by Kansas City 
Power & Light Company (KCP&L) in support of a proposal to sell 
generation at market-based rates.<SUP>74 The Commission explained that, 
in light of AEP, the utility's proposed open access transmission tariff 
(which provided only for point-to-point service) did not adequately 
mitigate its transmission market power so as to justify allowing the 
requested market-based rates. KCP&L could charge market-based rates for 
sales only if it modified its proposed transmission tariff to reflect 
the AEP comparability standard.
---------------------------------------------------------------------------

    \74\ See Kansas City Power & Light Company, 67 FERC para. 61,183 
(1994), reh'g pending.
---------------------------------------------------------------------------

    Since then, the Commission has required comparable service in a 
variety of contexts, and has set for hearing the factual issues 
associated with comparable service. For example, the Commission found 
that market power can be adequately mitigated only if a merged company 
offers transmission services in accordance with the AEP comparability 
standard.<SUP>75 The Commission further held that, even if a merger 
does not result in an increase in market power, the merger would not be 
consistent with the public interest under section 203 of the FPA unless 
the merged company offers comparable transmission services, as defined 
in AEP.<SUP>76 The Commission therefore announced a transmission 
comparability requirement for all new mergers:

    \75\ E.g., CSW, supra, 68 FERC at 61,914.
    \76\ Id.
---------------------------------------------------------------------------

    Given the transition of the electric utility industry as a 
whole, we conclude that, absent other compelling public interest 
considerations, coordination in the public interest can best be 
secured only if merging utilities offer comparable transmission 
services.<SUP>77

    \77\ Id. at 61,915 (footnote omitted).
---------------------------------------------------------------------------

    In Heartland Energy Services, Inc.,<SUP>78 the Commission applied 
its comparability standard to an affiliated electric power marketer 
seeking blanket authorization to sell electricity at market-based 
rates. The Commission explained that

    \78\ 68 FERC para. 61,223 (1994).
---------------------------------------------------------------------------

    For all future cases involving blanket approval of market-based 
rates an offer of comparable transmission services will be required 
before the Commission will be able to find that transmission market 
power has been adequately mitigated. In the context of an affiliated 
power marketer, this means that all of its affiliated utilities must 
have a comparable transmission tariff on file.<SUP>79
---------------------------------------------------------------------------

    \79\ Id. at 62,060. In InterCoast Power Marketing Company, 68 
FERC para. 61,248, clarified, 68 FERC para. 61,324 (1994), the 
Commission rejected an affiliated marketer's proposal to sell at 
market rates without its affiliate utility offering comparable 
transmission services. The Commission stated that the only way to 
ensure that InterCoast does not have transmission market power is to 
require its affiliated public utility to offer comparable 
transmission services. See also LG&E Power Marketing Inc., 68 FERC 
para. 61,247 at 62,120-21 (1994). The Commission added that this is 
consistent with encouraging competitive bulk power markets as 
envisioned by the Energy Policy Act of 1992. Id. at 62,132.
---------------------------------------------------------------------------

    The Commission also denied a request by a company affiliated with a 
transmission-owning utility seeking permission to sell power at market-
based rates to a particular customer. The denial was without prejudice 
to refiling such a request in a new section 205 proceeding, but only 
after the affiliated transmission-owning utility filed a comparable 
transmission service tariff.<SUP>80 The Commission added that it

    \80\ See Hermiston Generating Company, 69 FERC para. 61,035 at 
61,164 (1994), reh'g pending. The Commission subsequently accepted 
the rates on a cost basis. See Letter Order dated November 10, 1994.
---------------------------------------------------------------------------

    Will require comparability in any situation in which a seller 
seeking market-based rates is affiliated with an owner or controller 
of transmission facilities.<SUP>81

    \81\ Id. at 61,165.
---------------------------------------------------------------------------

    The Commission has also stated that ``it will henceforth apply the 
transmission comparability standard announced in the AEP case to all 
transmitting utility members of an RTG.'' <SUP>82
---------------------------------------------------------------------------

    \82\ See SWRTA, 69 FERC at 61,397; see also PacifiCorp, the 
California Municipal Utilities Association, and the Independent 
Energy Producers (on behalf of Western Regional Transmission 
Association), 69 FERC para. 61,099, order on reh'g, 69 FERC para. 
61,352 (1994), order on compliance filing, 71 FERC para. 61,158 
(1995) (WRTA). An RTG is a regional transmission group. It is 
defined as ``a voluntary organization of transmission owners, 
transmission users, and other entities interested in coordinating 
transmission planning (and expansion), operation and use on a 
regional (and inter-regional.'' Policy Statement Regarding Regional 
Transmission Groups, 58 FR 41626 (August 5, 1993), FERC Stats. & 
Regs., Regulations Preambles para. 30,976 at 30,870 n. 4 (RTG Policy 
Statement).
---------------------------------------------------------------------------

    The Commission further declared that comparable services must be 
provided through ``open access'' tariffs rather than only on a 
contract-by-contract basis:

    (T)ariffs are essential to the provision of comparable services. 
Tariffs set out the services that are available and the terms and 
conditions under which those services will be made available * * *. 
(In contrast), a negotiation process creates uncertainty and imposes 
on customers delay and other transaction costs that the transmitting 
utility members of an RTG do not incur when using the transmission 
for their own benefit. Moreover, the ability to execute separate 
transmission agreements with different but similarly situated 
customers is the ability to unduly discriminate among them. A tariff 
ensures against such discrimination in the RTG.<SUP>83

    \83\ SWRTA, 69 FERC at 61,398.

---------------------------------------------------------------------------

[[Page 21549]]

    Thus, the Commission required the RTGs to amend their bylaws to 
commit all transmitting utility members to offer comparable 
transmission services to other RTG members pursuant to a transmission 
tariff or tariffs.
    As discussed below, since the AEP comparability standard was 
announced, the Commission has set for hearing 44 open access tariffs to 
determine what constitutes comparable service. This number includes 
tariffs filed subsequent to the Open Access NOPR. All tariffs have now 
been made subject to the outcome of the Final Rule.
3. Lack of Market Power in New Generation
    In 1994 in the KCP&L case, discussed in the prior section, the 
Commission continued to recognize that transmission remains a natural 
monopoly. However, it found that, in light of the industry and 
statutory changes that now allow ease of market entry, no wholesale 
seller of generation has market power in generation from new 
facilities.<SUP>84 In particular, the Commission explained that it had 
previously noted in Entergy Services, Inc. that

    \84\ KCP&L, 67 FERC para. 61,183 (1994).
---------------------------------------------------------------------------

    There was significant evidence that non-traditional power 
project developers, including qualifying facilities and independent 
power projects, are becoming viable competitors in long-run 
markets.<SUP>85
---------------------------------------------------------------------------

    \85\ Id. at 61,557 (citing Entergy Services, Inc., 58 FERC para. 
61,234 at 61,756 and nn. 63 and 65 (Entergy)).
---------------------------------------------------------------------------

    The Commission further explained that since Entergy, Congress had 
enacted the Energy Policy Act, which had lowered barriers to the entry 
of new suppliers by creating a new class of power suppliers--EWGs--that 
are exempt from the provisions of PUHCA.<SUP>86 The Commission 
concluded that, in considering market-based rate proposals for 
generation sales, it need only focus on market power in transmission, 
generation market power in short-run markets, and other barriers to 
entry.<SUP>87
---------------------------------------------------------------------------

    \86\ Id. The Commission added that ``after examining generation 
dominance in many different cases over the years, we have yet to 
find an instance of generation dominance in long-run bulk power 
markets.'' Id.
    \87\ Id.
---------------------------------------------------------------------------

4. Further Commission Action Addressing a More Competitive Electric 
Industry
    To address the fact that the electric industry is becoming more 
competitive, and to remove barriers that might inhibit a more 
competitive industry, the Commission has initiated a number of 
proceedings: (1) Stranded Cost NOPR,<SUP>88 (2) Transmission Pricing 
Policy Statement,<SUP>89 (3) Pooling Notice of Inquiry,<SUP>90 (4) 
Regional Transmission Group (RTG) Policy Statement,<SUP>91 and (5) 
Notice of Inquiry on Merger Policy.<SUP>92
---------------------------------------------------------------------------

    \88\ FERC Stats. & Regs. para. 32,507 (1994).
    \89\ Inquiry Concerning the Commission's Pricing Policy for 
Transmission Services Provided by Public Utilities Under the Federal 
Power Act, 59 FR 55031 (November 3, 1994), FERC Stats. & Regs., 
Regulations Preambles para. 31,005 (Transmission Pricing Policy 
Statement).
    \90\ Inquiry Concerning Alternative Power Pooling Institutions 
Under the Federal Power Act, 59 FR 54851 (October 26, 1994), FERC 
Stats. & Regs., Notices para. 35,529 (1995) (Pooling Notice of 
Inquiry).
    \91\ FERC Stats. & Regs. para. 30,976 (RTG Policy Statement).
    \92\ FERC Stats. & Regs. para. 35,531 (1996).
---------------------------------------------------------------------------

    In the Stranded Cost NOPR the Commission recognized that the trend 
toward greater transmission access and the transition to a fully 
competitive bulk power market could cause some utilities to incur 
stranded costs as wholesale requirements customers (or retail 
customers) use their supplier's transmission to purchase power 
elsewhere. As the Commission noted, a utility may have built facilities 
or entered into long-term fuel or purchased power supply contracts with 
the reasonable expectation that its customers would renew their 
contracts and would pay their share of long-term investments and other 
incurred costs. If the customer obtains another power supplier, the 
utility may have stranded costs. If the utility cannot locate an 
alternative buyer or somehow mitigate the stranded costs, the 
Commission explained that ``the costs must be recovered from either the 
departing customer or the remaining customers or borne by the utility's 
shareholders.'' <SUP>93 Accordingly, the Commission proposed to 
establish provisions concerning the recovery of wholesale and retail 
stranded costs by public utilities and transmitting utilities.
---------------------------------------------------------------------------

    \93\ FERC Stats. & Regs. para. 32,507 at 32,864.
---------------------------------------------------------------------------

    In the Transmission Pricing Policy Statement, the Commission 
announced a new policy providing greater flexibility in the pricing of 
transmission services provided by public utilities and transmitting 
utilities. The Commission traditionally had allowed only postage-stamp, 
contract-path pricing.<SUP>94 Under the new policy, we will permit a 
variety of proposals, including distance sensitive and flow-based 
pricing, which may be more suitable for competitive wholesale power 
markets.<SUP>95 The Commission explained that this ``(g)reater pricing 
flexibility is appropriate in light of the significant competitive 
changes occurring in wholesale generation markets, and in light of our 
expanded wheeling authority under the Energy Policy Act of 1992.'' 
<SUP>96 However, the Commission explained that any new transmission 
pricing proposal must meet the Commission's AEP comparability standard. 
The Commission further explained that comparability of service applies 
to price as well as to terms and conditions.<SUP>97
---------------------------------------------------------------------------

    \94\ Most transmission contracts set a single price for energy 
flow over a utility's transmission system. This single-price policy 
is called ``postage stamp'' pricing because the rate does not depend 
on how far the power moves within a company's transmission system. 
If power flows through several companies, traditional industry 
practice is to specify that power flows along a ``contract path'' 
consisting of the transmission-owning utilities between the ultimate 
receipt and delivery points. See Indiana Michigan Power Company, 64 
FERC para. 61,184 at 62,545 (1993).
    \95\ Unlike with postage stamp pricing, with distance-sensitive 
pricing the cost of moving power through a company depends on how 
far the power moves within the company. In contrast to contract path 
pricing, flow-based pricing establishes a price based on the costs 
of the various parallel paths actually used when the power flows. 
Because flow-based pricing can account for all parallel paths used 
by the transaction, all transmission owners with facilities on any 
of the parallel paths could be compensated for the transaction.
    \96\ FERC Stats. & Regs. para. 31,005 at 31,136.
    \97\ Id. at 31,142.
---------------------------------------------------------------------------

    The Commission issued the Pooling Notice of Inquiry to receive 
comments on traditional power pools and on alternative power pooling 
institutions that are being explored in today's more competitive 
environment. The Commission expressed concern that

    (G)iven the ongoing changes in the competitive environment of 
the electric utility industry--in particular, the potential for 
substantially increased access to transmission--we must consider 
whether we are appropriately balancing our dual objectives of 
promoting coordination and competition.<SUP>98

    \98\ FERC Stats. & Regs. para. 35,529 at 35,715.
---------------------------------------------------------------------------

    Accordingly, the Commission explained that it wished to look at 
alternative power pooling institutions and to re-examine the role of 
more traditional power pools in today's environment of increased 
competition. In particular the Commission expressed its intent to 
ensure that its policies ``are consistent with the development of a 
competitive bulk power market.'' <SUP>99
---------------------------------------------------------------------------

    \99\ Id. at 35,714. As explained below, the Commission held 
technical conferences on issues surrounding power pools and 
competition.
---------------------------------------------------------------------------

    In the RTG Policy Statement, the Commission announced a policy 
encouraging the development of RTGs. The Commission explained that a 
primary purpose of RTGs is to facilitate transmission access for 
potential users and voluntarily resolve disputes over such service. The 
Commission has approved the formation of three

[[Page 21550]]

RTGs.<SUP>100 One of the conditions is that each RTG member must offer 
comparable transmission services by tariff to other RTG members.
---------------------------------------------------------------------------

    \100\ See WRTA and SWRTA, supra, and Northwest Regional 
Transmission Association, 71 FERC para. 61,397 (1995).
---------------------------------------------------------------------------

    In the merger NOI, the Commission indicated that it will review 
whether its criteria and policy for evaluating mergers need to be 
modified in light of the changing circumstances occurring in the 
electric industry.
    In addition to the Commission's actions, a number of states have 
initiated proceedings concerning retail wheeling or proposed 
legislation for retail wheeling, that is, for ultimate consumers to 
choose their supplier of power, or other restructuring 
proposals.<SUP>101
---------------------------------------------------------------------------

    \101\ At least 12 states have retail wheeling proposals, 
legislation, or pilot programs underway--Alabama, California, 
Connecticut, Illinois, Massachusetts, Michigan, New Hampshire, New 
York, Ohio, Rhode Island, Vermont, and Wisconsin. At least 14 other 
states are investigating retail wheeling. Currently, according
    to a report of the NARUC-affiliated National Council on 
competition and the Electric Industry, 41 States are actively 
involved in investigating whether and how to restructure their 
respective electric power markets. Of this total, 29 State 
regulatory authorities * * * have initiated investigations. In 
addition, five State legislatures are involved in similar 
investigations, while seven other States have joint regulatory/
legislative proceedings underway.
    Testimony of the Honorable Cheryl L. Parrino, Chair of the 
Wisconsin Public Service Commission, on behalf of the National 
Association of Regulatory Utility Commissioners, before the United 
States Senate Committee on Energy and Natural Resources (March 6, 
1996).
---------------------------------------------------------------------------

5. Events Since Issuance of Open Access NOPR
    Since issuance of the Open Access NOPR, public utilities have 
filed, in some form or another, 47 open access tariffs. In acting on 
those filings, the Commission has made all of the non-rate terms and 
conditions of those proposed tariffs subject to the outcome of this 
Final Rule.<SUP>102
---------------------------------------------------------------------------

    \102\ See American Electric Power Service Corporation, et al., 
72 FERC para. 61,287 at 61,238 (1995).
---------------------------------------------------------------------------

    Over the last year, the Commission also has received and analyzed 
more than 20,000 pages of comments that were received from over 400 
commenters, as well as additional information provided by industry 
participants at a number of Commission-initiated technical 
conferences.<SUP>103 Those technical conferences addressed several 
issues--ancillary services, pro forma tariffs, power pools, and ISOs--
and provided significant input to the Commission's formulation of this 
Final Rule.
---------------------------------------------------------------------------

    \103\ Attached to this Final Rule as Appendix B is a list of 
commenters and the abbreviations used to designate them, including 
those commenters that filed late.
---------------------------------------------------------------------------

F. Need for Reform

    The many changes discussed above have converged to create a 
situation in which new generating capacity can be built and operated at 
prices substantially lower than many utilities' embedded costs of 
generation. As discussed above, new generation facilities can produce 
power on the grid at a cost of less than 3 cents per kWh to 5 cents per 
kWh, yet the costs for large plants constructed and installed over the 
last decade were typically in the range of 4 to 7 cents per kWh for 
coal plants and 9 to 15 cents for nuclear plants.
    Non-traditional generators are taking advantage of this opportunity 
to compete. Indeed, the non-traditional generators' share of total U.S. 
electricity generation increased from 4 percent in 1985 to 10 percent 
in 1993.<SUP>104 Much of this increased share of generation is the 
result of competitive bidding for new generation resources that has 
occurred in 37 states. Since 1984, almost 4,000 projects, representing 
over 400,000 MW, have been offered in response to requests. Over 350 
projects have been selected to supply 20,000 MW, and, of these, 126 are 
now online producing almost 7,800 MW of power.<SUP>105
---------------------------------------------------------------------------

    \104\ Energy Information Administration, Performance Issues for 
a Changing Electric Power Industry (January 1995) 10 and (Figure 5).
    \105\ Current Competition, November 1994, Vol. 5, No. 8, at 8.
---------------------------------------------------------------------------

    In addition, the cost of utility-generated electricity differs 
widely across the major regions of the United States. Average utility 
rates range from 3 to 5 cents in the Northwest to 9 to 11 cents in 
California. Electricity consumers are demanding access to lower cost 
supplies available in other regions of the United States, and access to 
the newer, lower cost generation resources. Therefore, it is important 
that the non-traditional generators of cheaper power be able to gain 
access to the transmission grid on a non-discriminatory open access 
basis.
    The Commission's goal is to ensure that customers have the benefits 
of competitively priced generation. However, we must do so without 
abandoning our traditional obligation to ensure that utilities have a 
fair opportunity to recover prudently incurred costs and that they 
maintain power supply reliability. As well, the benefits of competition 
should not come at the expense of other customers. The Commission 
believes that requiring utilities to provide non-discriminatory open 
access transmission tariffs, while simultaneously resolving the 
extremely difficult issue of recovery of transition costs (discussed 
infra), is the key to reconciling these competing demands.
    Non-discriminatory open access to transmission services is critical 
to the full development of competitive wholesale generation markets and 
the lower consumer prices achievable through such competition.<SUP>106 
Transmitting utilities own the transportation system over which bulk 
power competition occurs and transmission service continues to be a 
natural monopoly. Denials of access (whether they are blatant or 
subtle), and the potential for future denials of access, require the 
Commission to revisit and reform its regulation of transmission in 
interstate commerce. As discussed in detail in Section IV.B., such 
action is required by the FPA's mandate that the Commission remedy 
undue discrimination.
---------------------------------------------------------------------------

    \106\ As discussed above, a significant number of public 
utilities still do not have any form of an ``open access'' tariff on 
file with the Commission and no public utility has on file a non-
discriminatory open access tariff as defined by this Rule.
---------------------------------------------------------------------------

    Since the time the NOPR issued, the Commission staff has completed 
an FEIS that provides a quantitative estimate of some of the cost 
savings expected from this Rule: approximately $3.8 to $5.4 billion per 
year. Other non-quantifiable benefits are also expected from this Rule 
and include: (1) Better use of existing assets and institutions; (2) 
new market mechanisms; (3) technical innovation; and (4) less rate 
distortion. These potential benefits to the Nation's electricity 
consumers and the economy as a whole confirm the need to take generic 
action to remove barriers to competition. In what follows, we set out 
the changes necessary to remedy undue discrimination and to ensure a 
fair transition to a more competitive regulatory regime.

IV. Discussion

A. Scope of the Rule

1. Introduction
    The Commission has determined that non-discriminatory open access 
transmission services (including access to transmission information) 
and stranded cost recovery are the most critical components of a 
successful transition to competitive wholesale electricity markets. 
These issues are the focal point of this Rule, the accompanying rule on 
open access same-time information systems, and the accompanying 
proposed rule on capacity reservation tariffs.

[[Page 21551]]

    In undertaking these initiatives, however, we are mindful that they 
are part of a broader picture of evolving issues affecting the electric 
industry and that other Commission policies will play an important role 
in ensuring the full development of competitive markets. Among the many 
issues that are important to competitive bulk power markets are: 
independent system operators (ISOs); regional transmission groups; 
generation market power; utility merger policy; and the development of 
innovative transmission pricing alternatives, such as flow-based, 
distance-sensitive transmission pricing methodologies that reflect 
incremental costs. In particular, we believe that ISOs have great 
potential to assist us and the industry 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. Although we discuss some of 
these issues in this Rule, we will further develop our policies in 
other proceedings as well to accommodate and encourage more efficient 
market structures.
    We now address the comments received on the scope of the proposed 
rulemaking.
2. Functional Unbundling
    In the NOPR, the Commission preliminarily found that functional 
unbundling of wholesale generation and transmission services is 
necessary to implement non-discriminatory open access 
transmission.<SUP>107 At the same time, the Commission explained that 
the proposed rule would accommodate, but not require, corporate 
unbundling (which could include selling generation or transmission 
assets to a non-affiliate (divestiture) or the less aggressive step of 
establishing separate corporate affiliates to manage a utility's 
transmission and generation assets). However, we invited comments on 
functional unbundling and asked whether it is a strong enough measure 
to ensure non-discriminatory open access transmission without some form 
of corporate restructuring.
---------------------------------------------------------------------------

    \107\ FERC Stats. & Regs. para.32,514 at 33,080.
---------------------------------------------------------------------------

Comments
    Commenters take both sides on whether functional unbundling is 
sufficient to assure non-discriminatory open access transmission or 
whether a stronger measure, such as corporate unbundling, is needed.
Supporting Functional Unbundling
    Various commenters, including utilities and state commissions, 
generally support functional unbundling as sufficient to assure non-
discriminatory open access transmission and oppose requiring corporate 
unbundling or divestiture.<SUP>108 Several commenters state that 
functional unbundling will remedy discrimination without creating the 
inefficiencies and additional costs that corporate restructuring would 
create.<SUP>109
---------------------------------------------------------------------------

    \108\ E.g., Ohio Edison, UtiliCorp, Pennsylvania P&L, Atlantic 
City, Montana Power, IL Com, Seattle, OK Com, TX Industrials, 
MidAmerican, Southwestern, Southern, DOD, Public Service Co of CO, 
SC Public Service Authority, Florida Power Corp, DOE, WP&L, Com Ed, 
SBA, Consumers Power, CA Com, UT Com, Houston L&P, KCPL, EEI.
    \109\ E.g., Florida Power Corp, El Paso, PSNM, and SC Public 
Service Authority.
---------------------------------------------------------------------------

    A number of other commenters argue that the Commission has no 
authority under the FPA to require divestiture of transmission 
assets.<SUP>110 Several of these commenters assert that, even if the 
Commission has the authority, the electric industry, unlike the natural 
gas industry, is not ready for mandated corporate unbundling because 
electric utilities still serve a high percentage of retail customers 
and own large amounts of the generating capacity. They assert that 
transmission system operation requires the operator to have control 
over much of the generating capacity.
---------------------------------------------------------------------------

    \110\ E.g., Southwestern, PECO, El Paso, Florida Power Corp, 
NSP, Public Service E&G, MidAmerican.
---------------------------------------------------------------------------

    Various other commenters also support functional unbundling, but 
believe that safeguards are needed to make it work.<SUP>111 Power 
Marketing Association, for example, suggests a number of safeguards: 
adoption of cost allocation mechanisms to ensure that utilities do not 
shift costs from generation to transmission; random audits of utility 
books; a requirement that each utility file a code of conduct that 
provides for maximum separation of generation and transmission 
functions; and active oversight and complaint procedures with strong 
penalties for abuse. OK Com and GA Com believe that functional 
unbundling along with the safeguard of the Commission's complaint 
process will provide sufficient incentive for non-discriminatory open 
access transmission.
---------------------------------------------------------------------------

    \111\ E.g., NRECA, IN Com, Power Marketing Association, TDU 
Systems, NorAm, Turlock, Texaco, Utility Shareholders, NSP, El Paso, 
Utility Investors Analysts, PECO, Florida Power Corp, UT Com, 
Sierra, Carolina P&L, SoCal Gas, OK Com, FL Com, Southern.
---------------------------------------------------------------------------

Supporting Corporate Unbundling
    A number of commenters see weaknesses in functional unbundling and 
argue that some form of corporate unbundling is necessary to assure 
non-discriminatory open access transmission.<SUP>112 American Forest & 
Paper says that there is affiliate abuse in the gas industry and argues 
that the electric industry presents even more serious potential for 
abuse because it is still dominated by vertically integrated 
utilities.<SUP>113 UAMPS asserts that functional unbundling is 
insufficient because the utility will still favor itself on issues 
related to transmission planning, capital investment, and operation and 
maintenance and replacement costs.
---------------------------------------------------------------------------

    \112\ E.g., American Forest & Power, American National Power, ND 
Com, IL Com, UAMPS, NIEP, APPA, Public Power Council, Municipal 
Energy Agency Nebraska, Missouri Basin MPA, Texaco, Direct Services 
Industries, Calpine, CCEM, Wisconsin Coalition, VT DPS.
    \113\ See also American National Power, ND Com, Calpine.
---------------------------------------------------------------------------

    NIEP argues that divestiture of generation assets from transmission 
and distribution is the preferred mechanism for mitigating market 
power. It further suggests that if corporate divestiture is not 
feasible the Commission should

    Seek to achieve ``virtual divestiture'' by requiring that the 
utility generation function be separated from transmission and 
distribution functions in a separate corporate affiliate, or 
business unit, and that affiliate transaction rules be established 
to guard against possible abuses. <SUP>114
---------------------------------------------------------------------------

    \114\ NIEP Initial Comments at 4.

    It maintains that the Commission has broad authority to protect 
against undue discrimination and anticompetitive behavior and can order 
divestiture if such action is required to remedy such behavior.<SUP>115
---------------------------------------------------------------------------

    \115\ See also Municipal Energy Agency Nebraska, Direct Services 
Industries.
---------------------------------------------------------------------------

    FTC and DOJ argue that operational unbundling, an example of which 
is the formation of an independent system operator (ISO), likely would 
be more effective than functional unbundling and less costly than 
industry-wide divestiture.<SUP>116 FTC describes operational unbundling 
as ``structural institutional arrangements, short of divestiture, that 
would separate operation of the transmission grid and access to it from 
economic interests in generation.'' It gives as an example the 
California proposal under which utilities would continue to own 
transmission lines, but an independent system operator would have 
operational control. DOJ also suggests ``a separate authority'' to

[[Page 21552]]

manage the grid and access to the grid, joint ventures, and voluntary 
pooling arrangements. These commenters argue that operational 
unbundling would be easier to enforce than functional unbundling.
---------------------------------------------------------------------------

    \116\ Others oppose operational unbundling. See, e.g., Carolina 
P&L, Salt River.
---------------------------------------------------------------------------

    DOE states that separation of the control of transmission from 
vertically-integrated companies does not necessarily require a poolco 
or any particular market mechanism. It suggests the possibility of an 
ISO that is functionally separate from any buyer or seller of 
generation, but would not perform all the functions of a poolco.
    United Illuminating supports ``operational unbundling'' that would 
either (1) eliminate vertical integration and divestiture of 
transmission assets, leading to the formation of a regional 
transmission company, or (2) develop a regional contractual approach to 
transmission services that eliminates the transmission owner's market 
power and fairly allocates support of the transmission facilities 
between native load and third-party users of the system.
Commission Conclusion
    We conclude that functional unbundling of wholesale services is 
necessary to implement non-discriminatory open access transmission and 
that corporate unbundling should not now be required. As we explained 
in the NOPR, functional unbundling means three things:
    (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.
    We believe that these requirements are necessary to ensure that 
public utilities provide non-discriminatory service.<SUP>117 These 
requirements also will give public utilities an incentive to file fair 
and efficient rates, terms, and conditions, since they will be subject 
to those same rates, terms, and conditions.
---------------------------------------------------------------------------

    \117\ When and how functional unbundling is to be achieved for 
requirements transactions and for various types of coordination 
arrangements, including power pools, is discussed at Sections IV.A.5 
and IV.F. Functional unbundling of ancillary services is discussed 
in Section IV.D.
---------------------------------------------------------------------------

    However, we recognize that additional safeguards are necessary to 
protect against market power abuses. Functional unbundling will work 
only if a strong code of conduct (including a requirement to separate 
employees involved in transmission functions from those involved in 
wholesale power merchant functions) is in place. In the RINs NOPR, the 
Commission proposed a code of conduct that would apply to all public 
utility transmission providers. As the Commission explained,

    [T]his code of conduct would require, among other matters, a 
separation of the utilities' transmission system operations and 
wholesale marketing functions, and would define permissible and 
impermissible contacts between employees that conduct wholesale 
generation marketing functions and employees that handle 
transmission system operations and reliability in the system control 
center or at other facilities or locations.<SUP>118

    \118\ Real-Time Information Networks and Standards of Conduct, 
Notice of Proposed Rulemaking, 60 FR 66182 (December 21, 1995), FERC 
Stats. & Regs., Proposed Regulations para. 32,516 at 33,170 (1995).
---------------------------------------------------------------------------

    Adoption of this code of conduct, discussed in detail in the 
accompanying final rule on OASIS,<SUP>119 is needed to ensure that the 
transmission owner's wholesale marketing personnel and the transmission 
customer's marketing personnel have comparable access to information 
about the transmission system.
---------------------------------------------------------------------------

    \119\ The final rule on information systems no longer uses the 
terminology RINs. The new terminology used is OASIS--Open Access 
Same-time Information System--which we will use in this Final Rule.
---------------------------------------------------------------------------

    As noted by OK Com and GA Com, a further safeguard--section 206--is 
available if a public utility seeks to circumvent the functional 
unbundling requirements. Under section 206, any person is free to file 
a complaint with the Commission detailing any alleged misbehavior on 
the part of the public utility or its affiliates concerning matters 
subject to our jurisdiction under the FPA. Similarly, the Commission 
may, on its own motion, initiate a proceeding to investigate the 
practices of the public utility and its affiliates.
    We believe that functional unbundling, coupled with these 
safeguards, is a reasonable and workable means of assuring that non-
discriminatory open access transmission occurs. In the absence of 
evidence that functional unbundling will not work, we are not prepared 
to adopt a more intrusive and potentially more costly mechanism--
corporate unbundling--at this time.
    Several commenters discuss the need to encourage or even to require 
ISOs in the context of functional unbundling. We believe 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. As we learned at our technical 
conference on power pools, many utilities are examining ISOs and 
corporate unbundling in various shapes and forms, particularly in the 
context of power pools. We discuss ISOs extensively in our section on 
power pools where we believe they will have an important role to play. 
However, in the context of individual utility transactions, we believe 
that the less intrusive functional unbundling approach outlined above 
is all that we must require at this time. Nevertheless, we see many 
benefits in ISOs, and encourage utilities to consider ISOs as a tool to 
meet the demands of the competitive marketplace.
    As a further precaution against discriminatory behavior, we will 
continue to monitor electricity markets to ensure that functional 
unbundling adequately protects transmission customers. At the same 
time, we will analyze all alternative proposals, including formation of 
ISOs, and, if it becomes apparent that functional unbundling is 
inadequate or unworkable in assuring non-discriminatory open access 
transmission, we will reevaluate our position and decide whether other 
mechanisms, such as ISOs, should be required.
    Finally, while we are not now requiring any form of corporate 
unbundling, we again encourage utilities to explore whether corporate 
unbundling or other restructuring mechanisms may be appropriate in 
particular circumstances. Thus, we intend to accommodate other 
mechanisms that public utilities may submit, including voluntary 
corporate restructurings (e.g., ISOs, separate corporate divisions, 
divestiture, poolcos), to ensure that open access transmission occurs 
on a non-discriminatory basis. We also will continue to monitor--and 
stand ready to work with parties engaging in--innovative restructuring 
proposals occurring around the country.
3. Market-Based Rates
a. Market-Based Rates for New Generation
    In the NOPR, the Commission proposed to codify its determination in 
Kansas City Power & Light Company <SUP>120

[[Page 21553]]

that the generation dominance standard for market-based sales from new 
capacity be dropped.<SUP>121 The proposed new section 35.27 would 
provide:

    \120\ 67 FERC para. 61,183 at 61,557 (1994), reh'g pending 
(KCP&L).
    \121\ FERC Stats. & Regs. para. 32,514 at 33,050.
---------------------------------------------------------------------------

    Notwithstanding any other requirements, any public utility 
seeking authorization to engage in sales for resale of electric 
energy at market-based rates shall not be required to demonstrate 
any lack of market power in generation with respect to sales from 
capacity first placed in service on or after June 10, 1996.<SUP>122

    \122\ Id. at 33,154.
---------------------------------------------------------------------------

    However, this proposal would not affect the Commission's continuing 
authority to look at whether an applicant and its affiliates could 
erect other barriers to entry and whether there may be affiliate abuse 
or reciprocal dealing.<SUP>123
---------------------------------------------------------------------------

    \123\ 67 FERC at 61,557.
---------------------------------------------------------------------------

Comments
    A number of commenters support the Commission's determination in 
KCP&L <SUP>124 and several of them explicitly support the Commission's 
proposed codification.<SUP>125 EEI asserts that more than 50 percent of 
new generation is from non-utility sources and that recent competitive 
solicitations for new capacity have been greatly over-subscribed. 
Entergy argues that there is no evidence in any proceeding thus far of 
a market power problem in long-run markets.
---------------------------------------------------------------------------

    \124\ E.g., Entergy, EEI, Atlantic City, Duke Centerior, Houston 
L&P, Montana-Dakota Utilities, Canadian Petroleum Producers, DOE, 
Florida Power Corp, PSNM.
    \125\ E.g., EEI, Centerior, Houston L&P, NYSEG.
---------------------------------------------------------------------------

    Other commenters, however, oppose codifying KCP&L.<SUP>126 They 
believe that market power in long-run markets exists for both new and 
old generation due to, for example, constraints on interface 
capabilities and unduly long notice periods for replacement of 
purchases. They argue that there is not enough of a distinction between 
new and old generation to treat them differently. TDU Systems also 
notes that the Commission in KCP&L did not take into account the 
differences between firm and non-firm bulk power. NIEP and ELCON 
conclude that the Commission erroneously found in KCP&L that no 
wholesale seller of generation has market power in generation from new 
facilities. NIEP asserts that in each service area there is usually 
only one wholesale buyer--the utility--who also is virtually always a 
wholesale seller of generation. Under these circumstances, NIEP argues 
that there cannot be arm's-length bargaining. Environmental Action 
complains that the Commission's proposal to codify KCP&L ignores 
significant factors that impede entry to generation markets, such as 
utility resistance to purchased power, state government-created 
barriers to non-utility generation, pancaking of rates under the 
contract path approach, sunk investment, and scale economies.
---------------------------------------------------------------------------

    \126\ E.g., TDU Systems, ELCON, NRECA, Environmental Action, 
NIEP, APPA, Power Marketing Association, EGA.
---------------------------------------------------------------------------

Commission Conclusion
    In reviewing applications to sell at market-based rates, whether 
from new (unbuilt) capacity or existing capacity, we require that the 
seller (and each of its affiliates) must not have, or must have 
mitigated, market power in generation and transmission and not control 
other barriers to entry. In order to demonstrate the requisite absence 
or mitigation of transmission market power, a transmission-owning 
public utility seeking to sell at market-based rates must have on file 
with the Commission an open access transmission tariff for the 
provision of comparable service. In addition, the Commission considers 
whether there is evidence of affiliate abuse or reciprocal 
dealing.<SUP>127
---------------------------------------------------------------------------

    \127\ See, e.g., MidAmerican Energy Company, 74 FERC para. 
61,211 (1996).
---------------------------------------------------------------------------

    In KCP&L, we stated that ``in light of industry and statutory 
changes which allow ease of market entry, we therefore will no longer 
require rate applicants to submit evidence of generation dominance in 
long-run bulk power markets.'' <SUP>128 We further explained that we 
had examined ``generation dominance in many different cases over the 
years'' and had ``yet to find an instance of generation dominance in 
long-run bulk power markets.'' <SUP>129 Commenters have criticized our 
findings in KCP&L, but no commenter has provided any evidence of 
generation dominance in long-run bulk power markets. Moreover, we have 
seen no such evidence in any of the market-based rate cases we have 
considered since KCP&L. Based on the comments received, we will codify 
the Commission's determination in KCP&L that the generation dominance 
standard for market-based sales from new capacity should be dropped. 
Because the Commission's findings in KCP&L applied to long-run markets, 
we will revise proposed Sec. 35.27 to apply to sales from capacity for 
which construction has commenced on or after the effective date of this 
Rule.<SUP>130
---------------------------------------------------------------------------

    \128\ KCP&L, 67 FERC at 61,557. See also discussion in proposed 
rule, FERC Stats. & Regs. at 33,067-68.
    \129\ Id.
    \130\ The NOPR's proposed language that a public utility would 
not have to demonstrate a lack of market power in generation for 
sales from capacity first placed in service on or after the date 30 
days after the final rule is published in the Federal Register does 
not properly reflect the finding in KCP&L. Because KCP&L addressed 
new or unbuilt generation, the proposed language is being revised as 
indicated above and as set forth in the regulatory text included 
with this Final Rule.
---------------------------------------------------------------------------

    The Commission wishes to clarify that dropping the generation 
dominance standard for new capacity does not affect the demonstration 
that an applicant must make in order to qualify for market-based rates 
for sales from its existing generating capacity. In other words, the 
fact that an applicant need not demonstrate its lack of generation 
dominance with respect to new capacity cannot be used to ``bootstrap'' 
the authorization of market-based rates for its existing capacity. 
Moreover, our evaluation of market-based rates for existing capacity 
will include consideration of new capacity.
    In addition, the fact that we are codifying KCP&L does not mean 
that we will ignore specific evidence presented by an intervenor that a 
seller requesting market-based rates for sales from new generation 
nevertheless possesses generation dominance. For example, if the 
evidence indicated that the new generator, due to its proximity to an 
existing transmission constraint, could significantly influence the 
ability to move power across the constraint, we would consider such 
evidence in determining whether to grant the applicant's 
request.<SUP>131 If such evidence is presented, the Commission will 
evaluate whether the evidence disproves the premise that the seller 
lacks generation dominance with respect to its new capacity.
---------------------------------------------------------------------------

    \131\ Cf. Wisconsin Electric Power Company, et al., 74 FERC 
para. 61,069 at 61,193 (1996).
---------------------------------------------------------------------------

    If the applicant has existing generation, the sales from which are 
authorized to be made on a market basis, the Commission would consider 
whether the new generation (when added to the existing generation with 
market-based authority) results in the applicant having generation 
dominance. On the other hand, if the applicant has existing generation, 
the sales from which are subject to cost-of-service regulation, the 
Commission would not include this generation in its analysis of the 
applicant's request for market-based rates for its new generation. The 
question of whether or not the applicant lacks generation dominance 
with respect to its existing capacity is relevant only if, and when, 
the seller applies to the Commission for authority to make wholesale 
sales for its existing capacity at market-based rates.
    If evidence regarding an applicant's generation dominance with 
respect to

[[Page 21554]]

its new capacity is submitted, the applicant would be required to 
provide a satisfactory rebuttal.
b. Market-Based Rates for Existing Generation
    In the NOPR, the Commission explained that increased competition 
resulting from open access transmission may reduce or even eliminate 
generation-related market power in the short-run market (sales from 
existing capacity).<SUP>132 Because market power has been the primary 
concern of the Commission in analyzing requests for market-based rates 
for such sales, we sought comments on the effect of industry-wide non-
discriminatory open access on our criteria for authorizing power sales 
at market-based rates. The Commission also sought comments on whether 
the generation dominance standard should be dropped for market-based 
sales from existing capacity.
---------------------------------------------------------------------------

    \132\ FERC Stats. & Regs. para. 32,514 at 33,093-94.
---------------------------------------------------------------------------

Comments
    Many commenters support, but many also oppose, market-based rates 
for existing generation without a case-specific analysis of generation 
dominance.
Supporting Market-Based Rates for Existing Generation
    Many commenters (primarily IOUs and a number of state commissions) 
assert that existing generators will not possess market power after 
implementation of non-discriminatory open access transmission and that 
market-based rates should be permitted generically for sales from 
existing generation.<SUP>133
---------------------------------------------------------------------------

    \133\ E.g., EEI, CINergy, Central Illinois Public Service, 
Citizens Utilities, Com Ed, Ohio Edison, Allegheny, Southern, 
Portland, NRRI, Pennsylvania P&L, PECO, Dayton P&L, Utilities For 
Improved Transition, Centerior, Houston L&P, Duke, ConEd, IPALCO, 
Salt River, PJM, NU, NYSEG, Oklahoma G&E, PA Com, OK Com, CT DPUC, 
CA Com, MT Com.
---------------------------------------------------------------------------

    EEI asserts that market power concerns generally would be 
transitory, limited to the time needed to build new facilities. Thus, 
it recommends that all markets be declared competitive by a date 
certain and that market-based rates then be allowed, with customers 
permitted to file complaints. Florida Power Corp believes that existing 
procedures under sections 205 and 206 will adequately protect 
consumers. Other commenters also urge the Commission to eliminate its 
generation dominance standard, but assert that the Commission should 
allow a showing of market dominance in a complaint or show cause 
proceeding.<SUP>134 CT DPUC notes that the Commission should be able to 
rely on rules of conduct, market mechanisms, and monitoring to curb any 
market power that may exist.
---------------------------------------------------------------------------

    \134\ E.g., Consumers Power, Portland, Dayton P&L, CSW.
---------------------------------------------------------------------------

    Utilities For Improved Transition argues that if utilities cannot 
get market-based rates, the new players in the market will have an 
unfair advantage, since they do not have to carry the traditional 
utilities' burden of older, less efficient plants.
    Entergy proposes a screening test that would permit the Commission 
to ``deregulate'' wholesale sales to certain short-run markets. CINergy 
recommends that after industry-wide open access tariffs become 
effective, the Commission adopt a rebuttable presumption that all 
markets are workably competitive; that presumption could be rebutted in 
a section 206 proceeding.<SUP>135
---------------------------------------------------------------------------

    \135\ See also Citizens Utilities.
---------------------------------------------------------------------------

    UtiliCorp, while it believes that market power will probably be 
fully mitigated by open access, also argues that the Commission should 
examine generation dominance on a region-by-region basis.<SUP>136 
Montana-Dakota Utilities argues that the Commission should allow all 
suppliers in a power pool or RTG to have market-based rates after a 
Commission finding that there is sufficient generation competition 
within the region.
---------------------------------------------------------------------------

    \136\ See also CSW, Industrial Energy Applications, Public 
Service Co of CO, Coalition for Economic Competition.
---------------------------------------------------------------------------

    Duke states that it would be highly inconsistent for the Commission 
to require open access, but not allow utilities to compete in the 
market. It further states that the relevant market should be determined 
using standard antitrust techniques; the Commission should examine the 
options available to customers and determine whether the utility 
possesses monopoly power in a relevant market.
Opposing Market-Based Rates for Existing Generation
    Many commenters are concerned that even with open access tariffs 
certain generators will be able to exercise market dominance.<SUP>137 
For example, NARUC argues that utilities retain market power through 
their ownership of existing generation and transmission facilities, 
favorable long-term contracts for fuel and other inputs, and access to 
superior generation sites.<SUP>138 NRECA believes that the universe of 
generation providers is still too narrow to assume a competitive market 
and that other factors, such as transmission constraints and pancaking 
of rates, will inhibit the development of competitive markets.<SUP>139 
FTC says that, although comparable transmission access could broaden 
the relevant geographic market for generation, the Commission should 
not assume that there will be no market power. It says that the 
Commission must continue to evaluate each case.<SUP>140 TDU Systems 
argues that the Commission cannot move to market-based rates without a 
Congressional determination that deregulation of wholesale electric 
rates should be implemented. It further asserts that the Commission 
does not have a factual basis for a reasoned conclusion that regulated 
utilities do not have market dominance--full open access is only a goal 
at this time, and the success of open access will depend upon the 
transmission rate structures the Commission approves.
---------------------------------------------------------------------------

    \137\ E.g., NRECA, TDU Systems, MT Com, SMUD, NEPCO, Orange & 
Rockland, El Paso, American Forest & Paper, NIPSCO, AEC & SMEPA, OH 
Com, IL Com, IN Com, Legal Environmental Assistance, LG&E, Cajun, 
Industrial Energy Applications, LEPA, MA DPU, MI Com, FTC, Minnesota 
P&L, SC Public Service Authority, WP&L, NARUC, Canadian Petroleum 
Producers, DOD, CCEM, Environmental Action, American Wind, Cajun, 
NIEP, EGA, TAPS, ELCON, Consolidated Natural Gas.
    \138\ See also NIEP, Pacificorp, CA Energy Com.
    \139\ See also MT Com, TDU Systems, Soyland.
    \140\ See also AEC & SMEPA, NIPSCO, El Paso (discusses a 
particular transmission constraint that it states limits its access 
to suppliers).
    NRECA is also concerned that mergers may create a handful of 
``mega-public utilities'' that may affect a regional generation 
market and that the Commission should apply more traditional 
antitrust principles in analyzing the impacts of mergers.
---------------------------------------------------------------------------

    LEPA raises concerns that the small bulk power suppliers, QFs, co-
generators, EWGs, IPPs, and marketers (who provide non-requirements 
power) may not be able to bring competition to the wholesale market. 
LEPA concludes that ``barriers will exist unless buyers have full 
access to requirements power itself, rather than just to the chance to 
acquire the individual components of requirements power.'' <SUP>141 TDU 
Systems raises concerns about the limited number of generation 
providers and the effect of possible future mergers. It also argues 
that pancaked rates raise the cost of transmission to third parties, 
thereby restricting the geographic scope of markets. As a result, TDU 
Systems asserts that individual generators in highly concentrated 
regions will still be able to exert market power. OH Com expresses 
concerns that restrictions on siting of generation and transmission 
will favor nearby generators. SC Public Service Authority argues that 
if the Commission allows utilities to recover stranded costs their 
market power will not be mitigated, since customers will

[[Page 21555]]

have to pay exit fees to switch suppliers.<SUP>142
---------------------------------------------------------------------------

    \141\ LEPA Initial Comments Affidavit of William G. Shepherd at 
4.
    \142\ See also DOD and WP&L. IL Com suggests that the Commission 
allow market-based rates to a utility on the condition that the 
utility forego stranded cost recovery.
---------------------------------------------------------------------------

    CCEM notes that in Order No. 636 gas pipelines were not allowed 
market-based rates for merchant sales until after transmission had been 
completely unbundled and non-discriminatory open access had been fully 
implemented.
    DOE and DOJ assert that open access should not be assumed to 
mitigate market power sufficiently to justify deregulation of existing 
generation--structural changes, such as control of the regional grid by 
an independent entity, are required. DOE requests that the Commission 
continue to look for affiliate abuse when reviewing market-based rates 
for new generation. Similarly, EPA is concerned that even with open 
access, individual generators may still exert market power by their 
domination of a particular geographic market. It is also concerned that 
low-cost plants that are subject to weaker environmental standards 
could have a market advantage. NEPOOL Review Committee requests that 
the Commission not approve any market prices ``where the market into 
which the seller proposes to sell is not effectively competitive due to 
the absence of regional transmission products and prices.''<SUP>143
---------------------------------------------------------------------------

    \143\ NEPOOL Review Committee Initial Comments at 28.
---------------------------------------------------------------------------

Commission Conclusion
    While the Commission expects this Rule to facilitate the 
development of competitive bulk power markets, we find that there is 
not enough evidence on the record to make a generic determination about 
whether market power may exist for sales from existing generation. We 
continue to have concerns about how to define the relevant markets and 
believe that a more rigorous analysis is needed than can be achieved 
with the limited market data that is now available. We will continue 
our case-by-case approach that allows market-based rates based on an 
analysis of generation market power in first tier and second tier 
markets.<SUP>144 In particular cases, however, the effect of the 
mandatory open access prescribed by this Final Rule may lead to the 
consideration of geographic markets for the applicant's generation 
products that are broader in scope than the first-tier and second-tier 
markets currently considered.<SUP>145 By the same token, in some cases, 
evidence of the effects of transmission constraints may circumscribe 
the scope of the relevant geographic market for the applicant's 
generation products.
---------------------------------------------------------------------------

    \144\ See, e.g., Southwestern Public Service Company, 72 FERC 
para. 61,208 at 61,996 (1995).
    \145\ The Commission's practice is to define the relevant 
markets as those utilities directly interconnected to the applicant 
(first-tier markets). For each first-tier market, we consider all 
utilities interconnected to the first-tier utility and all utilities 
interconnected to the applicant as competitors in that relevant 
market. Thus, the competitors include the second-tier utilities 
directly interconnected to the relevant market and those other 
first-tier utilities that can reach the market by virtue of the 
applicant's open access transmission tariff. See, e.g., Kansas City 
Power & Light Company, 67 FERC para. 61,183 at 61,556; and Heartland 
Energy Services, Inc., 68 FERC para. 61,223 at 62,061.
---------------------------------------------------------------------------

    While we will continue to apply the first-tier/second-tier 
analysis, we will allow applicants and intervenors to challenge the 
presumption implicit in the Commission's practice that the relevant 
geographic market is bounded by the second-tier utilities. Thus, for 
instance, applicants may present evidence that the relevant market is 
in fact broader than the first or second tier. In support of such a 
contention, an applicant would need to show more than the existence of 
open access. For example, an applicant might attempt to demonstrate the 
lack of significant transmission constraints in the more broadly 
defined market and that cumulative transmission rates would not 
significantly affect the ability of more distant suppliers to compete 
in the relevant market. Similarly, an intervenor may present evidence 
that, due to the existence of significant transmission constraints 
within the first- and second-tier markets, the relevant market is in 
fact more limited in scope.<SUP>146
---------------------------------------------------------------------------

    \146\ See Wisconsin Public Service Corporation, 75 FERC para. 
61, ______, slip op. at 6-7 (1996).
---------------------------------------------------------------------------

    Finally, we will maintain our current practice of allowing market-
based rates for existing generation to go into effect subject to 
refund. To the extent that either the applicant or intervenors in 
individual cases offer specific evidence that the relevant geographic 
market ought to be defined differently than under the existing test, we 
will examine such arguments through formal or paper hearings.
    Because our goal is to develop more competitive bulk power markets, 
we will continue to monitor markets to assess the competitiveness of 
the market in existing generation, and we will modify our market rate 
criteria if and when appropriate. However, any changes we might make to 
our analysis for authorizing market-based rates in the future will not 
upset transactions entered into pursuant to existing market-based rate 
authority. The policies we put in place today to develop a smoothly 
functioning transmission access regime will provide useful experience 
and information for assessing the effects of generation concentration.
4. Merger Policy
    In the NOPR, the Commission did not address possible ramifications 
of the NOPR with regard to its existing merger policy.
Comments
    A number of commenters suggest that the Commission should 
reevaluate its merger policy in light of the NOPR.<SUP>147 They further 
suggest a number of changes that they believe need to be made to the 
Commission's existing merger policy.
---------------------------------------------------------------------------

    \147\ E.g., NRECA, TAPS, Wisconsin Coalition, APPA.
---------------------------------------------------------------------------

    Most commenters raising this issue express concerns that mergers 
will lessen competition and hinder achievement of competitive bulk 
power markets.<SUP>148 For example, NRECA indicates that the 
Commission's merger policy is at a crossroads. It believes that it is 
essential for the Commission to reevaluate its merger policy in concert 
with the proposed rulemakings.<SUP>149 Similarly, TAPS recommends that 
the Commission reevaluate its merger criteria to ensure that in a more 
competitive era, mergers are found to be consistent with the public 
interest only if they are pro-competitive. Several commenters argue 
that the Commission should continue to conduct a case-by-case 
investigation of the product and geographic markets that will be 
affected by a proposed merger.<SUP>150
---------------------------------------------------------------------------

    \148\ E.g., Wisconsin, Rosebud, NRECA, IN Com, Wisconsin 
Coalition, NIEP, Minnesota P&L, APPA.
    \149\ See also APPA.
    \150\ E.g., Wisconsin Coalition, MMWEC.
---------------------------------------------------------------------------

    A number of commenters also suggest certain changes that they would 
like to see in the Commission's merger policy.<SUP>151 APPA recommends 
that, at a minimum, all merger approvals considered by the Commission 
should be conditioned on: (1) Filing an open access transmission 
tariff, (2) demonstrating no market power in generation or ancillary 
services, and (3) granting all existing requirements customers of the 
merged entity the right to convert existing contracts to rights to 
equivalent transmission capacity. Several commenters suggest adopting 
the U.S. Department of Justice Merger

[[Page 21556]]

Guidelines in analyzing merger proposals.<SUP>152
---------------------------------------------------------------------------

    \151\ E.g., APPA, Wisconsin Coalition, Minnesota P&L, IN Com.
    \152\ E.g., Wisconsin Coalition.
---------------------------------------------------------------------------

    Environmental Action and others contend that merging utilities must 
be required to demonstrate real net benefits to retail and wholesale 
customers that could not otherwise be achieved but for the proposed 
merger.<SUP>153
---------------------------------------------------------------------------

    \153\ E.g., TAPS, Wisconsin Coalition.
---------------------------------------------------------------------------

    Commenters also argue that the Commission should use its merger 
conditioning authority to order divestiture of transmission and 
generation when required to ensure competition.<SUP>154 Environmental 
Action and NEPOOL Review Committee suggest conditioning merger 
applications on the existence of regional transmission pricing 
arrangements to mitigate any generation market power gained by the 
merging entities.
---------------------------------------------------------------------------

    \154\ E.g., NIEP, Wisconsin Coalition, TAPS, Environmental 
Action.
---------------------------------------------------------------------------

Commission Conclusion
    The Commission appreciates the concerns and suggestions raised with 
respect to our merger policy. However, since the time the NOPR was 
issued (and comments received thereon), we issued a Notice of Inquiry 
on the Commission's merger policy in Docket No. RM96-6-000.<SUP>155 
There we indicated that we will review whether our criteria and 
policies for evaluating mergers need to be modified in light of the 
changing circumstances, including this final rule, that are occurring 
in the electric industry. The NOI proceeding will permit us to consider 
comments from all interested participants and, at the same time, allow 
us to review our merger criteria and policies in light of this final 
rule. We are committed to reviewing our merger policy in a timely 
manner in the ongoing NOI proceeding.<SUP>156
---------------------------------------------------------------------------

    \155\ FERC Stats. & Regs. para. 35,531 (1996).
    \156\ Our decision to review our merger policy in a separate NOI 
proceeding is not intended to affect a utility's business decision 
of whether a merger may be in the economic interest of its 
ratepayers and stockholders. The NOI proceeding will not prevent us 
from reviewing merger applications in as timely a manner as 
possible.
---------------------------------------------------------------------------

5. Contract Reform
    In the NOPR, the Commission explained that it believed that it 
could remedy unduly discriminatory practices and achieve more 
competitive bulk power markets without abrogating existing wholesale 
power supply contracts that bundle generation and transmission services 
and existing wholesale transmission contracts.<SUP>157 Thus, we 
proposed to apply the functional unbundling requirement only to 
transmission services under new requirements contracts, new 
coordination contracts, and new transactions under existing 
coordination contracts. However, the Commission did invite comment on 
whether it would be contrary to the public interest to allow all or 
some of the above types of existing contracts to remain in effect.
---------------------------------------------------------------------------

    \157\ FERC Stats. & Regs. para. 32,514 at 33,093.
---------------------------------------------------------------------------

Comments
Requirements and Transmission Contracts
    Many of the commenters (including utility customers and third-party 
power suppliers) addressing this issue oppose abrogating existing 
contracts on a generic basis.<SUP>158 A number of the commenters 
contend that existing contracts should be retained because they are the 
result of mutually beneficial bargaining.<SUP>159 SMUD and TANC are 
concerned that existing contracts providing for transmission service 
that is superior to the pro forma tariffs not be abrogated.<SUP>160 
Ohio Edison argues that existing contracts have contributed to the 
emergence of competition, meet the specific needs of the parties, have 
been approved by the Commission, and have not been found to be unduly 
discriminatory or violative of the public interest, and that their 
preservation is consistent with the Energy Policy Act, most notably 
amended section 211 of the FPA. PacifiCorp and AEP express concern that 
contract abrogation would create competitive instability. American 
Forest & Paper argues that the Commission cannot refuse to honor 
existing contracts if it expects a competitive bulk power market to 
emerge.
---------------------------------------------------------------------------

    \158\ E.g., Dayton P&L, NSP, Montaup, Southwestern, Ohio Edison, 
Consumers Power, Allegheny, Public Generating Pool, NEPCO, 
Pennsylvania P&L, Southwest TDU Group, Arizona, DOD, El Paso, 
Florida Power Corp, AEC & SMEPA, Atlantic City, Texaco, Tampa, CSW, 
Central Illinois Public Service, CA Cogen, ConEd, GA Com, 
Consolidated Natural Gas, Ohio Valley, Pacific Northwest Coop, Salt 
River, Oglethorpe, Minnesota P&L, NYSEG, Brazos, Southern, 
Washington Water Power, CINergy, SoCal Edison, Hoosier EC.
    \159\ E.g., AEC & SMEPA, Cajun, Carolina P&L, NSP, Pennsylvania 
P&L, UNITIL, Southwestern, CSW.
    \160\ See also Dairyland, DE Muni, Arkansas Cities, Ohio Valley.
---------------------------------------------------------------------------

    Numerous commenters further argue that contract abrogation requires 
a fact-based, contract-specific evaluation, and they oppose any generic 
declaration that existing contracts are contrary to the public 
interest.<SUP>161 Some suggest that generic contract abrogation cannot 
be justified under the public interest standard.<SUP>162
---------------------------------------------------------------------------

    \161\ E.g., AEP, Associated EC, DOD, El Paso, NEPCO, Ohio 
Edison, PSNM, Southwest TDU Group, Utilities For Improved 
Transition, NYSEG, Citizens Utilities, NM Com, EGA. See also NRECA, 
TDU Systems, Blue Ridge, CCEM, Industrial Energy Applications, APPA, 
Cajun, Springfield, DE Muni, Missouri Basin MPA, TANC, Wolverine 
Coop Members, FL Com, Citizens Utilities, Soyland (support contract 
abrogation on a case-by-case basis).
    \162\ E.g., Utilities For Improved Transition, NSP, 
Southwestern, DE Muni.
---------------------------------------------------------------------------

    Missouri Basin MPA argues that the Commission should allow 
abrogation of existing wholesale power and transmission arrangements if 
the customer can demonstrate the undue competitive disadvantage caused 
by the arrangement.
    A few commenters support some form of generic contract 
abrogation.<SUP>163 CCEM asserts that existing wholesale requirements 
customers must be given the right to convert to transmission service 
under non-discriminatory open access tariffs.<SUP>164 CCEM notes that 
this is the same relief from undue discrimination that the Commission 
afforded to pipeline customers in Order Nos. 436 and 500.<SUP>165 CCEM 
emphasizes that here, in contrast to what occurred in the gas industry, 
``[c]onversion rights should be understood as the logical  quid pro quo 
for introducing extra-contractual stranded-cost recovery rights into 
the wholesale requirements contracts of electric utilities.'' <SUP>166 
NRECA asserts that it would be unduly discriminatory to allow new 
transmission customers to use the open access transmission tariffs, but 
not allow existing customers the same access.<SUP>167
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    \163\ E.g., NRECA, CCEM, ELCON, DE Muni, Oglethorpe. Portland 
maintains that it would be in the public interest to abrogate 
existing contracts completely, but recommends that such action be 
taken only on a case-by-case basis.
    \164\ See also VT DPS, NYMEX.
    \165\ See also VT DPS, Portland.
    \166\ CCEM Initial Comments at 26. See also ELCON, VT DPS, Blue 
Ridge, NYMEX, OK Com, Missouri Basin MPA, Texas-New Mexico, TDU 
Systems.
    \167\ See also TDU Systems, Texas-New Mexico, TAPS, Wisconsin 
Municipals.
---------------------------------------------------------------------------

    TAPS says that if those who now have discriminatory contracts are 
forced to live with those contracts, a fully competitive market will be 
delayed considerably.<SUP>168 Moreover, TAPS argues, the Commission has 
a statutory duty to remedy the undue discrimination that it is only now 
recognizing. Even if the Commission will not abrogate these contracts 
across the board, TAPS asserts that we should use our section 206 
authority to do so on a contract-by-contract basis.
---------------------------------------------------------------------------

    \168\ See also NorAm. UtiliCorp argues that existing contracts 
should not be allowed to extend indefinitely (as through 
``evergreen'' clauses) without adopting comparability. See also 
Texaco, Wisconsin Municipals, Phelps Dodge.
---------------------------------------------------------------------------

    San Francisco requests that the Commission clarify that a holder of 
capacity rights under an existing

[[Page 21557]]

contract can extend contractual rights to transmission access at least 
coterminous with the life of the project and under a roll-over or 
renewal contract on the same basis as provided in the existing 
contract. Anoka EC proposes that when a wholesale purchaser's contract 
expires, it should have a right of first refusal to contract for the 
transmission capacity to which it previously had a right. Knoxville 
urges the Commission to require renegotiation of the notice and/or term 
of all existing contracts for which the voluntary termination period 
exceeds the time frame for implementation of the final rule.
    NEPCO suggests that we require existing power contracts that allow 
rate changes to be separated into their generation and transmission 
components, without otherwise disturbing their terms; this would allow 
comparisons between the transmission service the utility provides to 
its power customers and the service it offers to others.<SUP>169
---------------------------------------------------------------------------

    \169\ See also Industrial Energy Applications.
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Coordination Agreements
    CINergy argues that coordination agreements should not be excluded 
from the comparability standard and that the Commission should use its 
authority under section 206 to require amendments to such agreements, 
just as it did in Order 636 in requiring unbundling of pipeline supply 
contracts. CINergy suggests that public utilities should be given up to 
three years to file the amendments to avoid hardship on the industry 
and the Commission's staff. CINergy further asserts that future 
transactions conducted under coordination agreements should be 
unbundled and the transmission component subjected to the comparable 
transmission service requirement.
    Others argue that purchases under existing coordination agreements 
made on behalf of retail native load should not be unbundled.<SUP>170 
NY Com and IL Com recommend that proposed Sec. 35.28(c) be modified to 
state that the functional unbundling requirement ``exclude(s) those 
wholesale purchases made by the utility to serve existing or expected 
native retail load.''
---------------------------------------------------------------------------

    \170\ E.g., Con Ed, Detroit Edison, IL Com.
---------------------------------------------------------------------------

    Utilities For Improved Transition disagrees with the idea that new 
transactions under existing coordination agreements should be subject 
to the rule.<SUP>171 It argues that the sanctity of coordination 
contracts should be the same as for other contracts. Coordination 
contracts are not simply agreements to agree in the future, according 
to Utilities For Improved Transition; they set forth terms and rates 
and merely leave the timing of transactions to be resolved in the 
future. Moreover, it argues that the Commission has given no reason to 
abandon its practice of encouraging coordination sales by allowing 
price flexibility.
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    \171\ See also Utility Workers Union, VEPCO.
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Commission Conclusion
Requirements and Transmission Contracts
    We do not believe it is appropriate to order generic abrogation of 
existing requirements and transmission contracts. While the Commission 
did generically find it appropriate to modify natural gas contracts to 
complete the move to a competitive commodity market in natural gas, we 
face a different situation here. At the time the Commission addressed 
this situation in the natural gas industry, it was faced with shrinking 
natural gas markets, statutory escalations in natural gas ceiling 
prices under the Natural Gas Policy Act, and increased production of 
gas.<SUP>172 In other words, there was a market failure in the industry 
that required the extraordinary measure of generically allowing all 
customers to break their contracts with pipelines.
---------------------------------------------------------------------------

    \172\ See Pierce, Richard J., Reconstituting the Natural Gas 
Industry from Wellhead to Burnertip, 9 Energy L.J. 1 (1988).
---------------------------------------------------------------------------

    In contrast, there is no such market failure in the electric 
industry. Although changes in the industry have been and continue to be 
dramatic, we do not believe they compel generic abrogation of 
requirements and transmission contracts.<SUP>173
---------------------------------------------------------------------------

    \173\ In addition, we do not believe that unfavorable 
requirements contracts will derail the attainment of competitive 
wholesale power markets. Indeed, many of the commenters support this 
position and seek to retain their existing requirements contracts.
---------------------------------------------------------------------------

    While we have concluded that current conditions in the wholesale 
power market do not warrant the generic modification of requirements 
contracts, we conclude nonetheless that the modification of certain 
requirements contracts on a case-by-case basis may be appropriate. We 
conclude further that, even if customers under such contracts are bound 
by so-called Mobile-Sierra clauses, they nonetheless ought to have the 
opportunity to demonstrate that their contracts no longer are just and 
reasonable.
    The Commission finds that it would be against the public interest 
to permit a Mobile-Sierra clause in an existing wholesale requirements 
contract to preclude the parties to such a contract from the 
opportunity to realize the benefits of the competitive wholesale power 
markets. For purposes of this finding, the Commission defines existing 
requirements contracts as contracts executed on or before July 11, 
1994.<SUP>174 By operation of this finding, a party to a requirements 
contract containing a Mobile-Sierra clause no longer will have the 
burden of establishing independently that it is in the public interest 
to permit the modification of such contract. The party, however, still 
will have the burden of establishing that such contract no longer is 
just and reasonable and therefore ought to be modified.
---------------------------------------------------------------------------

    \174\ This is consistent with the definition of existing 
requirements contracts we have used for purposes of stranded cost 
recovery.
---------------------------------------------------------------------------

    This finding complements the Commission's finding that, 
notwithstanding a Mobile-Sierra clause in an existing requirements 
contract, it is in the public interest to permit amendments to add 
stranded cost provisions to such contracts if the public utility 
proposing the amendment can meet the evidentiary requirements of this 
Rule.<SUP>175 The Commission's complementary Mobile-Sierra findings are 
not mutually exclusive. Any contract modification approved under this 
Section shall provide for the utility's recovery of any costs stranded 
consistent with the contract modification. The stranded costs must be 
prudently incurred, legitimate and verifiable, as provided in Section 
IV.J. Further, the Commission has concluded that if a customer is 
permitted to argue for modification of existing contracts that are less 
favorable to it than other generation alternatives, then the utility 
should be able to seek modification of contracts that may be beneficial 
to the customer.
---------------------------------------------------------------------------

    \175\ See Section IV.J.5.
---------------------------------------------------------------------------

    The Commission believes that the most productive way to analyze 
contract modification issues is to consider simultaneously both the 
selling public utility's claims, if any, that it had a reasonable 
expectation of continuing to serve the customer beyond the term of the 
contract and the customer's claim, if any, that the contract no longer 
is just and reasonable and therefore ought to be modified. Thus, if the 
selling public utility intends to claim stranded costs, it must present 
that claim in any section 206 proceeding brought by the customer to 
shorten or terminate the contract. Similarly, if the customer intends 
to claim that the notice or termination provision of its existing 
requirements contract is unjust and unreasonable, it must present that 
claim in any proceeding brought by the selling public utility to seek 
recovery of stranded

[[Page 21558]]

costs. This will promote administrative efficiency and will permit the 
Commission to consider how the contracting parties' claims bear on one 
another.
    The Commission does not take contract modification lightly. Whether 
a utility is seeking a contract amendment to permit stranded cost 
recovery based on expectations beyond the stated term of the contract, 
or a customer is seeking to shorten or eliminate the term of an 
existing contract, we believe that each has a heavy burden in 
demonstrating that the contract ought to be modified. Still, we believe 
that given the industry circumstances now facing us, both selling 
utilities and their customers ought to have an opportunity to make the 
case that their existing requirements contracts ought to be modified. 
By providing both buyers and sellers this opportunity, the Commission 
attempts to strike a reasonable balance of the interests of all market 
participants. The Commission expects that many of the arguments 
presented by buyers and sellers in such proceedings will be fact 
specific.
    We note that because we are not abrogating existing requirements 
and transmission contracts generically and because the functional 
unbundling requirement of the Final Rule applies only to new wholesale 
services, the terms and conditions of the Final Rule pro forma tariff 
do not apply to service under existing requirements contracts. However, 
if a customer's existing bundled service (transmission and generation) 
contract or transmission-only contract expires, and the customer takes 
any new transmission service from its former supplier, the terms and 
conditions of the Final Rule tariff would then apply to the 
transmission service that the customer receives.
    A further issue concerning firm contract customers is their right 
to transmission capacity (and the rate for such capacity) when their 
contracts expire by their own terms or become subject to renewal or 
rollover. We have concluded that all firm transmission customers 
(requirements and transmission-only), upon the expiration of their 
contracts or at the time their contracts become subject to renewal or 
rollover, should have the right to continue to take transmission 
service from their existing transmission provider. The limitations are 
that the underlying contract must have been for a term of one-year or 
more and the existing customer must agree to match the rate offered by 
another potential customer, up to the transmission provider's maximum 
filed transmission rate at that time, and to accept a contract term at 
least as long as that offered by the potential customer.<SUP>176 This 
means that there is no right to grandfather the historical price of the 
transmission service. Thus, if not enough capacity is available to meet 
all requests for service, the right of first refusal gives the capacity 
to the existing customer who had contractually been using the capacity 
on a long-term, firm basis, assuming that it meets the conditions set 
forth above. Moreover, this limited right of first refusal is not a 
one-time right of first refusal for contracts existing as of the date 
of the final rule, but is an ongoing right that may be exercised at the 
end of all firm contract (including all future unbundled transmission 
contracts) terms. A customer converting existing bundled service to the 
Final Rule pro forma tariff would not have a reservation priority for 
capacity expansions, unless the existing contract provides for future 
transmission to the customer that requires capacity expansion.<SUP>177
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    \176\ This right of first refusal exists whether or not the 
customer buys power from the historical utility supplier or another 
power supplier. If the customer chooses a new power supplier and 
this substantially changes the location or direction of its power 
flows, the customer's right to continue taking transmission service 
from its existing transmission provider may be affected by 
transmission constraints associated with the change.
    \177\ The above discussion on a right of first refusal addresses 
firm contract customers. However, the same logic applies to retail 
customers.
---------------------------------------------------------------------------

    Finally, with respect to all existing requirements contracts and 
tariffs that provide for bundled rates, we will require all public 
utilities to make informational filings setting forth the unbundled 
power and transmission rates reflected in those contracts and tariffs. 
These informational rates must be submitted to the Commission within 60 
days of publication of the Final Rule in the Federal Register and must 
also be included as a line item on all bills submitted to wholesale 
customers in the third month following the effective date of this final 
rule. The unbundled informational rates will permit wholesale customers 
to compare rates in anticipation of their contracts expiring so that 
they can evaluate alternative contracts.
Coordination Agreements
    The situation as to coordination agreements requires a slightly 
different approach.<SUP>178 While we also believe that as a general 
matter it is important not to generically abrogate any coordination 
agreements, this is particularly true for non-economy energy 
coordination agreements that may reflect complementary long-term 
obligations among the parties. This type of agreement presents special 
problems and, as discussed below, we will not generically require this 
type of coordination agreement to be modified.<SUP>179
---------------------------------------------------------------------------

    \178\ For purposes of this discussion, we define coordination 
agreements as all power sales agreements, except requirements 
service agreements. In addition, for purposes of implementing the 
non-discriminatory, open access requirements of the Final Rule, we 
are dividing bilateral coordination agreements into two general 
categories: (1) Economy energy coordination agreements are contracts 
and service schedules thereunder that provide for trading of 
electric energy on an ``if, as, and when available'' basis, but do 
not require either the seller or buyer to engage in a particular 
transaction; and (2) non-economy energy coordination agreements are 
any non-requirements service agreements, except economy energy 
coordination agreements.
    \179\ The requirements for power pools and other multilateral 
arrangements are discussed in detail in Section IV.F.
---------------------------------------------------------------------------

    Hundreds of coordination agreements exist in the industry today. 
Many are open-ended agreements that permit new transactions to occur 
well into the future. Because these contracts may not expire of their 
own terms in a reasonable time, they may present a larger and more 
enduring obstacle to non-discriminatory open access and more 
competitive bulk power markets. Thus, to assure that non-discriminatory 
open access becomes a reality in the relatively near future, we will 
partially modify existing economy energy coordination agreements. We 
will condition future sales and purchase transactions under existing 
economy energy coordination agreements <SUP>180 to require that the 
transmission service associated with those transactions be provided 
pursuant to this Rule's requirements of non-discriminatory open access, 
no later than December 31, 1996.<SUP>181 We also will require that for 
new economy energy coordination agreements <SUP>182 where the 
transmission owner uses its transmission system to make economy energy 
sales or purchases, the transmission owner must take such service under 
its own transmission tariff as of the date trading begins under the 
agreement.<SUP>183
---------------------------------------------------------------------------

    \180\ Those executed prior to 60 days after publication of the 
Open Access Rule in the Federal Register.
    \181\ The requirement to unbundle future transactions under 
existing economy energy coordination agreements means that if the 
transmission owner uses its transmission system to make economy 
energy coordination sales or purchases, it must take service for 
these transactions under its own transmission tariff after December 
31, 1996.
    \182\ Those executed 60 days after publication of the Open 
Access Rule in the Federal Register.
    \183\ Accordingly, transmission service needed for sales or 
purchases under all new economy energy coordination agreements will 
be pursuant to the Final Rule pro forma tariff.

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[[Page 21559]]

    Finally, we will treat non-economy energy coordination agreements 
differently. We will not require their modification. However, this does 
not insulate such agreements from complaints that transmission service 
provided under such agreements be provided pursuant to the Final Rule 
pro forma tariff.
    With respect to coordination pricing practices, we conclude that 
non-discriminatory open access consistent with the requirements of this 
Rule is necessary if we are to allow utilities to continue to use 
market-driven pricing, such as split-the-savings pricing, for 
coordination sales. Absent such non-discriminatory open access, a 
utility would be able to deny access to others so as to obtain a higher 
price for its own power sales.
6. Flow-Based Contracting and Pricing
    In the NOPR, the Commission discussed the procedures to be used in 
establishing Stage One rates. These Stage One rates were proposed as an 
administrative convenience. The proposal merely followed the long-
established practice of establishing rates on the basis of contract 
path pricing.<SUP>184 The Commission made no determination with respect 
to the appropriateness of flow-based pricing or contracting for other 
purposes.<SUP>185
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    \184\ A contract path is simply a path that can be designated to 
form a single continuous electrical path between the parties to an 
agreement. Because of the laws of physics, it is unlikely that the 
actual power flow will follow that contract path.
    \185\ Flow-based pricing or contracting would be designed to 
account for the actual power flows on a transmission system. It 
would take into account the ``unscheduled flows'' that occur under a 
contract path regime.
---------------------------------------------------------------------------

Comments
    Most of the commenters addressing this issue recommend that 
industry or the Commission--either in this rule or ultimately--dispense 
with the traditional contract path basis for pricing and contracting. 
Most commenters also recommend that the Commission adopt or encourage a 
regional approach to the solution of transmission pricing problems, 
though they differ markedly in how to account for flows.<SUP>186
---------------------------------------------------------------------------

    \186\ E.g., APPA, TAPS, NY Energy Buyers, Arcadia, Brownsville, 
Detroit Edison Customers, AMP-Ohio, Michigan Systems.
---------------------------------------------------------------------------

    Transmission customers generally seek to rid themselves of 
``pancaked'' transmission rates that are associated with the 
traditional approach to transmission pricing.<SUP>187 They propose the 
development of regionwide transmission rates, perhaps determined on a 
pool or RTG basis. Most, however, do not discuss how to account for 
unscheduled flows.<SUP>188
---------------------------------------------------------------------------

    \187\ E.g., AMP-Ohio, NRECA, APPA, Detroit Edison Wholesale 
Customers, MMWEC, Missouri Basin MPA, Air Liquide, American Wind 
Energy, Associated Power, CCEM.
    \188\ Some commenters propose the development of a regional rate 
on a postage stamp basis, without regard to distance travelled or 
the actual path of power flows. E.g., Air Liquide, American National 
Power, CA Energy Co. Several commenters do, however, propose ways to 
account for unscheduled flows. E.g., American Forest & Paper, DE 
Muni, Lower Colorado River Authority.
---------------------------------------------------------------------------

    Many transmission providers, some regulatory authorities, and some 
individuals strongly support flow-based pricing. Most of these 
commenters recognize a need for a regional approach to resolve 
transmission pricing concerns.<SUP>189 However, many of them also 
appear to accept contract pricing in the near term because of the need 
to implement open access quickly.<SUP>190 NERC recommends that the 
Commission maintain an open position on the transfer scheduling process 
and supports changes in the process to reflect actual power flows. EEI 
suggests that the Commission should be willing to deviate from a 
contract path approach, since competition may be accompanied by greater 
unscheduled flows and contract pricing is not well equipped to deal 
with such flows. However, EEI concludes that a single approach to 
pricing will not be appropriate for all systems.
---------------------------------------------------------------------------

    \189\ E.g., CSW, EDS Utilities, Dominion, CINergy, KS Com, CT 
DPUC, Com Ed, Hogan.
    \190\ NYMEX favors contract path pricing because of its 
familiarity and believes that the issue should primarily be resolved 
by the transmitting utilities. AEP believes that the primary 
responsibility lies with industry to develop alternative pricing 
structures.
---------------------------------------------------------------------------

    Other commenters, however, do raise concerns with respect to flow-
based pricing. AEC & SMEPA considers flow-based pricing to be flawed 
because that method makes an individual customer responsible for load 
flow effects caused by a third party's development of the third-party's 
transmission system over which the customer and its transmission 
provider had no control. Dayton P&L fears that competition would be 
lessened under flow-based pricing because utilities with large 
transmission systems would dominate the market.
    Several commenters oppose Southern's and United Illuminating's 
flow-based proposals, arguing that the methodologies are based on 
estimates of actual flows or a set of conditions with limited 
applicability. Various commenters also believe that a single rate is 
flawed and could cause just as many problems as contract path 
pricing.<SUP>191
---------------------------------------------------------------------------

    \191\ E.g., NU, NEPCO, BECO, Florida Power Corp.
---------------------------------------------------------------------------

    Most commenters appear to believe that the Commission endorsed 
contract path pricing in the NOPR. Hogan expresses concern that many 
industry participants' understanding of the pro forma tariffs is based 
on the fiction of the contract path. The MT Dept of Environmental 
Quality believes that despite the Commission's pledge to consider 
innovative pricing proposals,<SUP>192 such proposals will receive heavy 
scrutiny, while conventional contract path pricing proposals will 
receive nearly automatic approval. Dominion is concerned that relying 
on the initiative of individual transmission owners to develop flow-
based pricing will yield slow and patchy results.
---------------------------------------------------------------------------

    \192\ See FERC Stats. & Regs. para. 31,005.
---------------------------------------------------------------------------

Commission Conclusion
    We will not, at this time, require that flow-based pricing and 
contracting be used in the electric industry. In reaching this 
conclusion, we recognize that there may be difficulties in using a 
traditional contract path approach in a non-discriminatory open access 
transmission environment, as described by Hogan and others. At the same 
time, however, contract path pricing and contracting is the 
longstanding approach used in the electric industry and it is the 
approach familiar to all participants in the industry. To require now a 
dramatic overhaul of the traditional approach--such as a shift to some 
form of flow-based pricing and contracting--could severely slow, if not 
derailed for some time, the move to open access and more competitive 
wholesale bulk power markets. In addition, we believe it is premature 
for the Commission to impose generically a new pricing regime without 
the benefit of any experience with such pricing. We welcome new and 
innovative proposals, but we will not impose them in this Rule.
    While we are not requiring the use of any form of flow-based 
pricing, we recognize that some versions of flow-based pricing could 
have benefits. For example, some versions of flow-based pricing could 
more accurately reflect and price the actual power flows on 
transmission systems and thus could produce efficiency gains, better 
generation siting decisions, and benefits for customers and utilities 
alike. Other versions could more accurately assign capacity rights in 
accordance with a party's contribution to capacity costs.
    These potential benefits, however, will not simply come about in 
the abstract. Flow-based pricing methodologies that will achieve the 
benefits sought by most of the

[[Page 21560]]

participants in the industry are in a development stage and require 
further work and refinement to address some of the difficulties 
associated with flow-based approaches. Concurrent work on OASIS and 
resolving available transmission capability issues may help resolve 
flow-based issues. However, as demonstrated by the paucity of possible 
methodologies presented in the comments, developing workable 
methodologies will be difficult. As we explained in our Transmission 
Pricing Policy Statement, we are receptive to proposals for alternative 
rate methodologies, such as distance-sensitive and flow-based pricing, 
as long as the proposals are well supported. However, we have yet to 
receive a formal rate application for a flow-based pricing methodology 
that has been tested enough that it can be required on a generic basis. 
Thus, we have decided to go forward to achieve open access and more 
competitive wholesale bulk power markets without waiting for the 
development of a generic flow-based pricing methodology.
    We wish to emphasize further that in taking this approach we are 
not endorsing the traditional contract path approach as the only 
available approach. We continue to approve contract path pricing 
because it is the long-established pricing method that comes to us in 
rate filings by the electric industry, is administratively convenient 
and feasible, and thus is a practical way to move forward now. We 
remain open to alternative methodologies, but need to see better 
developed approaches from the industry before we can consider generic 
adoption of alternative pricing.
    We also believe the adoption of flow-based pricing will be more 
practical on a regional, instead of individual utility, basis. Some 
forms of flow-based pricing may even require a regional approach. To 
this extent, regional ISOs could be a valuable mechanism for 
implementing such pricing reforms.

B. Legal Authority

    The Commission reaffirms its conclusion in the NOPR that we have 
the authority under the FPA to order wholesale transmission services in 
interstate commerce to remedy undue discrimination by public utilities. 
We analyze below the relevant cases examining our wheeling authority, 
then discuss and respond to the legal arguments raised by the 
commenters.
1. Bases for Legal Authority
a. Undue Discrimination/Anticompetitive Effects
    In upholding the Commission's order requiring non-discriminatory 
open access in the natural gas industry, the court in Associated Gas 
Distributors v. FERC stated that the Natural Gas Act ``fairly 
bristles'' with concern for undue discrimination.<SUP>193 The same is 
true of the FPA. 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. 
As discussed below, AGD demonstrates that our remedial power is very 
broad and includes the ability to order industry-wide non-
discriminatory open access <SUP>194 as a remedy for undue 
discrimination. The AGD court reached this decision even in the face of 
prior cases that acknowledged that Congress did not mandate common 
carriage or explicitly empower the Commission to order direct access 
for either gas transporters or electric utilities. Moreover, the 
Commission's power under the FPA ``clearly carries with it the 
responsibility to consider, in appropriate circumstances, the 
anticompetitive effects of regulated aspects of interstate utility 
operations pursuant to (FPA) sections 202 and 203, and under like 
directives contained in sections 205, 206, and 207.'' <SUP>195
---------------------------------------------------------------------------

    \193\ Associated Gas Distributors v. FERC, 824 F.2d 981, 998 
(D.C. Cir. 1987), cert. denied, 485 U.S. 1006 (1988) (AGD).
    \194\ We use the term ``open access'' to refer to a public 
utility's obligation to put a tariff on file offering service to 
eligible customers. Access is not open to all. Specifically, the 
tariff is not an offer to serve retail customers if state law does 
not permit retail wheeling.
    \195\ Gulf States Utilities Company v. FPC, 411 U.S. 747, 758-59 
(1973).
---------------------------------------------------------------------------

    Therefore, based on the mandates of sections 205 and 206 of the FPA 
and the case law interpreting the Commission's authority over 
transmission in interstate commerce, we conclude that we have ample 
legal authority--indeed, a responsibility--under section 206 of the FPA 
to order the filing of non-discriminatory open access transmission 
tariffs if we find such order necessary as a remedy for undue 
discrimination or anticompetitive effects.<SUP>196 We discuss below the 
primary court decisions that touch on our wheeling authority under 
sections 205 and 206.
---------------------------------------------------------------------------

    \196\ In most situations, discrimination that precludes 
transmission access or gives inferior access will have at least 
potential anticompetitive effects because it limits access to 
generation markets and thereby limits competition in generation. 
Similarly, it is probable that any transmission provision that has 
anticompetitive effects would also be found to be unduly 
discriminatory or preferential because the anticompetitive provision 
would most likely favor the transmission owner vis-a-vis others.
---------------------------------------------------------------------------

    The Commission's authority to order access as a remedy for undue 
discrimination under the Natural Gas Act (NGA) was upheld and discussed 
in detail in AGD. In AGD, the court upheld in relevant part the 
Commission's Order No. 436.<SUP>197 That order found the prevailing 
natural gas company practices to be ``unduly discriminatory'' within 
the meaning of section 5 of the NGA (the parallel to section 206 of the 
FPA) and held that if pipelines wanted blanket certification for their 
transportation services, they must commit to transport gas for others 
on a non-discriminatory basis; in other words, they must provide non-
discriminatory open access.
---------------------------------------------------------------------------

    \197\ Order No. 436, Regulation of Natural Gas Pipelines After 
Partial Wellhead Decontrol, FERC Stats. & Regs., Regulations 
Preambles para. 30,665 (1985).
---------------------------------------------------------------------------

    In upholding the Commission's authority to require open access, the 
court first noted that the opponents' arguments against such authority 
must proceed ``uphill.'' The statute contains no language forbidding 
the Commission to impose common carrier status on pipelines, let alone 
forbidding the Commission to impose ``a specific duty that happens to 
be a typical or even core component of such status.'' The court found 
that the legislative history cited by the opponents came nowhere near 
overcoming this statutory silence. Rather, the legislative history 
supported only the proposition that Congress itself declined to impose 
common carrier status.<SUP>198 Emphasizing Congress' deep concern with 
undue discrimination, the court found that the Commission had ample 
authority to ``stamp out'' such discrimination:

    \198\ AGD, supra, 824 F.2d at 997.
---------------------------------------------------------------------------

    The issue seems to come down to this: Although Congress 
explicitly gave the Commission the power and the duty to achieve one 
of the prime goals of common carriage regulation (the eradication of 
undue discrimination), the Commission's attempted exercise of that 
power is invalid because Congress in 1906 and 1914 and 1935 and 1938 
itself refrained from affixing common carrier status directly onto 
the pipelines and from authorizing the Commission to do so.

[[Page 21561]]

And this proposition is said to control no matter how sound the 
Order may be as a response to the facts before the Commission. We 
think this turns statutory construction upside down, letting the 
failure to grant a general power prevail over the affirmative grant 
of a specific one.<SUP>199
---------------------------------------------------------------------------

    \199\ Id. at 998.

The AGD court found that court decisions under the FPA did not support 
the view that the Commission's authority to ``stamp out'' undue 
discrimination is hamstrung by an inability to require non-
discriminatory open access as a remedy. These decisions are discussed 
below.
    One of the earliest cases on wheeling is Otter Tail Power Company 
v. United States (Otter Tail).<SUP>200 In that case, the Supreme Court 
rejected the argument that the District Court, in a civil antitrust 
suit, could not order wheeling because to do so would conflict with the 
FPC's purported wheeling authority.<SUP>201 The Court explained that 
Congress had decided not to impose a common carrier obligation on the 
electric power industry and noted that the Commission was not at that 
time expressly granted power to order wheeling.<SUP>202 In effect, it 
concluded that because Congress did not include common carrier 
provisions in the FPA, the Commission must not have any express 
authority to order wheeling that would preclude the District Court from 
imposing a wheeling remedy. Nowhere, however, did the Court say that 
the Commission lacked authority under section 206 to remedy undue 
discrimination. Indeed, that was simply not a matter before the Court 
or of any consequence to its decision.
---------------------------------------------------------------------------

    \200\ 410 U.S. 366 (1974).
    \201\ 410 U.S. at 375-76.
    \202\ Id. at 374-76.
---------------------------------------------------------------------------

    In the FPA, while Congress elected not to impose common carrier 
status on the electric power industry, it tempered that determination 
by explicitly providing the Commission with the authority to eradicate 
undue discrimination--one of the goals of common carriage 
regulation.<SUP>203 By providing this broad authority to the 
Commission, it assured itself that in preserving ``the voluntary action 
of the utilities'' it was not allowing this voluntary action to be 
unfettered. It would be far-reaching indeed to conclude that Otter 
Tail, which was a civil antitrust suit that raised issues entirely 
unrelated to our authority under section 206, is an impediment to our 
achieving one of the primary goals of the FPA--eradicating undue 
discrimination in transmission in interstate commerce in the electric 
power industry.
---------------------------------------------------------------------------

    \203\ See AGD, 824 F.2d at 998.
---------------------------------------------------------------------------

    In Richmond Power & Light Company v. FERC (Richmond),<SUP>204 the 
FPC, in reaction to the 1973 oil embargo, was attempting to reduce 
dependence on oil. The FPC requested that utilities with excess 
capacity wheel power to the New England Power Pool (NEPOOL). In 
response, several suppliers and transmission owners filed rate 
schedules with the FPC that provided for voluntary wheeling. Richmond 
Power & Light Company (Richmond) objected to these filings, claiming 
that they were unreasonable because they did not guarantee transmission 
access. The FPC refused to compel the utilities to wheel Richmond's 
power, stating that it did not have the authority to order a public 
utility to act as a common carrier.
---------------------------------------------------------------------------

    \204\ 574 F.2d 610 (D.C. Cir. 1978).
---------------------------------------------------------------------------

    The D.C. Circuit upheld the Commission. It acknowledged that 
Richmond's argument was persuasive in some respects, but stated that 
any conditions the Commission might impose could not contravene the 
FPA. The court examined the legislative history of the FPA and stated 
that ``[i]f Congress had intended that utilities could inadvertently 
bootstrap themselves into common-carrier status by filing rates for 
voluntary service, it would not have bothered to reject mandatory 
wheeling * * *.'' <SUP>205
---------------------------------------------------------------------------

    \205\ Id. at 620.
---------------------------------------------------------------------------

    However, the D.C. Circuit in no way indicated that the Commission 
was foreclosed from ordering transmission as a remedy for undue 
discrimination. Richmond also had argued that the alleged refusal of 
the American Electric Power Company (AEP) and its affiliate, Indiana & 
Michigan Electric Company (Indiana), to wheel Richmond's excess energy 
was unlawful discrimination because AEP and Indiana wheeled higher-
priced electricity from other AEP affiliates. The court acknowledged 
that Richmond's claim of unlawful discrimination was theoretically 
valid, but found that Richmond had failed to prove its case. It noted 
that if Richmond had argued that the rates were unjustifiably 
discriminatory, or that Indiana's failure to use its transmission 
capability fully or to purchase less expensive electricity for wheeling 
resulted in unnecessarily high rates, a different case would be before 
the court.<SUP>206 The case thus does not in any way limit the 
Commission's authority to remedy undue discrimination.
---------------------------------------------------------------------------

    \206\ Id. at 623, nn.53 and 57.
---------------------------------------------------------------------------

    In Central Iowa Power Cooperative v. FERC,<SUP>207 the FPC <SUP>208 
reviewed the terms of the Mid-Continent Area Power Pool (MAPP) 
Agreement under its section 205 and 206 authority. The agreement 
contained two membership limitations. First, the agreement established 
two classes of membership, with one class being entitled to more 
privileges than the other. Second, the agreement excluded non-
generating distribution systems from pool services. The FPC found the 
first limitation on membership--the two-class system--to be unduly 
discriminatory and not reasonably related to MAPP's objectives. The FPC 
conditioned approval of the agreement under section 206 on the removal 
of the unduly discriminatory provision. The FPC found that the second 
limitation, the exclusion of non-generating distribution systems, was 
not anticompetitive and did not render the agreement inconsistent with 
the public interest.
---------------------------------------------------------------------------

    \207\ 606 F.2d 1156 (D.C. Cir. 1979).
    \208\ While Central Iowa was pending, certain of the functions 
of the FPC were transferred to the FERC under the DOE Organization 
Act. Accordingly, the FERC was substituted for the FPC as the 
respondent in the case.
---------------------------------------------------------------------------

    On appeal, the D.C. Circuit affirmed the FPC's decision. The court 
found that the FPC did have authority to order changes in the scope of 
the MAPP agreement, if the agreement was unjust, unreasonable, unduly 
discriminatory or preferential under section 206 of the FPA. The court 
stated:

    The Commission had authority, * * * under section 206 of the 
Act, * * * to order changes in the limited scope of the Agreement, 
including the addition of pool services, if, in the absence of such 
modifications, the Agreement presented ``any rule, regulation, 
practice or contract (that was) unjust, unreasonable, unduly 
discriminatory or preferential.'' <SUP>209
---------------------------------------------------------------------------

    \209\ 606 F.2d at 1168.

However, the court agreed with the FPC's conclusion that the limited 
scope of MAPP was not unjust, unreasonable, or unduly discriminatory. 
The court recognized that a pool was not invalid under section 206 
merely because a more comprehensive arrangement was possible.
    The D.C. Circuit upheld the Commission's refusal to eliminate the 
second limitation on membership by ordering MAPP participants to wheel 
to non-generating electric systems.<SUP>210 However, neither the 
Commission nor the court was presented with the argument that wheeling 
was necessary as a remedy for undue discrimination.
---------------------------------------------------------------------------

    \210\ Id. at 1169; see also Municipalities of Groton v. FERC, 
587 F.2d 1296 (D.C. Cir. 1978).

---------------------------------------------------------------------------

[[Page 21562]]

    In Florida Power & Light Company v. FERC (Florida),<SUP>211 the 
Commission ordered Florida Power & Light Company (FP&L) to file a 
tariff setting forth FP&L's policy relating to the availability of 
transmission service.<SUP>212 FP&L objected to including such a policy 
statement in its tariff and argued that the filing of such a policy 
would convert FP&L into a common carrier by obligating it to offer 
service to all customers.<SUP>213 There was no finding that the action 
ordered was necessary to remedy undue discrimination.
---------------------------------------------------------------------------

    \211\ 660 F.2d 668 (5th Cir. 1981), cert. denied sub nom. Fort 
Pierce Utilities Authority v. FERC, 459 U.S. 1156 (1983).
    \212\ FP&L provided transmission service when four conditions 
were met: (1) The specific potential seller and buyer were 
contractually identified; (2) the magnitude, time and duration of 
the transaction were specified prior to the commencement of the 
transmission; (3) it could be determined that the transmission 
capacity would be available for the term of the contract; and (4) 
the rate was sufficient to cover FP&L's costs.
    \213\ All utilities requesting wheeling services, subject to 
availability, would be entitled to receive transmission service 
under the filed terms. Any changes to a filed rate must be filed 
with the Commission. This is the so-called ``filed rate doctrine.'' 
See Northwestern Public Service Company v. Montana-Dakota Utilities 
Company, 181 F.2d 19, 22 (8th Cir. 1980), aff'd, 341 U.S. 246 
(1951).
---------------------------------------------------------------------------

    The Fifth Circuit Court of Appeals agreed with FP&L that the 
mandatory filing of the policy statement would require FP&L to provide 
transmission service beyond its voluntary commitment because such a 
requirement would change its duties and liabilities.<SUP>214 The 
Commission order would impose common carrier status on FP&L, the court 
found.<SUP>215 The court noted that the Commission did not rely on a 
finding of anticompetitive behavior and therefore the court did not 
address the Commission's power to remedy antitrust violations.<SUP>216
---------------------------------------------------------------------------

    \214\ Under the filed rate doctrine, a refusal to wheel would be 
unduly discriminatory under section 206 of the FPA. As the court 
acknowledged, a customer refused service could petition the 
Commission to find that FP&L's policy of availability was unduly 
discriminatory under section 206(a) of the FPA. The court said that 
in the absence of a tariff on file, a utility refused wheeling 
services would be unable to claim discrimination under section 
206(a) of the FPA. 660 F.2d at 675 (expressing ``serious doubts that 
such a petition would be successful in the absence of a tariff'').
    \215\ Id. at 676.
    \216\ Id. at 678.
---------------------------------------------------------------------------

    The AGD court explicitly rejected the claim that the above line of 
cases establishes that the Commission lacks authority to require non-
discriminatory open access.<SUP>217 Opponents of the Commission's order 
argued in AGD that Richmond and Florida, supra, stand for the 
proposition that the Commission cannot indirectly do what it allegedly 
cannot do directly, that is, impose common carriage. The AGD court 
rejected these arguments, stating that the petitioners read the 
electric cases far too broadly:

    \217\ The AGD court did not address New York State Electric & 
Gas Corporation v. FERC, 638 F.2d 388 (2d Cir. 1980), cert. denied, 
454 U.S. 821 (1981) (NYSEG), presumably because that case did not 
concern whether the Commission could order wheeling as a remedy for 
undue discrimination.
---------------------------------------------------------------------------

(n)either Richmond nor Florida comes anywhere near stating that the 
Commission is barred from imposing an open-access condition in all 
circumstances.<SUP>218
---------------------------------------------------------------------------

    \218\ 824 F.2d at 999.

The court noted that the Florida case had expressly left open the 
question of whether the Commission would be entitled to use an open 
access condition as a remedy for anticompetitive conduct, and that in 
Richmond the D.C. Circuit had said little more than that unwillingness 
to transmit for all could not be automatically deemed undue 
discrimination. The court also noted the Central Iowa case, supra, in 
which it had upheld a Commission order that found a power pooling 
agreement discriminatory on its face because the agreement gave one 
class of membership privileged status over another. The court stated 
that the Central Iowa case ``upholds the power of the Commission to 
subject approval of a set of voluntary transactions to a condition that 
providers open up the class of permissible users.'' <SUP>219 The court 
added that it refused to ``turn statutory construction upside down'' by 
letting Congress' failure to grant a general power of common carriage 
prevail over the affirmative grant of the specific power to eradicate 
undue discrimination.<SUP>220
---------------------------------------------------------------------------

    \219\ Id. at 999.
    \220\ Id. at 1006.
---------------------------------------------------------------------------

    We conclude that AGD's analysis of undue discrimination under 
sections 4 and 5 of the Natural Gas Act is equally applicable to an 
undue discrimination analysis under sections 205 and 206 of the FPA. 
The Commission and courts have long recognized that the NGA was 
patterned after the FPA and that the two statutes should be interpreted 
in the same manner.<SUP>221 Thus, we conclude that we have the 
authority to remedy undue discrimination and anticompetitive effects by 
requiring all public utilities that own, control or operate 
transmission facilities to file non-discriminatory open access 
transmission tariffs.
---------------------------------------------------------------------------

    \221\ See, e.g., FPC v. Sierra Pacific Power Company, 350 U.S. 
348, 353 (1956); Arkansas Louisiana Gas Company v. Hall, 453 U.S. 
571, 577 n.7 (1981); and Kentucky Utilities Company v. FERC, 760 
F.2d 1321, 1325 n.6 (D.C. Cir. 1985). Section 206 of the FPA was 
recently revised and now differs from section 5 of the NGA, but not 
in a manner significant to our discussion here. See 16 U.S.C. 824e 
(b) and (c).
---------------------------------------------------------------------------

b. Section 211 of the Federal Power Act
    In concluding that we must invoke our section 206 authority to 
remedy undue discrimination and anticompetitive effects in the electric 
industry, we have carefully considered the goals of Title VII of the 
Energy Policy Act, and whether section 211 of the FPA, by itself, is 
sufficient to remedy undue discrimination in public utility 
transmission services. Title VII of the Energy Policy Act, which 
amended section 211 of the FPA to give the Commission broader authority 
to order wheeling in the public interest on a case-by-case basis, 
reflects the intent of Congress to encourage competitive wholesale 
electric markets. Section 211 provides a means for wholesale power 
sellers and buyers to obtain transmission services necessary to compete 
in, or to reach, competitive markets, and is a valuable tool to 
encourage competitive markets. However, in amending section 211, 
Congress left unaltered the authorities and obligations of the 
Commission under sections 205 and 206 (similar to our authorities and 
obligations under sections 4 and 5 of the NGA) to remedy undue 
discrimination. In addition, as discussed below, reliance on section 
211 alone in some circumstances can result in the perpetuation of, 
rather than the elimination of, undue discrimination and 
anticompetitive effects.
    First, there are inherent delays in the procedures for obtaining 
service under section 211. However, for competitive reasons, many 
transactions must be negotiated relatively quickly. Many competitive 
opportunities will be lost by the time the Commission can issue a final 
order under section 211. Case-by-case section 211 proceedings are not a 
substitute for tariffs of general applicability that permit timely, 
non-discriminatory access on request.
    Second, discrimination is inherent in the current industry 
environment in which some customers and sellers are served by open 
access systems, and others have to rely on negotiated bilateral 
arrangements or the mandatory section 211 process. The end result is 
discrimination in the ability to obtain transmission services, as well 
as in the quality and prices of the services. This national patchwork 
of open and closed transmission systems, with disparate terms and 
conditions of service, cannot be cured effectively through section 211.
    The Commission believes that its actions under sections 205 and 206 
will complement the section 211 procedures

[[Page 21563]]

to achieve both the Energy Policy Act's goals of creating more 
competitive bulk power markets and lower rates for consumers and the 
Federal Power Act's explicit direction in section 205(b) that no public 
utility shall, with respect to any transmission in interstate commerce, 
grant any undue preference or advantage to any person or subject any 
person to any undue prejudice or disadvantage.
2. Response to Commenters Opposing Our Legal Authority
a. Authority to Order Open Access Tariffs
Comments
Initial Comments Supporting Commission Authority
    A number of commenters support or state that they do not oppose the 
Commission's authority to order open access tariffs.<SUP>222 NIEP and 
CCEM explain that the AGD decision supports the Commission's action in 
this proceeding. ELCON asserts that the Commission's ``extensive 
treatment of the relevant case law demonstrating FERC's authority to 
remedy this discrimination is legally sound.'' UtiliCorp argues that 
section 211 supports, rather than undermines, the Commission's 
authority for the NOPR because it reflects Congress's intention to 
encourage more competitive bulk power markets.
---------------------------------------------------------------------------

    \222\ NIEP, ELCON, CINergy, UtiliCorp, TAPS, SBA, Entergy, NY 
Energy Buyers, Sierra.
---------------------------------------------------------------------------

Initial Comments Opposing Commission Authority
    Other commenters assert that the Commission has improperly relied 
on sections 205 and 206 of the FPA to require open access.<SUP>223 They 
argue, for instance, that Otter Tail should be read as a broad 
constraint on the Commission's authority to order wheeling for any 
purpose and that the AGD decision does not undermine that holding or 
the cases following Otter Tail.<SUP>224 In support, some of these 
commenters discuss Richmond Power & Light, New York State Electric & 
Gas Corporation, and Florida Power & Light Company, the same cases 
discussed by the Commission in the NOPR.<SUP>225
---------------------------------------------------------------------------

    \223\ E.g., EEI, Atlantic City, Allegheny, VA Com, PA Com, Ohio 
Edison, Southern, Utilities For Improved Transition, Dayton P&L, 
SCE&G, Centerior, BG&E, Central Hudson, NY Com, Salt River, Carolina 
P&L, Union Electric, VEPCO, Utility Workers Union.
    \224\ EEI, VA Com, Union Electric.
    \225\ E.g., EEI, VA Com, NY Com, PA Com, Salt River, Southern, 
Dayton P&L, Detroit Edison, BG&E.
---------------------------------------------------------------------------

    For example, EEI highlights the AGD court's discussion noting the 
difference between the legislative history of the NGA and that of the 
FPA, which the court stated was not as strong as that of the NGA. 
Moreover, EEI argues that the court found that section 7 of the NGA 
provided support for the Commission's actions in Order No. 436 and that 
such section 7 conditioning authority is lacking under the FPA. 
Allegheny notes that AGD did not overrule Otter Tail. Dayton P&L states 
that, in the gas case, the Commission was responding to voluntary 
filings by pipelines. It also says that before the NOPR, the Commission 
itself saw its authority as more limited. SCE&G points to differences 
between Commission jurisdiction over public utilities and gas pipelines 
and criticizes the Commission's alleged assumption that the 
circumstances involved in the gas and electric industries are virtually 
identical.
    PA Com argues that the attempt to analogize to the NGA and the 
cases that refer to that Act is inconsistent with the technical and 
engineering realities of the electric transmission grid and that 
extensive comparisons between the natural gas industry and the electric 
industry are misleading.<SUP>226
---------------------------------------------------------------------------

    \226\ See also NY Com (NGA has no parallel provision to section 
211 of the FPA), Salt River.
---------------------------------------------------------------------------

    FL Com argues that, in relying on sections 205 and 206 to establish 
generic open access transmission tariffs for all public utilities, the 
Commission violates the court's decision in Cajun Electric Power 
Cooperative v. FERC, 28 F.3d 173 at 179 (D.C. Cir. 1994), where, FL Com 
argues, the court refused to allow the Commission to use a non-
evidentiary ruling when there were material facts at issue.
Reply Comments
    CCEM responds that EEI and others confuse the obligations of a 
common carrier with the duty of public utilities not to unduly 
discriminate. It says that AGD supports the Commission's authority 
because the legislative history of the FPA and the NGA are similar with 
respect to common carriage. According to CCEM, early versions of both 
statutes would have made the regulated industries operate as common 
carriers (citing Otter Tail, the legislative history of the FPA, the 
legislative history of the Public Utility Holding Company Act, and the 
legislative history of the Mineral Leasing Act), but that Congress 
chose not to impose the common carrier obligations.
    CCEM also says that the duties the Commission imposed on the gas 
industry and those in the NOPR are not common carriage in any event. 
According to CCEM, a common carrier must carry all goods offered 
(citing Am. Trucking Assoc. v. Atchison, T. & S.F. Ry. Co., 387 U.S. 
397, 406 (1967)). Finally, CCEM cites Stephenson v. Binford, 287 U.S. 
251, 265-66 (1932), where the Supreme Court held that obligations that 
are typical of common carriers can be imposed on contract motor 
carriers.
    CCEM further disagrees with EEI's argument that the enactment of 
section 211 was a disavowal of any other Commission authority to order 
transmission.
    ELCON also disagrees with EEI's claim that the Energy Policy Act 
undermines the Commission's pre-existing section 205 and 206 authority. 
It states that the savings clause in section 212(e) of the FPA, as 
amended, explicitly expresses Congress' intention not to undermine the 
Commission's pre-existing authority and that the legislative history 
contains nothing to suggest otherwise.
    Similarly, in response to those who argue that section 211 is the 
only source of authority for the Commission to order transmission, NIEP 
argues that sections 211 and 212 serve purposes different from section 
206. It says that the Commission's authority to order transmission in 
the ``public interest'' under sections 211 and 212 is not synonymous 
with its authority to order transmission as a remedy for undue 
discrimination under section 206; the two standards are complementary 
but distinct:

    Although broadly applicable, the Commission's ability to order 
wheeling under sections 211 and 212 is carefully limited by a number 
of procedural provisions. Foremost among these is the requirement 
that the wheeling may be ordered only upon a specific application 
for transmission services. FERC's authority to act in the public 
interest is thus confined to the individual case.
    By contrast, FERC's remedial powers under Section 206 can be 
exercised upon a finding of unjust, unreasonable or unduly 
discriminatory or preferential practices. Once that finding has been 
made, however, the form and substance of the remedy is left entirely 
to the FERC's discretion. If FERC deems it necessary, FERC may adopt 
generally applicable rules or practices as a countermeasure to 
discriminatory acts, including ordering utilities to file generally 
applicable transmission tariffs.\227\
---------------------------------------------------------------------------

    \227\ NIEP Reply Comments at 8.

    NIEP also points out that the legislative history does not address 
the Commission's authority to order transmission as a remedy for undue 
discrimination. It challenges the

[[Page 21564]]

interpretation of the legislative history advanced by some 
commenters.<SUP>228
---------------------------------------------------------------------------

    \228\ NIEP explains that
    (W)hile much has been made of the Senate report accompanying 
S.2114, which subsequently became part of PURPA in 1978, that report 
does not illustrate an intent to limit FERC's authority to remedy 
undue discrimination under section 206. That report characterizes 
the Supreme Court's decision in Otter Tail as holding that ``the 
Federal Power Act leaves open a gap in its failure to assign the FPC 
general authority to order wheeling in this situation * * *.'' The 
``situation'' to which the Report refers is not discrimination, 
however. Instead, the statement appears to make reference to 
circumstances in which general public interest concerns, such as 
reliability, efficiency and competition, are at stake. Thus, Senate 
Report 2114 is simply not a limitation on the Commission's remedial 
powers under Sections 206.
    NIEP Reply Comments at 8-9 (citations omitted).
---------------------------------------------------------------------------

    Next, NIEP defends the Commission's proposed findings that there is 
generally undue discrimination in the provision of transmission 
service. It notes that when an agency acts on an industry-wide basis, 
the agency does not have to make a finding as to each particular case.
    Finally, NIEP responds to those who argue that AGD is not on point. 
It notes that the AGD court discussed electric cases and emphasizes the 
court's statement that the NGA ``fairly bristles with concern for undue 
discrimination''--a statement that is equally true of the FPA.
    TDU Systems responds to the argument that Otter Tail is a broad 
constraint on the Commission's authority to order transmission.<SUP>229 
At issue in that case, it argues, was the reach of the Sherman Act, not 
of FPA sections 205 and 206. Similarly, it argues, the Florida Power 
case is not on point, and the court there specifically said that it was 
not deciding whether the Commission could have ordered wheeling as a 
remedy for anticompetitive activities. Moreover, TDU Systems asserts 
that EEI's use of a quote from a single Senator should carry no weight, 
since it is a well-established principle of statutory construction that 
such statements have little value. Finally, it points out that the AGD 
court itself did not view Otter Tail or other electric precedent as 
forbidding the Commission to order wheeling as a remedy for undue 
discrimination.
---------------------------------------------------------------------------

    \229\ See also Entergy.
---------------------------------------------------------------------------

    Entergy asserts that Congress's refusal to require utilities to 
provide transmission as common carriers or whenever it is in the public 
interest was merely a decision not to give the Commission general 
authority to order wheeling, without regard to undue discrimination. 
Thus, the Otter Tail language concerning the absence of a common 
carrier requirement does not demonstrate that Congress meant to limit 
the Commission's authority to remedy undue discrimination.
    ELCON disputes EEI's reading of NYSEG, noting that the NYSEG court 
explicitly stated:

    Nor do we suggest that the Commission is powerless to review a 
wheeling agreement under section 206 without following the 
requirements of sections 211 and 212.\230\)
---------------------------------------------------------------------------

    \230\ ELCON Initial Comments at 7 (quoting NYSEG at 403).

    TAPS discusses numerous cases, including the primary cases relied 
upon by the Commission, and disposes of NYSEG by stating that it is no 
longer good law, if it ever was.
Commission Conclusion
    There can be no question that the Commission has the authority to 
remedy undue discrimination. Sections 205 and 206 of the FPA mandate 
that we 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. Under these sections, 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 we must disapprove those contracts and practices that 
do not meet this standard. Our discretion is at its zenith in 
fashioning remedies for undue discrimination.<SUP>231
---------------------------------------------------------------------------

    \231\ See, e.g.,- Niagara Mohawk Power Corporation v. FPC, 379 
F.2d 153, 159 (D.C. Cir. 1967).
---------------------------------------------------------------------------

    Some commenters, however, challenge our authority to order 
industry-wide non-discriminatory open access as a remedy for the undue 
discrimination we have found in the industry. As summarized above, they 
essentially assert that we are prohibited by court precedent, the 
legislative history of the FPA, and sections 211 and 212 of the FPA 
from ordering wheeling as a remedy for undue discrimination. We 
disagree and conclude that we have the authority--indeed, a 
responsibility--to require non-discriminatory open access transmission 
as a remedy for undue discrimination.
AGD and Legislative History
    The court decision in Associated Gas Distributors v. FERC provides 
powerful support for our ability to order industry-wide non-
discriminatory open access transmission in the electric industry as a 
remedy for undue discrimination. As discussed in detail above, AGD, 
which is the only decision to have addressed the Commission's authority 
to remedy undue discrimination by requiring open access, upheld our 
authority under section 5 of the NGA (the parallel to section 206 of 
the FPA) to require open access in the natural gas industry. The 
rationale supplied by the AGD court applies equally to the FPA and our 
responsibility to eliminate undue discrimination in the electric 
industry.
    Those who challenge the Commission's legal authority to remedy 
undue discrimination face the same difficulty that parties faced in 
seeking to overturn open access in the natural gas industry--they ``can 
point to no language in the (FPA) barring the Commission from imposing 
common carrier status on (public utilities), and certainly none barring 
it from imposing upon the (public utilities) a specific duty that 
happens to be a typical or even core component of such status.'' \232\ 
Instead, as was unsuccessfully attempted in the AGD proceeding, they 
seek to overcome the statutory silence primarily by means of 
legislative history. However, as the AGD court explained, legislative 
history is not even relevant, because

    \232\ AGD, 824 F.2d at 997.
---------------------------------------------------------------------------

courts have no authority to enforce principles gleaned solely from 
legislative history that has no statutory reference point.\233\

    \233\ Id. (quoting IBEW, Local No. 474 v. NLRB, 814 F.2d 697, 
712 (D.C. Cir. 1987) (emphasis deleted by court from original)).
---------------------------------------------------------------------------

Here, as the court found with respect to the NGA, the legislative 
history of the FPA ``provides strong support only for the point that 
Congress declined itself to impose common carrier status on (public 
utilities) * * * It affords weak--almost invisible--support for the 
idea that the Commission could under no circumstances whatsoever impose 
obligations encompassing the core of a common carriage duty.'' \234\
---------------------------------------------------------------------------

    \234\ Id. (emphasis added).
---------------------------------------------------------------------------

    Commenters focus on the following statement in the AGD decision to 
support the argument that, because Congress did not expressly reject 
common carriage under the NGA, but did reject it under the FPA, a 
different outcome in this proceeding is required:

we note that the legislative history of the two acts is, on this 
point, materially different. In its deliberations on the bill that 
ultimately emerged as the Federal Power Act, Congress considered and 
rejected a provision that would have ``empowered the Federal Power 
Commission to order wheeling if it found such action to be 
`necessary or desirable in the public interest.' '' (citing Otter 
Tail) (quoting S. 1725, 74th Cong., 1st Sess.). The evidence as to 
the NGA (surveyed above) is less direct: it consists exclusively of 
various occasions on which Congress did not adopt proposals actually 
making the natural gas pipelines into common carriers.\235\
---------------------------------------------------------------------------

    \235\ Id. at 998-99.


[[Page 21565]]


---------------------------------------------------------------------------

    The above statement, however, does not preclude the AGD court's 
decision on our broad authority to remedy undue discrimination in the 
gas industry from applying equally in the electric industry. Clearly, 
the court did not say that. As discussed below, we believe the 
statement focuses on a distinction in the legislative histories that is 
not meaningful.
    First, whether or not a material difference exists in the 
respective legislative histories of the NGA and FPA, the fact remains 
that the crucial findings of the AGD court were that: (1) ``Congress 
declined itself to impose common carrier status'' (emphasis added) and 
(2) there is no ``support for the idea that the Commission could under 
no circumstances whatsoever impose obligations encompassing the core of 
a common carriage duty.'' \236\ These findings apply equally to the 
FPA. Simply stated, statutory silence cannot be overcome by means of 
legislative history--even if the legislative history in fact indicated 
that Congress ``rejected'' legislative imposition of common carrier 
status under the FPA, but ``did not adopt'' it under the NGA. In either 
event, nothing in the statute or legislative history suggests that 
Congress concluded that the Commission could under no circumstances 
impose open access as a remedy to undue discrimination.
---------------------------------------------------------------------------

    \236\ Id. at 997. We also note that the contract carriage 
obligation we are imposing is easily distinguished from the common 
carrier obligation Congress chose not to adopt. As discussed infra, 
the common carrier provisions rejected by Congress would have 
required transmission for ``any person'' upon reasonable request. 
This would have included retail purchasers.
---------------------------------------------------------------------------

    Moreover, the legislative history of the bills containing the FPA 
and the NGA, taken as a whole, suggests that the distinction drawn in 
AGD between the legislative histories of the NGA and the FPA is not 
meaningful. The legislation that was to become the FPA originally 
included provisions regulating both electric power and natural gas. As 
originally proposed, the legislation contained identical common 
carriage language for both public utilities and natural gas pipelines.
    With respect to the FPA, the Supreme Court explained in Otter Tail 
that

(a)s originally conceived, Part II would have included a ``common 
carrier'' provision making it ``the duty of every public utility to 
* * * transmit energy for any person upon reasonable request * * 
*.'' In addition, it would have empowered the Federal Power 
Commission to order wheeling if it found such action to be 
``necessary or desirable in the public interest.'' H.R. 5423, 74th 
Cong., 1st Sess.; S. 1725, 74th Cong. 1st Sess. These provisions 
were eliminated to preserve ``the voluntary action of the 
utilities.'' S.Rep. No. 621, 74th Cong., 1st Sess., 19.\237\

    \237\ Otter Tail, 410 U.S. at 374.
---------------------------------------------------------------------------

The language paraphrased by the Supreme Court was from Title II of the 
initial bill proposing the Public Utility Holding Company Act. The 
entire sections from which the paraphrased language came are as 
follows:

    SEC. 202. (a) It shall be the duty of every public utility to 
furnish energy to, exchange energy with, and transmit energy for any 
person upon reasonable request therefor; and to furnish and maintain 
such services and facilities as shall promote the safety, comfort, 
and convenience of all its customers, employees, and the public, and 
shall be in all respects adequate, efficient, and reasonable.
    * * *
    SEC. 203. (b) Whenever the Commission after notice and 
opportunity for hearing finds such action necessary or desirable in 
the public interest, it may by order direct a public utility to make 
additions, extensions, repairs, or improvements to or changes in its 
facilities, to establish physical connection with the facilities of 
one or more other persons, to permit the use of its facilities by 
one or more other persons, or to utilize the facilities of, sell 
energy to, purchase energy from, transmit energy for, or exchange 
energy with, one or more other persons. Where any such order affects 
two or more persons, the Commission may prescribe the terms and 
conditions of the arrangement to be made between such persons, 
including the apportionment of cost between them and the 
compensation or reimbursement reasonably due to any of them.\238\

    \238\ H.R. 5423, 74th Cong., 1st Sess., 32 (emphasis added).
---------------------------------------------------------------------------

    This initial bill proposing the Public Utility Holding Company Act 
also included a Title III that was intended to regulate the 
transmission and sale of natural gas. Sections 303(a) and 304 of Title 
III included the identical common carrier language paraphrased by the 
Supreme Court and included in sections 202(a) and 203(b) of Title 
II.\239\ After further deliberations, Congress rejected the above-
quoted language in Title II and eventually adopted a Title II that did 
not include any common carrier language. On the other hand, Title III 
(addressing regulation of natural gas) was not reported out of 
committee, but reemerged in the next year.\240\ The bill that reemerged 
did not contain the common carrier language that was in the original 
Title III. However, as Congress had just debated the common carrier 
issue in enacting electric power regulation, it is not surprising that 
Congress did not engage in debating the very same issue in enacting 
natural gas regulation.
---------------------------------------------------------------------------

    \239\ Id. at 44.
    \240\ In the debate on the subsequent bill to regulate natural 
gas, Congressman Cole explained:
    Mr. Chairman, the House should realize that the measure we are 
dealing with today is of extreme importance, more so than the 
attendance and the time taken in the discussion would seem to 
indicate. It is the culmination of one of the most far-reaching, 
intensive studies of the Federal Trade Commission I assume that that 
Commission ever conducted, and last year found a place in not 
identical language but very similar in the Rayburn bill, the famous 
holding-company bill, as part 3 thereof. Our committee eliminated 
part 3, as members will recall, and saved it for a separate measure 
reported out as it was last year, which was not considered by the 
House, but is here today in improved form.
    81 Cong. Rec. H6724 (daily ed. July 1, 1937).
---------------------------------------------------------------------------

    Because of the timing of the legislation involving the FPA and the 
NGA and the logical nexus between the two acts, we conclude that there 
is in fact no material difference as to this issue in the legislative 
histories of the two acts. Both initially included identical common 
carrier language, and the language was removed from both. As to both 
acts, Congress chose not to impose common carrier obligations on the 
electric or natural gas industries, but gave the Commission the 
authority and responsibility to eliminate undue discrimination in both 
industries. Consequently, as open access was found to be a proper 
remedy for undue discrimination in the natural gas industry, it is also 
a proper remedy for undue discrimination in the electric industry.
    As the AGD court noted with respect to the Commission's powers and 
duties under the NGA, Congress explicitly gave the Commission the 
authority to eradicate undue discrimination under the FPA. That 
explicit power and duty provided by Congress cannot be invalidated 
solely on the ground that Congress chose not to impose statutory common 
carrier status on public utilities or did not explicitly authorize the 
Commission to do so.<SUP>241 As the AGD court explained, this would 
``turn [] statutory construction upside down, letting the failure to 
grant a general power prevail over the affirmative grant of a specific 
one.'' <SUP>242
---------------------------------------------------------------------------

    \241\ AGD, 824 F.2d at 998.
    \242\ Id.
---------------------------------------------------------------------------

Other Case Law
    A number of commenters argue that the Commission misinterpreted the 
other cases discussed in the NOPR with respect to our authority to 
order non-discriminatory open access transmission. We disagree. As 
demonstrated above, not one of the cases put forth by commenters holds 
that we cannot remedy undue discrimination by requiring public

[[Page 21566]]

utilities to provide non-discriminatory open access 
transmission.<SUP>243
---------------------------------------------------------------------------

    \243\ See FERC Stats. & Regs. at 33,053-56. We further note that 
the AGD court did not discuss the NYSEG decision at all. Indeed, the 
NYSEG case did not involve any allegations of undue discrimination 
and any discussion of section 206 by the court was dictum.
---------------------------------------------------------------------------

    AGD is the only case in which a court specifically addressed our 
authority to order open access transmission as a remedy for undue 
discrimination. Its favorable finding with respect to our action under 
section 5 of the NGA directly supports our ordering non-discriminatory 
open access transmission under section 206 of the FPA.
Authority to Act by Rule
    We disagree with those commenters that assert that we may find and 
remedy undue discrimination only through case-by-case adjudications and 
are prohibited from making a generic determination of undue 
discrimination through a rulemaking. First, there is no question that 
it is within our discretion whether we act through rule or through 
case-by-case adjudications.<SUP>244 The AGD court specifically rejected 
a similar argument that the Commission erred in requiring open access 
transportation tariffs without first finding that each individual 
pipeline's rates were unlawful. The AGD court held that ``(t)he 
Commission is not required to make individual findings if it exercises 
its Sec. 5 authority by means of a generic rule.'' <SUP>245
---------------------------------------------------------------------------

    \244\ See, e.g., NLRB v. Bell Aerospace Company, 416 U.S. 267, 
293 (1974) (citing SEC v. Chenery Corporation, 332 U.S. 194, 202-03 
(1947). See also Heckler v. Campbell, 461 U.S. 458, 467 (1983) (even 
where enabling statute requires a hearing to be held, agency may 
rely on its rulemaking authority); Panhandle Eastern Pipeline 
Company v. FERC, 907 F.2d 185, 187-88 (D.C. Cir. 1990). Under 
section 403 of the DOE Act, 42 U.S.C. 7173, the Commission is 
authorized at its discretion to initiate rulemaking proceedings.
    \245\ AGD, 824 F.2d at 1008.
---------------------------------------------------------------------------

    We have identified a fundamental generic problem in the electric 
industry: owners, controllers and operators of monopoly transmission 
facilities that also own power generation facilities have the incentive 
to engage, and have engaged, in unduly discriminatory practices in the 
provision of transmission services by denying to third parties 
transmission services that are comparable to the transmission services 
that they are providing, or are capable of providing, for their own 
power sales and purchases. These practices drive up the price of 
electricity and hurt consumers. Furthermore, the incentive to engage in 
such practices is increasing significantly as competitive pressures 
grow in the industry. It is within our discretion to conclude that a 
generic rulemaking, not case-by-case adjudications, is the most 
efficient approach to take to resolve the industry-wide problem facing 
us.
b. Undue Discrimination/Anticompetitive Effects
Initial Comments
    A number of commenters allege that the Commission has failed to 
meet its burden of proving industry-wide discrimination.<SUP>246 They 
assert that the Commission has provided only a few unsubstantiated 
allegations of discrimination, which do not represent the current 
conditions in the electric industry, or that the Commission has not 
shown that all electric utilities have unduly discriminated. Some 
attack the NOPR's incorporation by reference of the unsubstantiated 
allegations of discrimination set forth in a petition for rulemaking 
filed on February 16, 1995 by the Coalition for a Competitive Electric 
Market (CCEM).<SUP>247
---------------------------------------------------------------------------

    \246\ E.g., EEI, Ohio Edison, PA Com, BG&E, NY Com, Minnesota 
P&L, Carolina P&L.
    \247\ E.g., EEI, BG&E.
---------------------------------------------------------------------------

    EEI argues that the allegations of discrimination in the NOPR must 
be considered in light of the fact that: (1) All tariffs currently on 
file have been found by the Commission not to be discriminatory; (2) 
more than 30 utilities have voluntarily filed open access tariffs, 
which belies any assertion of widespread discrimination in the 
industry; and (3) transmission disputes are rare, with only 19 section 
211 proceedings having been filed in the last three years.<SUP>248 EEI 
concludes that the Commission's allegations of discrimination do not 
rise to the level of ``extreme circumstances'' found by the court in 
the natural gas industry in AGD.
---------------------------------------------------------------------------

    \248\ See also Ohio Edison.
---------------------------------------------------------------------------

    EEI adds that the Commission's proposal to act under section 206 is 
itself discriminatory because it applies only to public utilities and 
does not reach all transmission-owning utilities.<SUP>249 If 
reciprocity is designed to resolve this problem, EEI believes that 
reciprocity should also be ``effective for public utilities.'' 
Furthermore, EEI argues that the failure of a public utility to provide 
to others a service that it does not provide itself is not evidence of 
discrimination, and that inclusion of such a provision actually results 
in preferential treatment for transmission users.
---------------------------------------------------------------------------

    \249\ See also SCE&G.
---------------------------------------------------------------------------

    NE Public Power District alleges that the NOPR does not contain a 
single reference to any actual discrimination or anticompetitive 
conduct by any publicly owned utility.
    Salt River asserts that the Commission is required to consider all 
elements of an antitrust analysis before reaching a conclusion that 
market power exists in the transmission system and that we have failed 
to do so.<SUP>250 It concludes that the NOPR ``constitutes an attempt 
to legislate a remedy for an evil that has not been, and cannot be, 
lawfully found to exist on a wholesale basis among utilities that own 
and operate integrated generation and transmission systems.'' <SUP>251
---------------------------------------------------------------------------

    \250\ Salt River Initial Comments at 5-6 (referencing an 
attached legal memorandum of Donald A. Kaplan).
    \251\ Salt River Initial Comments at 6.
---------------------------------------------------------------------------

    PA Com argues that the Commission's request for examples of 
discriminatory behavior is a ``tacit admission as to the paucity of 
evidence of discriminatory practices by transmission owning 
utilities.'' NY Com argues that the ``Commission's lack of a record 
basis for its proposed findings is legally suspect because courts in 
two cases have held that the Commission cannot proceed with open access 
transmission tariffs absent record findings of specific anticompetitive 
conduct.'' <SUP>252
---------------------------------------------------------------------------

    \252\ NY Com Initial Comments at 16-18 (discussing FPL and 
Cajun).
---------------------------------------------------------------------------

    Finally, EEI claims that even if the Commission has proven its 
allegations of discrimination, we have failed to meet the requirements 
of section 206 of the FPA.<SUP>253 According to EEI, the Commission 
cannot find, without an adjudicatory hearing, that the rates on file 
are unlawful and order replacement rates.<SUP>254 The Commission's 
proposed procedure would unlawfully place the burden of justifying 
existing rates on the utilities.
---------------------------------------------------------------------------

    \253\ See also Southern.
    \254\ See also Southern.
---------------------------------------------------------------------------

Reply Comments
    A number of commenters provide instances of discriminatory behavior 
they have faced over the years. NCMPA describes difficulties it has 
faced in dealing with CP&L, including a situation where CP&L allegedly 
impeded NCMPA's use of transmission access through CP&L's control of 
dispatching.<SUP>255
---------------------------------------------------------------------------

    \255\ We note that CP&L raised legal objections to our authority 
to implement this rule.
---------------------------------------------------------------------------

    AMP-Ohio alleges that Toledo Edison refused to transmit emergency 
power on a buy-sell basis to certain AMP-Ohio members even though 
Toledo Edison's system was not constrained. Instead, AMP-Ohio alleges, 
Toledo Edison bought the power and resold it to AMP-Ohio at a higher 
rate.

[[Page 21567]]

    APPA challenges EEI's claim that there is no substantial evidence 
of undue discrimination in transmission. It suggests that nineteen 
instances of transmission disputes being filed since the Energy Policy 
Act was enacted is ample evidence of undue discrimination. Moreover, 
according to APPA, reported abuses are only the tip of the iceberg.
    CCEM responds to the argument raised by EEI and others that there 
is no showing of extreme circumstances of discrimination in the 
electric industry such as the AGD court noted in the gas industry. It 
says that these circumstances are present and gives numerous examples; 
it does not identify the specific utilities because ``it is the 
experience of * * * (our) members that nearly all transmission owners 
retaliate * * *'' against anyone who complains. Moreover, in answer to 
EEI's statement that transmission disputes are rare, CCEM states that 
since most of the competition is in the short-term market, it has not 
been worthwhile to file complaints. The examples provided by CCEM 
include: (1) Refusal by a California public utility to offer firm 
service; (2) refusal by control area utilities in Texas to offer 
ancillary services to a power marketer, with the result that one of the 
utilities won the bid, even though it did not have the lowest price; 
(3) non-utilities in ERCOT being unable to compete to meet short-term 
requests for economy energy because they were required to schedule by 
noon of the preceding day, while utilities did not subject themselves 
to such a scheduling requirement; (4) power pool or control area 
information requirements, particularly in the northwest part of WSPP, 
that force non-utilities to reveal commercially sensitive information; 
the transportation operator has then revealed the information to its 
own or its affiliate's sales arm, which ``steals'' the deal; (5) a 
northeast power pool that refused to wheel out even though capacity was 
available on the grounds that sending power out of the pool would drive 
up prices in the pool (hoarding); (6) a power marketer that asked a 
utility to provide transmission, whereupon the utility bought up 
certain transmission capacity necessary for the marketer to reach its 
buyer, thus blocking the path--this was possible because the utility 
was able to locate the purchaser based on commercially sensitive 
information the marketer had to give the utility when the marketer 
asked for transmission; (7) a common contracting practice among 
utilities restricting the use of interconnections to themselves, 
particularly in the Southwest Power Pool, MAPP, and MAIN; (8) utilities 
overstating the cost of improvements (gold-plating) and thus 
discouraging service. CCEM also responds to each of EEI's criticisms of 
CCEM's examples of undue discrimination submitted in its February 16, 
1995 petition and argues that its examples of undue discrimination are 
unrebutted.
    Brownsville asserts that

while PUB [Brownsville] must pay multiple distance-based and 
pancaked transmission rates to engage in transactions with the non-
ERCOT universe, El Paso Electric would have received transmission 
payments from its merger partners while gaining free transmission 
access to buy and sell within ERCOT. CSW presently walls other ERCOT 
utilities off from participation in the Western Systems Power Pool, 
while its ERCOT subsidiaries, CPL and WTU, share in the benefits of 
their non-ERCOT affiliates' WSPP memberships via the preferential 
terms of the CSW Operating Agreement. CSW treats its own inter-
affiliate central dispatch as having a higher priority than third-
party economy energy transactions, with the result that CPL not 
infrequently crowds PUB out of the economy market. <SUP>256

    \256\ Brownsville Reply Comments at 2-3 (emphasis in original).
---------------------------------------------------------------------------

    Wisconsin Municipals states that its members have been fighting 
transmission battles for years and sets forth five examples of the sort 
of difficulties it has experienced in attempting to obtain transmission 
rights. For example, it explains that Wisconsin public utilities have 
resisted an effort by the state commission to achieve comparability of 
use of transmission. Wisconsin Municipals also explains a situation 
where ``if WPPI continued to purchase its power from WPSC, it would pay 
WPSC $843,840 annually for transmission service: if it purchases power 
off system from WP&L (one of WPSC's competitors), WPPI would pay WPSC 
$1,774,224 for transmission service to the exact same load.''
    TAPS sets forth additional examples of undue discrimination, 
including refusals to wheel even in the face of Nuclear Regulatory 
Commission (NRC) nuclear license conditions requiring wheeling, and 
Northeast Utilities' refusal to provide transmission to a QF even 
though it had indicated to the Commission that it would provide such 
transmission in order to obtain Commission approval of its proposed 
merger with Public Service Company of New Hampshire.
    NIEP sets forth ten examples of undue discrimination that its 
members have experienced in seeking access to transmission service at 
reasonable terms and conditions.
    Some commenters challenge these claims of undue discrimination. For 
example, Carolina P&L responds to NCMPA #1's example of obstruction by 
Duke in accommodating energy sales from the jointly owned Catawba 
Plant. Carolina P&L explains that NCMPA #1's proposal ``would require 
Duke to provide its own generation resources on behalf of NCMPA #1 in 
order to support a bulk power sale when NCMPA #1's own resource 
capacity and energy are not sufficient for the sale.'' Carolina P&L 
argues that this is backstanding that goes beyond the scope of any 
ancillary service the Commission has proposed and would be entirely 
inappropriate ``to compel the Transmission Provider to sell power to 
its Transmission Customer for resale on the bulk power market.''
    Duke also responds to NCMPA #1's claim of discrimination and 
asserts that NCMPA #1's claim is not relevant to the NOPR proceeding, 
but is a specific contractual claim that should be pursued pursuant to 
the terms of its contract.
Commission Conclusion
    We conclude that unduly discriminatory and anticompetitive 
practices exist today in the electric industry and, more importantly, 
that such practices will increase as competitive pressures continue to 
grow in the industry, unless the Commission acts now to prevent such 
practices.<SUP>257 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. The inherent characteristics of 
monopolists make it inevitable that they will act in their own self-
interest to the detriment of others by refusing transmission and/or 
providing inferior transmission to competitors in the bulk power 
markets to favor their own generation, and it is our duty to eradicate 
unduly discriminatory practices. As the AGD court stated: ``Agencies do 
not need to conduct experiments in order to rely on the prediction that 
an unsupported stone will fall.'' <SUP>258
---------------------------------------------------------------------------

    \257\ While many public utilities have filed some form of open 
access tariff (often in response to our proposed rule), we believe 
that many of the remaining utilities will not voluntarily open their 
systems absent a final rule. See also note 266.
    \258\ AGD, 824 F.2d at 1008.
---------------------------------------------------------------------------

    We set forth examples in the NOPR of undue discrimination that we 
believe are occurring in the electric industry and invited commenters 
to identify any discrimination that they may have experienced. In 
response, commenters

[[Page 21568]]

presented numerous additional examples of undue discrimination, which 
are summarized above, and we set forth below further examples of undue 
discrimination that have been raised in cases before the Commission.
    Many of the examples of discriminatory behavior that have been 
brought to our attention do not name the specific utilities involved, 
and many are allegations that are not proven. However, we do not 
believe that this undermines our finding of unduly discriminatory 
practices by transmission owners and controllers. We believe that it is 
only natural that potential transmission customers with an interest in 
participating in electric markets will be reluctant to name names for 
fear of being shut out of those markets. CCEM, which identified a wide 
array of discriminatory behavior its members have experienced, 
explained that

(w)e do not identify the specific utilities in each example because 
it is the experience of CCEM members that nearly all transmission 
owners retaliate by cutting off all communications with anyone that 
challenges or complains about the rates, terms or conditions at 
which the owner offers access to its system. Inasmuch as most of the 
competitive commerce in electric power today is in short-term 
markets, it is typically not worth the effort of CCEM members or 
other transmission-dependent entities to file a complaint with the 
Commission's enforcement staff or in the courts in connection with a 
transmission owner's discriminatory practices. The deal is lost well 
before a complaint can be processed and ruled upon.\259\

    \259\ CCEM Initial Comments at 18-19. See also NIEP Reply 
Comments at 13 n.31.
---------------------------------------------------------------------------

    Other examples of discriminatory behavior have also been raised in 
proceedings before the Commission. As we explained in detail in the 
NOPR, transmission-owning utilities have discriminated against others 
seeking transmission access in a variety of ways, most often subtly and 
indirectly.\260\ For example, delaying tactics have been used to 
frustrate access. The history of Pacific Gas and Electric Company's 
(PG&E) attempt to avoid its commitments made to the California owners 
of the California-Oregon Transmission Project (COTP) is a prime 
example. The owners had originally planned the COTP to have its 
southern terminus at the Midway station with Southern California 
Edison. PG&E convinced them to terminate the project instead at PG&E's 
Tesla station and indicated that PG&E would provide transmission 
service the rest of the way south to Midway. PG&E promised this service 
in 1989 (in Principles). PG&E spent the next four years filing 
substitute provisions for what it had promised in the Principles.\261\ 
Additional allegations of discriminatory behavior are set forth in 
Appendix C, which includes allegations made under oath in proceedings 
at the Commission and allegations made in pleadings and other documents 
before the Commission.
---------------------------------------------------------------------------

    \260\ FERC Stats. & Regs. at 33,072.
    \261\ See Pacific Gas and Electric Company, 65 FERC para. 61,312 
at 62,428-30 and n.22, remanded on other grounds, Pacific Gas & 
Electric Company v. FERC, No. 94-70037 (9th Cir. June 23, 
1994)(unpublished opinion), order on remand, 69 FERC 61,006 (1994).
---------------------------------------------------------------------------

    In addition, to date, the Commission has received 28 section 211 
transmission requests.\262\ Applicants submit section 211 transmission 
requests when the transmission provider refuses to provide the 
requested transmission service. For example, American Municipal Power-
Ohio, Inc. (AMP-Ohio) requested Ohio Edison Company (Ohio Edison) to 
establish additional delivery points to certain of AMP-Ohio's members 
and to permit the addition of delivery points in the future upon AMP-
Ohio's request. Ohio Edison refused AMP-Ohio's request, claiming that 
it was not a proper request under section 211 because it already 
provided wholesale transmission to the municipal utilities at issue. In 
a proposed order, the Commission disagreed with Ohio Edison and ordered 
Ohio Edison to provide the requested additional delivery points and to 
entertain future requests by AMP-Ohio for specific delivery 
points.\263\
---------------------------------------------------------------------------

    \262\ A list of section 211 applications and the status of each 
is attached as Appendix A.
    \263\ American Municipal Power-Ohio, Inc. v. Ohio Edison 
Company, 74 FERC para. 61,086 (1996).
---------------------------------------------------------------------------

    Many of the examples of discriminatory actions we are seeing in the 
electric industry are similar to those we saw in the gas industry. 
Given our experience, we find that these examples of discriminatory 
actions are credible and well-founded. Thus, we conclude that there is 
more than sufficient reason to believe that transmission monopolists 
currently engage in unduly discriminatory practices, and that they will 
continue to engage in unduly discriminatory practices, unless we 
fashion a remedy to eliminate their ability and incentive to do so. In 
light of the competitive changes occurring in today's electric 
industry, we believe that the only effective remedy is non-
discriminatory open access transmission, including functional 
unbundling and OASIS requirements, and that it is within our statutory 
authority to order that remedy.
    Further, we disagree with the argument that we are limited to 
applying a traditional antitrust analysis in determining whether market 
power exists in the transmission system. While we must take antitrust 
concerns into consideration in exercising our responsibilities under 
the FPA, we are not an antitrust court, and our responsibilities are 
not those of the Department of Justice.\264\ We have analyzed the 
incentives and practices of monopoly transmission owners and 
controllers in light of the statutory standards and directives of the 
FPA and, based on our findings, have properly concluded that there is a 
generic problem that must be remedied.
---------------------------------------------------------------------------

    \264\ See, e.g., Gulf States Utilities Company v. FPC, 411 U.S. 
747, 758-60 (1973); FPC v. Conway Corporation, 426 U.S. 271, 279 
(1976); Northern Natural Gas Company v. FPC, 399 F.2d 953, 960 (D.C. 
Cir. 1968).
---------------------------------------------------------------------------

    The Commission also recognizes, as some commenters suggest, that we 
have, in the past, permitted utilities to file tariffs containing 
restrictions on transmission service that we are now finding to be 
unduly discriminatory in this rule and that we found unduly 
discriminatory in cases since our decision in AEP. However, it is 
entirely appropriate, and indeed necessary, that our application of the 
FPA's undue discrimination standard evolve over time and adapt to the 
changing circumstances in the industry. Our prior willingness to 
tolerate the use of monopoly power over transmission to maintain and 
aggregate the utility's market power over generation occurred in the 
context of an industry structured largely as vertically integrated 
regulated monopolies that supplied all facets of utility service--power 
supply, transmission, and distribution--as a single monopoly service. 
Competition generally was not meaningfully available as a means to 
discipline prices and consumer interests were best served by improving 
efficiencies of the integrated utilities, subject to cost-based 
regulation.
    Today, the circumstances of the industry are radically different. 
As explained in detail in Section III, a series of significant 
economic, regulatory, and technical changes in the power industry has 
introduced the promise of competitively priced power supplies. The 
profile of electric power suppliers has expanded to include not just 
the power supply arms of traditional utilities, but also independent 
power suppliers, affiliated utility power suppliers selling into 
territories of other franchise utilities,

[[Page 21569]]

and power marketers.\265\ This offers the promise of an increasingly 
competitive commodity market in electric power, in which significant 
benefits to consumers can be achieved. In the context of an emerging 
competitive market in generation, discriminatory practices that once 
did not constitute undue discrimination must be reviewed to determine 
whether they are being used to prevent the benefits of competition in 
generation from being achieved. Here we find conclusively that they 
are, and use our remedial authority to ensure that they can no longer 
occur.\266\
---------------------------------------------------------------------------

    \265\ We note that there are now 14 power marketers that are 
affiliated with public utilities.
    \266\ We take note of EEI's comments that, at the time of the 
comments, 30 utilities had filed open access tariffs. They argue, 
therefore, that the rule is unnecessary. Since their comment was 
filed, the number of utilities filing some form of an open access 
tariff has risen to 106. However, while some of these tariffs are 
based on the NOPR pro forma tariffs, many of these tariffs fall 
significantly short of the tariff requirements of both the NOPR and 
this Rule. Even if the tariffs met these requirements, the Rule is 
still needed to complete the task of eliminating undue 
discrimination by all public utilities and assuring, to the extent 
possible, a nationwide open access transmission grid. Indeed, a 
number of these tariffs were filed for the purposes of securing 
authority to market power competitively. This underscores markedly 
our fundamental conclusion that prior practices of using monopoly 
power over transmission to preserve market power over electricity 
sales has no place in today's industry and must be eliminated to get 
the benefits of competition to the customers we are required to 
protect under the FPA.
---------------------------------------------------------------------------

c. Section 211
Comments
    Various commenters contend that the enactment of section 211 in 
essence either removed any authority the Commission might have had 
under sections 205 and 206 or demonstrates that Congress did not 
believe the Commission could order wheeling under those provisions.
    These commenters assert that the legislative history of the FPA 
indicates that Congress specifically rejected giving the Commission 
authority to order wheeling under any circumstances.\267\ They further 
contend that the legislative history of section 211 demonstrates that 
Congress viewed the authority it granted in section 211 as a strictly 
limited and entirely new authority for the Commission.\268\ 
Specifically, EEI states that the legislative history of the Energy 
Policy Act confirms that the expanded authority provided under section 
211 was not intended to grant the Commission blanket authority to order 
wheeling, even as a remedy for anticompetitive conduct. Similarly, 
Utilities For Improved Transition argues that the legislative history 
shows that Congress specifically intended to preclude the Commission 
from ordering tariffs of general applicability under any circumstances. 
In addition, EEI points to testimony provided by a Commission staff 
witness before the Subcommittee on Energy and Power of the House 
Committee on Energy and Commerce in which EEI claims that ``she 
suggested that an affirmative statement that the Commission had the 
power to require wheeling on its own motion should be included, 
possibly in section 211.'' EEI maintains that such suggestion was 
rejected by Congress in favor of allowing the Commission to order 
wheeling only upon application.
---------------------------------------------------------------------------

    \267\ E.g., EEI, VA Com, Ohio Edison Southern, Utilities For 
Improved Transition, BG&E.
    \268\ See also NM Com.
---------------------------------------------------------------------------

    Detroit Edison, asserting that Cajun stands for the proposition 
that the agency must follow Congressionally mandated procedures, claims 
that the Commission can order transmission only after going through the 
procedures of section 211. Detroit Edison also argues that the 
Commission should incorporate into the final rule the various 
safeguards of section 211, such as the requirement that the utility 
receive prior notice, the requirement that transmission service be in 
the public interest, and the requirement that existing service not be 
displaced. FL Com further asserts that it was Congressional intent in 
the Energy Policy Act for wheeling to be ordered on a case-by-case 
basis pursuant to section 211.\269\
---------------------------------------------------------------------------

    \269\ See also Salt River. Moreover, FL Com states that the 
Commission should modify its hearing process to better accommodate 
state PUC participation by: (1) Holding hearings in the affected 
state; (2) teleconferencing; (3) making free transcripts available 
to states; and (4) substantially deferring to a state when the state 
commission has held a hearing on an issue in the case.
---------------------------------------------------------------------------

    EEI argues that the enactment of section 211 eliminated any 
authority the Commission had under sections 205 and 206 to order 
wheeling as a remedy for undue discrimination. It alleges that the 
Commission failed to discuss the NYSEG case concerning the relationship 
between section 211 and sections 205 and 206 in any meaningful way. 
According to EEI, the NYSEG court concluded that section 211 ``was the 
only appropriate vehicle under which the Commission could order NYSEG 
to wheel power for the municipality.'' <SUP>270 EEI further resorts to 
canons of statutory construction to conclude that ``section 211 must be 
given effect as the more specific provision and must be interpreted to 
limit the scope of sections 205 and 206.'' <SUP>271 In addition, EEI 
asserts that ``Congress had an opportunity to reject the NYSEG court's 
interpretation of the scope of sections 205, 206 and 211, but instead 
amended section 211 in a manner that is consistent with the view that 
mandatory wheeling is to be governed exclusively by section 211.'' 
Dayton P&L raises similar arguments. It notes the savings provision in 
section 212(e), but says that Congress ``would have been more specific 
if it understood that the Commission already had the authority to order 
wheeling under FPA sections 205 and 206. * * *'' <SUP>272
---------------------------------------------------------------------------

    \270\ EEI quoted the following language from NYSEG:
    Nor do we suggest that the Commission is powerless to review a 
wheeling agreement under section 206 without following the 
requirements of sections 211 and 212. If, after a hearing as 
required by section 206, the Commission determines that a particular 
rate, charge or condition is unreasonable, it can order a 
modification. But where, as here, the modification amounts to an 
order requiring wheeling, it must be preceded also by determination 
in accordance with sections 211 and 212. Simply put, we will not 
allow the Commission to do indirectly without compliance with the 
statutory prerequisites, what it could not do directly without such 
compliance. (citing Richmond Power & Light).
    \271\ See also VA Com.
    \272\ See also Carolina P&L.
---------------------------------------------------------------------------

    Associated EC argues that the NOPR appears to exceed the 
Commission's authority in that it proposes that ``wholesale buyers and 
sellers have 'equal access to the transmission grid.' '' It asserts 
that ``Section 211(a), however, makes mandatory transmission service 
available only to '[a]ny electric utility, Federal power marketing 
agency or any other person generating electric energy for sale for 
resale.' '' <SUP>273
---------------------------------------------------------------------------

    \273\ This argument is puzzling. First, section 211 does not 
control to whom access must be provided under sections 205 and 206. 
However, even if it did, Associated EC appears to misconstrue 
eligibility under section 211. An electric utility as defined in the 
FPA is any person or State agency (including any municipality) which 
sells electric energy. The definition does not say that electric 
energy must be re-sold at wholesale. Thus, an electric utility could 
be a wholesale buyer of transmission used to transmit energy for 
sale at either wholesale or retail.
---------------------------------------------------------------------------

    NE Public Power District argues that sections 211 and 212 of the 
FPA appear clearly to contemplate a case-by-case approach.<SUP>274 NE 
Public Power District adds that if the Commission believes sections 211 
and 212 are inconsistent with the public interest, it can ask Congress 
to modify those provisions. Allegheny adds that the Commission can 
order wheeling only under sections 211 and 212 on a company-specific 
basis and can use sections 205 and 206 only to evaluate the 
reasonableness of terms and conditions of voluntarily filed agreements 
or tariffs by public utilities.
---------------------------------------------------------------------------

    \274\ See also Allegheny.
---------------------------------------------------------------------------

    Utilities For Improved Transition also claims that sections 211 and 
212 override any authority the Commission might have had under sections 
205 and

[[Page 21570]]

206 to order industry-wide open access. It cites the savings clause in 
section 212(e) of the FPA as limiting the Commission's authority to 
order transmission.<SUP>275 Utilities For Improved Transition argues at 
some length that the NOPR does not meet the procedural and substantive 
standards of sections 211 and 212. It goes on to cite various passages 
from the legislative history of the Energy Policy Act as supporting the 
view that Congress intended to eliminate the Commission's authority to 
order industry-wide open access as a remedy for undue discrimination. 
According to Utilities For Improved Transition, these passages 
``unmistakably show a clear legislative intent to preclude the 
mandatory transmission that the Commission attempts here * * *.''
---------------------------------------------------------------------------

    \275\ It states that
    Section 212(e), however, provides that Sections 211 and 212 
limit or impair the Commission's authority under ``other provisions 
of law'' (a phrase including, obviously, Sections 205 and 206). On 
the face of the statute--we say again for emphasis: on the face of 
the statute--the Commission therefore does not have the authority to 
order transmission service outside the provisions of Sections 211 
and 212.
    Utilities For Improved Transition Initial Comments at 51 
(emphasis in original).
---------------------------------------------------------------------------

Commission Conclusion
    We disagree with those commenters that argue that the Energy Policy 
Act either eliminates our authority under section 206 to remedy undue 
discrimination by requiring non-discriminatory open access transmission 
or demonstrates that we never had any such authority. Nothing in 
sections 211 and 212 or in the legislative history of these sections 
indicates that Congress intended to eliminate the Commission's other, 
broader authorities under the FPA. Indeed, section 212(e) specifically 
provides:

    SAVINGS PROVISIONS.--(1) No provision of section 210, 211, 214, 
or this section shall be treated as requiring any person to utilize 
the authority of any such section in lieu of any other authority of 
law. Except as provided in section 210, 211, 214, or this section, 
such sections shall not be construed as limiting or impairing any 
authority of the Commission under any other provision of 
law.<SUP>276

    \276\ 16 U.S.C 824k (emphasis added).
---------------------------------------------------------------------------

    Utilities For Improved Transition's argument that the ``Except as 
provided'' clause limits or impairs the Commission's authority to order 
transmission service under sections 205 and 206 would make the savings 
provision meaningless. Moreover, such a reading would be entirely at 
odds with the underlying purposes of the Energy Policy Act. It would be 
ironic indeed to interpret the Energy Policy Act as eliminating our 
long-standing, broad authority to remedy undue discrimination, given 
the pro-competitive purpose of the statute.
    The legislative history also provides no support for the arguments 
that sections 211 and 212 remove or prove the non-existence of the 
Commission's authority to remedy undue discrimination by requiring non-
discriminatory open access transmission. In fact, virtually every bit 
of legislative history raised by commenters opposing the NOPR consists 
of various statements by Senator Wallop, an opponent of expanding 
transmission access under sections 211 and 212.<SUP>277 Such 
legislative history provides no insight into the meaning of a statute 
and is given little or no weight by the courts.<SUP>278
---------------------------------------------------------------------------

    \277\ In discussing the electricity provisions of the Energy 
Policy Act, Senator Wallop declared:
    It would be a mistake to take the presence of transmission 
access provisions in the Conference Report as a sign of change in 
position on my part or that of the Senate. I would have strongly 
preferred PUHCA reform without any transmission access provisions, 
as was the Senate position. However, in order to obtain the very 
significant benefits of PUHCA reform contained in the Senate bill, 
it was necessary to accept some of the House transmission access 
provisions.
    138 Cong. Rec. S17615 (daily ed. October 8, 1992).
    \278\ See, e.g., Shell Oil Company v. Iowa Department of 
Revenue, 488 U.S. 19, 29 (1988) (Shell). In Shell, the Court 
declared:
    This Court does not usually accord much weight to the statements 
of a bill's opponents. ``[T]he fears and doubts of the opposition 
are no authoritative guide to the construction of legislation.'' 
Gulf Offshore Co. v. Mobil Oil Corp., 453 U.S. 473, 483 (1981) 
(quoting Schwegmann Bros. v. Calvert Distillers Corp., 341 U.S. 384, 
394 (1951).
    See also Sutherland Statutory Construction Sec. 48.16 at 366.
---------------------------------------------------------------------------

    The only other legislative history that commenters put forth is the 
testimony of a Commission staff witness, in 1992 hearings before the 
Subcommittee on Energy and Power of the House Committee on Energy and 
Commerce. According to EEI, the witness indicated that an affirmative 
statement that the Commission could require wheeling on its own motion 
``would be needed [in the Energy Policy Act] if Congress intends for 
the Commission to be able to deal with transmission on its own motion 
and thereby go further than simply dealing with industry proposals.'' 
EEI claims that this statement demonstrates that the expanded authority 
in the Energy Policy Act ``was not intended to grant the Commission 
blanket authority to order wheeling, even as a remedy for 
anticompetitive conduct.''
    EEI's argument is misleading and disingenuous. It takes the 
witness's statements out of context, ignoring attendant testimony that 
``there are strong legal arguments that the Commission's obligation to 
protect against undue discrimination carries with it the authority to 
impose transmission requirements as a remedy for undue preference or 
discrimination,'' and the extensive legal argument, included in her 
testimony, in favor of that position--an argument that closely 
parallels the legal argument the Commission is relying on in this 
proceeding.<SUP>279 Indeed, in the face of such explicit testimony from 
the staff of the agency required to implement the statute, had Congress 
intended to limit the Commission's remedial authority under section 206 
when it amended section 211, we believe it would have explicitly done 
so in the language of the statute itself, or at least have indicated 
its intent to do so in the Conference Report on the Energy Policy 
Act.<SUP>280
---------------------------------------------------------------------------

    \279\ Hearings on H.R. 1301, H.R. 1543, and H.R. 2224 before the 
Subcommittee on Energy and Power of the House Committee on Energy 
and Commerce, 102d Cong., 1st Sess. (May 1,2 and June 26, 1991), 
Statement of Cynthia A. Marlette, Associate General Counsel, Federal 
Energy Regulatory Commission, Report No. 102-60 at 60 and 61-70. See 
also id. at 106 (``I believe that we have substantial authority 
under the existing case law to mandate access where necessary to 
remedy anticompetitive effects.'').
    \280\ At the time Congress enacted amendments to FPA section 
211, it was well aware that the Commission had unexplored 
authorities under sections 205 and 206 of the FPA to compel 
wheeling. The only explicit limitations it chose to impose on the 
Commission's wheeling authorities were those contained in sections 
212(g) and (h), which provide that no order ``under this Act'' may 
be inconsistent with any State law governing retail marketing areas 
of electric utilities (section 212(g)), or be conditioned upon or 
require the transmission of electric energy directly to an ultimate 
consumer (section 212(h)).
---------------------------------------------------------------------------

C. Comparability

1. Eligibility to Receive Non-Discriminatory Open Access Transmission
    In the NOPR, the Commission proposed to define who is eligible to 
receive service under a non-discriminatory open access tariff as 
follows:

    A non-discriminatory open-access tariff must be available to any 
entity that can request transmission services under section 
211.<SUP>281

    \281\ FERC Stats. & Regs. para. 32,514 at 33,083 (footnote 
omitted).
---------------------------------------------------------------------------

The Commission further explained that ``[u]nder section 211, any 
electric utility, Federal power marketing agency, or any other person 
generating electric energy for sale for resale may request transmission 
services under section 211.'' <SUP>282
---------------------------------------------------------------------------

    \282\ Id. at 33,083 n.195.

---------------------------------------------------------------------------

[[Page 21571]]

Comments
    PSNM believes that the NOPR properly defined customer eligibility. 
NIEP, on the other hand, believes that the proposed definition is too 
limited. It argues that the Commission should require public utilities 
to make transmission service available to all entities engaged in 
wholesale purchases or sales of power, not just to those ``generating'' 
power. Utility Working Group requests that the Commission clarify that 
eligibility is dependent not only on being the type of entity set forth 
in section 211, but on meeting the requirements of section 212(h) 
(Prohibition on Mandatory Retail Wheeling and Sham Wholesale 
Transactions) as well.<SUP>283
---------------------------------------------------------------------------

    \283\ Section 212(h) (Prohibition on Mandatory Retail Wheeling 
and Sham Wholesale Transactions).
---------------------------------------------------------------------------

    We also received several comments related to the applicability of 
the rule to foreign entities. Canada states that the requirements for 
comparability and reciprocity should be implemented in a flexible 
manner to permit Canadian utilities to have fair and competitive access 
in the U.S. electricity market. Maritime requests that the Commission 
require Canadian utilities who wish to participate in the U.S. market 
to offer other utilities the same privileges they receive in the United 
States. Southwestern argues that transmission to a foreign country is 
in interstate commerce and that a utility should therefore accommodate 
this type of transmission request under its open access tariff. El Paso 
argues that the Commission does not have the authority to condition 
access to foreign countries, but states that if the Commission 
nevertheless exercises such authority it should do so on a case-by-case 
basis. Destec asserts that

the posturing of Ontario Hydro before U.S. regulators pleading for 
open access and non-discriminatory transmission treatment--even for 
extra-territorial entities, should be met with a strong reply that 
such provisions should also be afforded transmission dependent 
entities on the Canadian side of the border. Ontario Hydro's 
aggressive pursuit of U.S. market opportunities while simultaneously 
blocking competitors through the control of their transmission 
assets can not be ignored.
Commission Conclusion
    In the Final Rule pro forma tariff the Commission has modified the 
definition of ``eligible customer'' to address concerns that in some 
respects the NOPR definition was too limited and in other respects it 
was too broad. This includes amended language to clarify that any 
entity engaged in wholesale purchases or sales of energy, not just 
those ``generating'' electric power, is eligible. It also includes 
clarification that entities that would violate section 212(h) of the 
FPA (prohibition on Commission-mandated wheeling directly to an 
ultimate consumer and sham wholesale transactions) are not eligible. 
The language also has been modified to provide that foreign entities 
that otherwise meet the eligibility criteria may obtain transmission 
services. Further, it has been modified to provide for service to 
retail customers in circumstances that do not violate FPA section 
212(h).<SUP>284
---------------------------------------------------------------------------

    \284\ We emphasize that any transmission customer must follow 
prudent utility practices so as to assure reliability.
---------------------------------------------------------------------------

    Persons that would be eligible section 211 applicants also would be 
eligible under the open access tariffs. Section 211 applicants may be 
any electric utility, Federal power marketing agency, or any other 
person generating electric energy for sale for resale.
    Section 3(22) of the FPA, as amended by the Energy Policy Act, 
defines ``electric utility'' to mean

any person or State agency (including any municipality) which sells 
electric energy; such term includes the Tennessee Valley Authority, 
but does not include any Federal power marketing agency.

Thus, as we have previously noted, municipal utilities are electric 
utilities simply by the terms of the statute.<SUP>285 In addition, we 
have also found that cooperatives and marketers are electric utilities 
as defined in the FPA.<SUP>286 Other entities that fall within the 
definition include IOUs, IPPs, APPs, and QFs that sell electric energy.
---------------------------------------------------------------------------

    \285\ New Reporting Requirement Implementing Section 213(b) of 
the Federal Power Act and Supporting Expanded Regulatory 
Responsibility Under the Energy Policy Act of 1992, and conforming 
and Other Changes to Form No. FERC-714, Order No. 558-A, 65 FERC 
para. 61,324 at 62,451 n.12 (1993).
    \286\ Order No. 558, FERC Stats. & Regs. para. 30,980 at 30,895-
96, reh'g denied, 65 FERC para. 61,324 (1993) (cooperatives are 
electric utilities); AES Power, Inc., 69 FERC para. 61,345 at 62,297 
(1995) (power marketer is an electric utility, i.e., a person 
``which sells electric energy'').
---------------------------------------------------------------------------

    We do not believe that entities that engage solely in brokering 
should be eligible. Such brokers do not take title to electricity and 
therefore do not engage in the sale of electric energy; nor do they 
generate electric energy for sale for resale.<SUP>287 Although such 
brokers are not eligible under the tariffs, they will be able to 
arrange deals because they will have access to the OASIS of all public 
utilities and will be able to solicit information from the relevant 
transmission service providers under the terms of the applicable 
tariffs.
---------------------------------------------------------------------------

    \287\ See, e.g., Citizens Energy Corporation, 35 FERC para. 
61,198 at 61,452-53 (1986).
---------------------------------------------------------------------------

    We clarify that foreign entities that otherwise meet the 
eligibility criteria must be eligible to receive service under the non-
discriminatory open access transmission tariffs.<SUP>288 We are making 
this determination pursuant to our authority under section 206 of the 
FPA to remedy undue discrimination. As we explained in the NOPR, market 
power through the control of transmission can be used discriminatorily 
to block competition. Customers in the United States should not be 
denied access to cheaper supplies of electric energy, whether such 
electric energy is from a domestic source or a foreign source. By 
making non-discriminatory access available to foreign entities that 
otherwise meet the eligibility criteria, we are assuring that customers 
in the United States have access to as many potential suppliers as 
possible. This should result in increased competition and lead to 
customers paying the lowest possible prices for their electric energy 
needs. To the extent that such an entity obtains access, however, we 
emphasize that it would be subject to all of the terms and conditions 
of the applicable open access tariff, including the requirement that it 
provide reciprocal service.
---------------------------------------------------------------------------

    \288\ In making this determination, we are not deciding whether 
these entities are eligible entities under section 211(a) of the 
FPA.
---------------------------------------------------------------------------

    Finally, we have reconsidered our NOPR position that would have 
limited eligibility to wholesale transmission customers. As we 
explained in the NOPR, the Commission's jurisdiction extends to all 
unbundled transmission in interstate commerce by public utilities. It 
is irrelevant to the Commission's jurisdiction whether the customer 
receiving the unbundled transmission service in interstate commerce is 
a wholesale or retail customer. Thus, if a public utility voluntarily 
offers unbundled retail access in interstate commerce or a state retail 
access program results in unbundled retail access in interstate 
commerce by a public utility, the affected retail customer must obtain 
its unbundled transmission service under a non-discriminatory 
transmission tariff on file with the Commission. Though the Commission 
may approve a separate retail transmission tariff when some variation 
is necessary or appropriate to meet local concerns,<SUP>289 we 
generally see no reason why retail transmission tariffs necessarily 
must be different from wholesale transmission tariffs. For that reason, 
we anticipate that in many

[[Page 21572]]

circumstances the same open access tariff that serves wholesale 
customers will be equally appropriate for retail transmission 
customers. Therefore, unless the Commission has specifically permitted 
a separate retail tariff, eligible customers under the Final Rule pro 
forma tariff must include unbundled retail customers.<SUP>290 We 
discuss this further in Section IV.I.
---------------------------------------------------------------------------

    \289\ See Section IV.I.
    \290\ The Commission has no authority to order retail 
transmission directly to an ultimate consumer or to order ``sham'' 
wholesale transmission. See FPA section 212(h). However, if such 
access occurs voluntarily or as a result of a state program, the 
rates, terms, and conditions of the access are within our exclusive 
jurisdiction if the service is provided by a public utility.
---------------------------------------------------------------------------

    While the rates, terms, and conditions of all unbundled 
transmission service will be subject to a Commission-authorized tariff, 
we will, in appropriate circumstances, give deference to state 
recommendations regarding rates, terms, and conditions for retail 
transmission service or regarding the proper transmission cost 
allocation to be used between retail and wholesale customers when state 
recommendations are consistent with our open access policies. This is 
also discussed further in Section IV.I.
    Moreover, we are mindful of the fact that we are precluded under 
section 212(h) from ordering or conditioning an order on a requirement 
to provide wheeling directly to an ultimate consumer or sham wholesale 
wheeling. We therefore clarify that our decision to eliminate the 
wholesale customer eligibility requirement does not constitute a 
requirement that a utility provide retail transmission service. Rather, 
we make clear that if a utility chooses, or a state lawfully requires, 
unbundled retail transmission service, such service should occur under 
this tariff unless we specifically approve other terms.
2. Service That Must be Provided by Transmission Provider
    In the NOPR, the Commission proposed that a public utility must 
offer to provide any point-to-point or network transmission service 
whether or not the utility provides itself that service:

    The Commission therefore proposes that all public utilities must 
offer both firm and non-firm point-to-point transmission service and 
firm network transmission service on a non-discriminatory open 
access basis in accord with the proposed rule and the attached 
appendix tariffs. The Commission believes that a utility's tariff 
must offer to provide any point-to-point transmission service and 
network transmission service that customers need, even though the 
utility may not provide itself the specific service 
requested.<SUP>291
---------------------------------------------------------------------------

    \291\ FERC Stats. & Regs. para. 32,514 at 33,079.
---------------------------------------------------------------------------

Comments
    EGA and SMUD agree that a transmission owner should offer any 
transmission service it is able to provide, even if it does not use the 
service itself.
    Public Generating Pool, an association of consumer-owned electric 
utilities, appears concerned that the Commission may interpret 
comparability broadly to require a utility to offer the same service 
provided by another utility or to offer service generally available in 
a region. Thus, it recommends that a third party seeking more service 
than a utility provides itself be required to resort to the section 211 
process.
Commission Conclusion
    Initially, we note that, with the possible exception of small 
utilities (which may qualify for a waiver, see infra), we have seen no 
evidence that public utilities are incapable of reasonably providing 
the services required in the Final Rule pro forma tariff. Nor have we 
seen evidence that utilities able to provide these services to 
themselves are choosing to forego such services. In short, we are not 
convinced that there is an appreciable difference, if any, among the 
services required in the pro forma tariff, the services utilities are 
able to provide, and the services they actually provide themselves.
    To the extent these services do differ, however, we explicitly 
adopt the proposal set forth in the NOPR. Thus, a public utility must 
offer transmission services that it is reasonably capable of providing, 
not just those services that it is currently providing to itself or 
others. Because a public utility that is reasonably capable of 
providing transmission services may provide itself such services at any 
time it finds those services desirable, it is irrelevant that it may 
not be using or providing that service today. Moreover, a public 
utility must offer these transmission services whether or not other 
utilities may be able to offer the same services and whether or not 
such services are generally available in the region (waiver of these 
requirements for small utilities is discussed in Section 
IV.K.2.).<SUP>292 However, if a customer seeks a customized service not 
offered in an open access tariff, a customer may, barring successful 
negotiation for such service, file a section 211 application.
---------------------------------------------------------------------------

    \292\ Requirements for ancillary services are discussed in 
Section IV.D.
---------------------------------------------------------------------------

3. Who Must Provide Non-Discriminatory Open Access Transmission
    In the NOPR, the Commission proposed to require all ``public 
utilities'' owning and/or controlling facilities used for transmitting 
electric energy in interstate commerce to file open access transmission 
tariffs.<SUP>293 We explained that we could not require all 
``transmitting utilities'' to file open access tariffs under sections 
205 and 206 because we do not have jurisdiction over non-public 
utilities under these sections.
---------------------------------------------------------------------------

    \293\ FERC Stats. & Regs. para. 32,514 at 33,049.
---------------------------------------------------------------------------

Comments
    Several commenters argue that the open access requirement must be 
applied to non-jurisdictional utilities that own interstate 
transmission facilities.<SUP>294 Power Marketing Association recognizes 
that this raises difficult legal issues and suggests that the 
Commission support legislation to expand the Commission's authority 
over non-jurisdictional utilities. Minnesota P&L argues that if the 
requirement is not applied to all entities that own transmission, 
jurisdictional and non-jurisdictional entities owning joint 
transmission facilities will be competitively disadvantaged due to 
unequal pricing. Union Electric argues that unless the requirement is 
extended to the 56 non-jurisdictional entities operating control areas, 
discrimination in the wholesale power markets will increase.
---------------------------------------------------------------------------

    \294\ E.g., Minnesota P&L, Power Marketing Association.
---------------------------------------------------------------------------

    A number of municipal commenters assert that the NOPR overlooks 
transmission assets jointly owned by jurisdictional and non-
jurisdictional utilities.<SUP>295 They argue that agreements regarding 
use of these assets often contain provisions prohibiting third-party 
power transfers. They further argue that such provisions should be 
nullified, and the joint owners should be required to develop equitable 
methodologies to allocate wheeling revenues among themselves.
---------------------------------------------------------------------------

    \295\ E.g., Springfield.
---------------------------------------------------------------------------

    Several cooperatives urge the Commission to clarify that contracts 
among their constituent cooperatives are not subject to any unbundling 
of existing contracts.
Commission Conclusion
    Our authority under sections 205 and 206 of the FPA permits us to 
require only public utilities to file open access tariffs as a remedy 
for undue discrimination. We have no authority

[[Page 21573]]

under those sections of the FPA to require non-public utilities to file 
tariffs with the Commission.
    However, we are concerned that if non-public utilities do not 
provide access, there will remain a patchwork of ``open'' and 
``closed'' transmission systems and the potential for distortions in 
wholesale bulk power markets. We believe that certain mechanisms exist 
that will help to alleviate these problems.
    First, as we explained in the NOPR, broad application of section 
211 will provide wider access to bulk power markets.<SUP>296 Under 
section 211, eligible entities may seek transmission service from 
``transmitting utilities,'' which section 3(23) of the FPA defines as 
``any electric utility, qualifying cogeneration facility, qualifying 
small power production facility, or Federal power marketing agency 
which owns or operates electric power transmission facilities which are 
used for the sale of electric energy at wholesale.'' We believe that 
section 211 provides us with authority to require the same quality of 
transmission service as sections 205 and 206, though the procedural 
path is more cumbersome. Thus, section 211 provides access to 
transmission systems owned or operated by non-public utilities.<SUP>297
---------------------------------------------------------------------------

    \296\ FERC Stats. & Regs. para. 32,514 at 33,050 and 33,092-93.
    \297\ As discussed in the NOPR, sections 211 and 212 require 
that applicants specify only rates, terms, and conditions of 
service, not specify transactions. Thus, applicants can file 
requests for tariffs to accommodate future, currently unspecified 
transactions, similar to the open access tariffs required by this 
Rule.
---------------------------------------------------------------------------

    Second, as we explained in the NOPR, our reciprocity requirement is 
designed to provide the widest possible use of the nationwide 
transmission grid:

    The purpose of this provision is to ensure that a public utility 
offering transmission access to others can obtain similar service 
from its transmission customers. It is important that public 
utilities that are required to have on file tariffs be able to 
obtain service from transmitting utilities that are not public 
utilities, such as municipal power authorities or the federal power 
marketing administrations that receive transmission service under a 
public utility's tariff.<SUP>298

    \298\ FERC Stats. & Regs. para. 32,514 at 33,089.
---------------------------------------------------------------------------

    Finally, again as we explained in the NOPR, the formation of RTGs 
should speed the development of competitive markets and involve more 
non-public utilities in the provision of non-discriminatory open access 
transmission.<SUP>299 In approving RTGs, our policy has been to require 
all members, whether or not they are public utilities, to offer 
comparable transmission services at least to other members.
---------------------------------------------------------------------------

    \299\ Id. at 33,095.
---------------------------------------------------------------------------

    We recognize that these solutions are not perfect. However, given 
the difficulties inherent in the statutory scheme, we believe they will 
go a long way toward effectuating transmission access by non-public 
utilities.
    One further issue involving non-public utilities concerns jointly 
owned transmission facilities. We will not allow public utilities that 
jointly own interstate transmission facilities with non-jurisdictional 
entities to escape the requirements of open access. We will require 
each public utility that owns interstate transmission facilities 
jointly with a non-jurisdictional entity to offer service over its 
share of the joint facilities, even if the joint ownership contract 
prohibits service to third parties. We urge such public utilities to 
seek mutually agreeable revisions to their agreements to permit third-
party access over all, or at least their share, of the facilities. For 
those joint ownership arrangements that include restrictions on the 
usage of jointly owned transmission facilities by third parties, we 
will require the public utilities, in a section 206 compliance filing, 
to file with the Commission, by December 31, 1996, a proposed revision 
(mutually agreeable or unilateral) to its contract with the non-
jurisdictional owner(s). This revision must be designed at a minimum to 
permit third parties to use the public utility's share of the joint 
facilities in accordance with this Rule and must provide for any needed 
cost allocation procedures between the public utility and the non-
jurisdictional owner(s).
4. Reservation of Transmission Capacity by Transmission Customers
    In the NOPR, the Commission set forth the information that a 
requester of transmission service would have to submit with a service 
request. We recognized that there may have to be a limit, for 
competitive reasons, on the information required, but also recognized 
the need to assure that no customer would reserve scarce capacity and 
then hold it without using it.<SUP>300 To avoid forcing transmission 
customers to reveal unnecessary details of their purchase or sales 
transactions, the Commission discussed several less restrictive 
options: (1) Allow the transmission provider to use or sell the 
capacity while it is unused, (2) have a pool that clears the short-term 
market, and (3) require the customer to begin using the capacity within 
some specified period or lose its reservation rights. The Commission 
requested comments on these and other possible approaches.
---------------------------------------------------------------------------

    \300\ Id. at 33,090.
---------------------------------------------------------------------------

Comments
Unused or Unneeded Transmission Capacity
    Many commenters recommend a use-it-or-lose-it rule (i.e., a 
transmission customer must use its reserved transmission capacity or 
lose its rights to that capacity).<SUP>301 Several commenters also 
recommend a number of restrictions on capacity reservations to reduce 
incentives to hoard or to cherry-pick (request to reserve firm capacity 
only during peak hours of peak seasons) existing transmission capacity. 
These include: (1) Allow requesters to reserve a place in the queue 
with a right of first refusal over later competing requests; (2) impose 
a take-or-pay charge on reservations and deny reservation holders the 
right to revenue sharing if they do not schedule or assign their 
rights; (3) limit the time period for reservations; (4) limit how far 
in advance reservations may be made for both non-firm and firm 
services; (5) maintain a price cap on the resale of transmission; (6) 
require multi-year reservations to be for sequential periods; and (7) 
require a nonrefundable fee for advance reservations of 
service.<SUP>302 Southwestern suggests that transmission tariffs 
include a provision that prevents transmission customers and the 
transmission provider from reserving and tying up firm transmission 
capacity for speculative wholesale transactions.<SUP>303
---------------------------------------------------------------------------

    \301\ E.g., Consumers Power, Northern States Power, PacifiCorp, 
Oklahoma G&E, Allegheny Power, ELCON, Public Service Co of CO.
    \302\ E.g., Northern States Power, VEPCO, Utilities For Improved 
Transition, PacifiCorp, Arizona Public Service, Dairyland, Montaup, 
Illinois Power, South Carolina E&G, Florida Power Corp, KU.
    \303\ See also NRECA.
---------------------------------------------------------------------------

    On the other hand, PSNM believes that a use-it-or-lose-it approach 
is inappropriate because any prudent utility that has reserved capacity 
would seek to sell the service it is not using so as to recover some 
portion of its fixed costs. Wisconsin P&L argues that a use-it-or-lose-
it approach would not work, would be difficult to administer, and may 
be anticompetitive.<SUP>304 Central Illinois Public Service asserts 
that a reservation holder has little incentive to hoard capacity 
because other customers can use the capacity on a non-firm basis during 
times when a reservation holder does not schedule power. It warns that

[[Page 21574]]

giving the transmission operator the ability to schedule unused 
capacity may result in undue influence and the exercise of market 
power. CA Energy Com maintains that, while reassignment would help 
prevent hoarding, it would not assure efficient use of the full 
transmission network.
---------------------------------------------------------------------------

    \304\ Wisconsin P&L notes, however, that a possible exception 
exists where a user could block the efficient transfer of power and 
then market its own power at a premium price.
---------------------------------------------------------------------------

Use of Pooling Arrangements To Prevent Improper Reservations
    Allegheny Power contends that a pooling arrangement could provide 
an incentive to hoarders to release capacity during a shortage. It 
suggests that capacity could be auctioned within a pool of available 
capacity. However, it acknowledges that an auction would be tantamount 
to allowing the network owner to sell transmission service at 
unregulated rates.
    PacifiCorp does not believe that a pooling arrangement would 
prevent capacity hoarding unless nonsequential reservations are 
prohibited. ELCON contends that a use-it-or-lose-it rule would be 
fairer and more effective than pooling.
Commission Conclusion
    Upon further consideration, we conclude that firm transmission 
customers, including network customers, should not lose their rights to 
firm capacity simply because they do not use that capacity for certain 
periods of time. Firm transmission customers that have reserved 
capacity and paid a reservation charge generally do not use the entire 
amount of reserved capacity at all times. This does not mean, however, 
that they must permanently return the unused amount to the utility. In 
the absence of evidence of hoarding or other anticompetitive practices, 
we will not limit the amount of transmission capacity that a customer 
may reserve. Firm transmission customers are in the best position to 
know the levels of electric energy they will be transmitting and the 
level of flexibility they need in carrying out their transmission 
activities. Indeed, when they are not using their reserved capacity, 
firm transmission customers remain obligated to pay the utility a 
reservation charge that covers all of the utility's fixed costs 
associated with the reserved capacity.<SUP>305
---------------------------------------------------------------------------

    \305\ A reservation charge would assure that the utility fully 
recovers its fixed costs associated with the transmission customer's 
reserved transmission capacity.
---------------------------------------------------------------------------

    Moreover, the possibility that a customer will reserve capacity and 
then hold it without using or reassigning it is mitigated because the 
utility is free to schedule and sell any unscheduled firm point-to-
point transmission capacity on a non-firm basis to any entity eligible 
to receive such service under the utility's tariff. We also note that 
it is in the economic self interest of reservation holders to make 
available unused capacity to the market.<SUP>306
---------------------------------------------------------------------------

    \306\ See Section IV.C.6.
---------------------------------------------------------------------------

    We recognize that situations could arise in which a customer 
unlawfully withholds capacity. That is, a transmission customer could 
retain capacity in a way that could have an anticompetitive effect. For 
example, a transmission customer may reserve certain capacity simply to 
prevent everyone else from using it and to make its own generation the 
only alternative available to the market. However, as described above, 
we believe that the incentives are such that parties are more likely to 
release unneeded capacity and that a generic remedy is therefore 
unnecessary. Any substantial allegations that indicate that a 
transmission customer is withholding scarce capacity in a way that has 
an anticompetitive effect would be addressed under section 206. If we 
found such allegations to be true, we could order the customer to 
return the capacity reservation right to the transmission operator. 
This approach should allay concerns that a customer may reserve scarce 
capacity and not use it, without forcing customers to demonstrate need 
or to reveal details of individual transactions.
5. Reservation of Transmission Capacity for Future Use by Utility
Comments
    EEI and many IOUs argue that native load and network transmission 
customers should have first priority to existing capacity for their 
reasonably forecasted load requirements because that capacity was 
constructed to provide service to them and was paid for by 
them.<SUP>307 EEI contends that such priority ensures equity and 
comparability based on past and future cost responsibility for the 
system. Similarly, Florida Power Corp and PECO contend that third-party 
customers should not be allowed to use transmission capacity that 
native load customers would grow into within a reasonable planning 
horizon.
---------------------------------------------------------------------------

    \307\ E.g., NYPP, Public Service E&G, Sierra Pacific Power, Ohio 
Edison. Sierra Pacific Power asserts that a utility should be 
permitted to retain capacity for native load use over the pertinent 
planning period. El Paso adds that the Commission should allow 
utilities the opportunity to reserve capacity for anticipated uses 
that, although not firm, are necessary to maintain reliability.
---------------------------------------------------------------------------

    Other commenters disagree, asserting that available transmission 
capacity must be determined in the same manner for all customers and 
that utilities should not be permitted to reserve capacity for their 
own uses.<SUP>308 NIEP argues that utilities should not be permitted to 
lock up available transmission capacity over valuable transmission 
paths and then require transmission requesters to pay for the cost of 
incremental transmission upgrades. This would let the utility avoid 
incremental transmission charges on its system. Oklahoma G&E argues 
that existing available transmission capacity should be made available 
until it is needed for native load growth. Utilicorp states that 
transmission owners should not be permitted to set aside capacity for 
sales or purchases of economy energy. CCEM argues that the centerpiece 
of comparability is that all transmission customers, including the 
merchant operations of the transmission owner, take service from 
available capacity pursuant to the same tariffs. CCEM adds that 
allowing utilities to reserve capacity based on forecasted retail and 
network loads creates an incentive for them to over-forecast their load 
to the detriment of all others. NRECA suggests that the need to 
maintain reliability should not perpetuate transmission providers' 
preferential treatment of their own transactions. It also recommends 
that, during periods when facilities are constrained, access be 
allocated based on a combination of past actual use and planned future 
use.
---------------------------------------------------------------------------

    \308\ E.g., NIEP, CCEM, Conservation Law Foundation.
---------------------------------------------------------------------------

Commission Conclusion
    We conclude that public utilities may reserve existing transmission 
capacity needed for native load growth and network transmission 
customer load growth reasonably forecasted within the utility's current 
planning horizon. However, any capacity that a public utility reserves 
for future growth, but is not currently needed, must be posted on the 
OASIS and made available to others through the capacity reassignment 
requirements, until such time as it is actually needed and used.
    In response to arguments raised by several commenters that existing 
requirements customers should have future rights to existing capacity 
beyond the terms of their contracts because of their historical use, as 
discussed previously, we believe existing customers should have a right 
of first refusal to capacity they previously used, if they are willing 
to match the rate offered by another potential customer, up to the 
transmission provider's maximum filed transmission rate at that time, 
and to accept a contract term at

[[Page 21575]]

least as long as that offered by another potential customer.<SUP>309
---------------------------------------------------------------------------

    \309\ See Section IV.A.5.
---------------------------------------------------------------------------

6. Capacity Reassignment
    In the NOPR, the Commission proposed that a tariff must explicitly 
permit reassignment of firm service entitlements.<SUP>310 We explained 
that reassignment of capacity rights could have a number of benefits: 
(1) Helping transmission users manage financial risk, (2) reducing 
transmission providers' market power by enabling transmission customers 
to compete with them, and (3) improving capacity allocation when 
capacity is constrained and some market participants value capacity 
more than current capacity holders. We requested comments on whether 
the current price cap on resale should be modified or eliminated and 
whether the transmission services described in the NOPR are suitable 
for reassignment.
---------------------------------------------------------------------------

    \310\ FERC Stats. & Regs. para. 32,514 at 33,088.
---------------------------------------------------------------------------

Comments
General
    Many commenters favor capacity reassignment and the development of 
secondary markets.<SUP>311 However, WP&L notes that reassignments 
should not be permitted over constrained interfaces if the source or 
destination of power changes, and LA DWP opposes unrestricted 
reassignment because it could cause tax-exempt financing problems for 
many public power utilities.
---------------------------------------------------------------------------

    \311\ E.g., PacifiCorp, DOJ, NIEP, ELCON, United Illuminating, 
DOD, WP&L, FTC. OK Com and FL Com favor reassignment of capacity, 
but express concerns that reliability not be affected.
---------------------------------------------------------------------------

    Many IOUs argue that the same terms and conditions of service 
applied to IOUs should be applied to resellers of transmission 
services.<SUP>312 Arizona Public Service, however, asserts that all 
unused transmission rights should not be assignable, but should be made 
available to others in a manner consistent with the contract supporting 
the rights. It argues that a network user experiencing an off-system 
network shutdown should be required during the outage to make available 
to others the path from the point that the power enters the system to 
its load. It also contends that firm transmission customers should be 
required to post their unused rights on an EBB or RIN.
---------------------------------------------------------------------------

    \312\ E.g., Northern States Power.
---------------------------------------------------------------------------

    Several commenters oppose mandatory reassignment of firm capacity 
rights.<SUP>313 NEPCO declares that if a customer is willing to pay for 
its reserved capacity, it should not be forced to reassign unused 
capacity. Nebraska Public Power District believes that mandatory 
reassignment could cause problems for publicly-owned utilities. It 
further asserts that in the gas industry the Commission did not allow 
the unregulated reassignment regime it proposes for the electric 
industry.
---------------------------------------------------------------------------

    \313\ E.g., NEPCO, Nebraska Public Power District.
---------------------------------------------------------------------------

    SoCal Edison argues that when a transmission customer resells 
transmission capacity, it should not be released from its contractual 
obligation to the transmission provider. It notes that under 
traditional contract law, a party to a contract cannot escape its 
obligations by delegating them to another.
Price Caps
    Most commenters addressing this issue support retaining the 
existing price cap on reassignments or resales.<SUP>314 Generally, 
these commenters believe that the price cap is necessary to prevent 
customers from speculating or hoarding capacity in anticipation of its 
value increasing. Public Service Co of CO believes that allowing 
assignments of capacity at prices greater than cost could prevent a 
transmission provider from offering firm capacity for legitimate long-
term transactions. TDU Systems states that a cap should remain until 
the secondary market in the relevant geographic market has been shown 
to be competitive. PA Com states that turning available capacity into a 
spot market would tie up capacity that might otherwise be used on a 
day-to-day basis and for emergencies. Still other commenters argue that 
customers should not be allowed to sell the capacity for more than the 
transmitting utility could charge.<SUP>315 Allegheny argues that any 
rule that allows resale of transmission capacity at a higher price than 
the transmission provider can achieve is ``patently illogical and 
probably illegal.'' Several utilities, including Allegheny and CSW, 
contend that if resellers can market transmission services at market 
rates, then transmission owners must be given the same opportunity.
---------------------------------------------------------------------------

    \314\ E.g., NRECA, Montana Power, PacifiCorp, NYSEG, PA Com, 
Idaho, Public Service Co of CO, FPC, Entergy, TDU Systems, Duke, 
Cajun, CVPSC, Oglethorpe, Minnesota DPS. FL Com argues that the 
price of reassignment should be capped at the contract selling 
price. WP&L argues that the price cap should be raised to the 
maximum rate allowed in the tariff under which the user purchased 
the original service.
    \315\ See also Minnesota DPS.
---------------------------------------------------------------------------

    Duquesne and United Illuminating argue that the price cap should be 
modified so that third parties are allowed to resell capacity at the 
higher of embedded costs or opportunity costs.<SUP>316 Duquesne notes 
that such a provision would be comparable to the option transmitting 
utilities now have and would be economically efficient because it would 
encourage the firm capacity owner with the lowest opportunity cost to 
resell its capacity.
---------------------------------------------------------------------------

    \316\ See also Midwest Commissions, SMUD, CCEM.
---------------------------------------------------------------------------

    A few commenters argue that the price cap should be 
eliminated.<SUP>317 IL Com claims that capacity will be made available 
to the entity that values it most and that an uncapped resale market 
cannot lead to more market power because an efficient secondary market 
cannot be monopolized. Con Ed agrees that if the secondary market is 
competitive, all entities should be allowed to sell at market-based 
rates.<SUP>318 CT DPUC argues that there should not be a price cap; 
instead, it would prefer that those holding transmission rights not be 
allowed to withhold use of any portion of their reserved transmission 
capacity in the actual moment-by-moment operation of the grid.
---------------------------------------------------------------------------

    \317\ E.g., IL Com, NEPCO, Consumers, American Wind.
    \318\ If the market is not competitive, however, Con Ed 
maintains that the cap should be retained for all entities.
---------------------------------------------------------------------------

Creditworthiness Standards
    Of those commenting on the appropriate creditworthiness standards 
for replacement customers (assignees), all favor allowing the 
transmission provider to use reasonable credit procedures to assure 
that the replacement customer is financially sound.<SUP>319 NYSEG 
suggests that, at a minimum, the same creditworthiness criteria should 
be applied to the replacement customer as are applied to the original 
customer. Oglethorpe recommends that the assignee be required to commit 
to comply with all customer obligations and to pay for any additional 
costs resulting from the assignment.
---------------------------------------------------------------------------

    \319\ E.g., PacifiCorp, NYSEG, Oglethorpe.
---------------------------------------------------------------------------

Liability for Payment
    Commenters split on whether the original customer or the 
replacement customer should be liable to the transmitting utility for 
payment for the service. One group of commenters believes that the 
original customer should remain liable for all costs and for the 
performance of all obligations.<SUP>320 Another group of commenters 
believes that the original customer should be relieved of financial 
responsibility, at least under certain circumstances.<SUP>321 For

[[Page 21576]]

example, NYSEG asserts that the original customer should be relieved of 
its obligations upon the execution of a new service agreement between 
the new customer and the provider. TDU Systems contends that the 
original customer should be relieved of future liability where the 
replacement customer meets the transmission provider's creditworthiness 
standards. Entergy argues that the original customer should remain 
liable until all obligations are fulfilled.
---------------------------------------------------------------------------

    \320\ E.g., Oglethorpe, NSP.
    \321\ E.g., NYSEG, Entergy, TDU Systems, Turlock, American Wind.
---------------------------------------------------------------------------

Commission Conclusion
    After reviewing the comments, we conclude that a public utility's 
tariff must explicitly permit the voluntary reassignment of all or part 
of a holder's firm transmission capacity rights <SUP>322 to any 
eligible customer.<SUP>323 Reassignment may be on a temporary or 
permanent basis, and must be subject to the conditions and requirements 
discussed below.
---------------------------------------------------------------------------

    \322\ The transmission provider has the same rights as any other 
potential assignee to obtain capacity that is posted on an OASIS or 
to negotiate with the assignor for any capacity the assignor seeks 
to assign.
    \323\ The public utility's tariff shall not preclude an assignor 
from including a right of recall in its agreement with an assignee.
---------------------------------------------------------------------------

    Allowing holders of firm transmission capacity rights to reassign 
capacity will: (1) Help them manage the financial risks associated with 
their long-term transmission commitments, (2) reduce the market power 
of transmission providers by enabling customers to compete, and (3) 
foster efficient capacity allocation. We offer below a number of 
clarifications and further explanations in response to concerns raised 
by commenters.
(1) Reassignable Transmission Services
    We conclude that point-to-point transmission service, because it 
sets forth clearly defined capacity rights, should be reassignable. As 
for network transmission service, we conclude that there are no 
specific capacity rights associated with such service, and thus, 
network transmission service is not reassignable.
(2) Terms and Conditions of Reassignments
a. General
    In effecting a reassignment, the assignor does not have to return 
its capacity entitlement to the original transmission provider, but may 
deal directly with an assignee without involvement of the transmission 
provider. However, an assignee must meet the eligibility standard 
established by this Rule and must comply with the reliability criteria 
of the original transmission provider. Any such transaction must be 
posted on the transmission provider's OASIS within a reasonable time 
after its effective date. Alternatively, the assignor may, if it 
wishes, request the transmission provider to effect a reassignment on 
its behalf.<SUP>324 In such a situation, the transmission provider must 
immediately post the available capacity on its OASIS. The transmission 
provider must assure that any revenues associated with the reassignment 
are credited to the assignor.<SUP>325
---------------------------------------------------------------------------

    \324\ The assignor may also request the transmission provider to 
provide the billing and payment services for the reassignment. The 
parties would negotiate terms for such an arrangement, including a 
fee for the transmission provider. If an assignor is a public 
utility, it will have to have on file with the Commission a rate 
schedule governing reassigned capacity.
    \325\ Any expenses that the public utility incurs in carrying 
out the capacity assignment program would simply be included in its 
cost of service.
---------------------------------------------------------------------------

b. Contractual Obligations
    Assignors and assignees may contract directly with each other, but 
the assignor will remain obligated to the transmission provider. This 
obligation extends to any penalties or other charges incurred by the 
assignee in its use of the reassigned capacity. The assignee will be 
liable solely to the assignor, and should it not meet its obligations, 
the assignor may cancel the assignment under their contract.
    If the transmission provider and the original customer mutually 
agree, we will permit alternatives to the above approach. For example, 
the transmission provider could agree to relieve the original customer 
of payment liability for the term of the reassignment and permit the 
assignee to pay the provider directly.
    In the case of a permanent reassignment, the transmission provider 
should not unreasonably refuse to release the assignor from liability 
if the assignee meets the transmission provider's creditworthiness 
requirements as set forth in its tariff and agrees to pay the price the 
assignor is obligated to pay the transmission provider.
c. Price Cap
    We conclude that the rate for any capacity reassignment must be 
capped by the highest of: (1) The original transmission rate charged to 
the purchaser (assignor), (2) the transmission provider's maximum 
stated firm transmission rate in effect at the time of the 
reassignment, or (3) the assignor's own opportunity costs capped at the 
cost of expansion (Price Cap). We remain convinced that we cannot lift 
the Price Cap and permit reassignments at market-based rates. Based 
upon the information available in this proceeding, we are unable to 
determine that the market for reassigned capacity is sufficiently 
competitive so that assignors will not be able to exert market power. 
Thus, we will not permit an assignor to reassign capacity at a rate in 
excess of the Price Cap. Assignees must agree, in contracting with the 
assignor, that the firm transmission capacity they will use is subject 
to the Price Cap.
7. Information Provided to Transmission Customers Comments
    Many commenters argue that in an open access, competitive 
environment, confidential and proprietary information should not be 
made publicly available through a RIN.<SUP>326
---------------------------------------------------------------------------

    \326\ Similar arguments with respect to the information that 
public utilities must provide to the Commission in standard reports 
(e.g., Form No. 1) are addressed later in this Final Rule.
---------------------------------------------------------------------------

    Several utilities assert that the existing reporting requirements 
are sufficient to support the comparability requirements of the 
proposed rule, with some modifications.<SUP>327 They note that the 
Commission's audit authority and complaint process will help enforce 
comparability requirements.<SUP>328 Central Illinois Public Service 
states that, with the availability of pricing and transaction 
information through the RIN, no further reporting requirements are 
necessary. IL Com states that additional reporting should be required 
only if clear evidence emerges of discriminatory use of the 
transmission system. Dominion Resources adds that users have no need 
for utility planning information and data on generator status and that 
disclosure of such information would place owners at a competitive 
disadvantage. VEPCO opposes the disclosure of any commercially 
sensitive information to marketers, including the utility's power 
marketing employees.
---------------------------------------------------------------------------

    \327\ E.g., PacifiCorp, NYSEG, NSP.
    \328\ See also PA Com.
---------------------------------------------------------------------------

    On the other hand, several commenters argue that the information 
submitted by public utilities may not be adequate. For example, APPA 
argues that the Commission should scrutinize closely cost 
functionalization by utilities to assure that plant in service is 
properly booked. Others recommend that the Commission put in place a 
monthly pass-through of transmission-related operating income for all 
classes of customers receiving firm transmission service, rather than 
rely on the current practice of reducing test year

[[Page 21577]]

cost of service by revenues booked to Accounts 456 and 447. Industrial 
Energy Applications recommends that utilities be required to file 
quarterly reports with the Commission that detail the transmission 
services and the pricing of their off-system power supply transactions, 
as an incentive to comply with the Commission's rule.
Commission Conclusion
    We conclude that all necessary transmission information, as 
detailed in the OASIS final rule, must be posted on an OASIS. With 
respect to generation information, we will require, consistent with the 
OASIS final rule, that information needed to verify opportunity/
redispatch costs be provided, on request, to the transmission customer 
charged. We will not require this information, or any other generation 
information,\329\ to be posted on an OASIS.\330\
---------------------------------------------------------------------------

    \329\ The prices of some ancillary services, which are posted on 
the OASIS, are based on generation costs, however.
    \330\ Because the Commission establishes many generation and all 
transmission rates on a cost basis, the Commission also will 
continue to need the information that it collects in Form No. 1 and 
other standard forms from public utilities to assure that the rates 
are just and reasonable. As we explain later in this Final Rule, the 
information provided in those forms is public information that is 
available to any transmission customer. However, because of the 
competitive changes occurring in the electric industry, we recognize 
that there may be a need to reexamine the information we collect 
from public utilities through the Form No. 1.
---------------------------------------------------------------------------

8. Consequences of Functional Unbundling
a. Distribution Function
    The NOPR proposed functional unbundling of wholesale generation and 
wholesale transmission so that the public utility as a wholesale seller 
could not gain an undue advantage from its transmission ownership. We 
did not propose to further unbundle the retail transmission and 
distribution functions from the wholesale transmission function.
Comments
    A number of commenters assert that utilities should be required to 
unbundle--either functionally or corporately--the distribution function 
from the transmission function. ELCON argues that unbundling 
distribution would help delineate state and Federal jurisdiction, 
facilitate the establishment of transmission pricing, avoid cross-
subsidization, and prepare for the customer choice (retail wheeling) 
programs that will be implemented by states in the future. It contends 
that functional distinctions between wholesale and retail service 
should be minimized.<SUP>331
---------------------------------------------------------------------------

    \331\ See also Environmental Action, Missouri Basin MPA, Texaco, 
EGA, AEC & SMEPA.
---------------------------------------------------------------------------

    Other commenters, however, oppose establishing a separate 
distribution function. DOD asserts that the Commission can address any 
problems that arise by enforcing the terms of open access tariffs and 
that the Commission should not intrude into state ratemaking.\332\
---------------------------------------------------------------------------

    \332\ See also TDU Systems, Public Service Co. of CO.
---------------------------------------------------------------------------

    Various state commissions question the workability and desirability 
of a functional test to determine the dividing line between retail 
transmission and local distribution.<SUP>333 CA Com recommends that, to 
avoid jurisdictional uncertainty surrounding functional unbundling, the 
Commission adopt a functional test for local distribution. Under this 
test, vertically integrated utilities that chose to unbundle into 
separate operating companies, including a local distribution company 
that sells only at retail, could establish a workable bright line 
between state and Federal authority without engaging in the arduous 
task of differentiating transmission from distribution.
---------------------------------------------------------------------------

    \333\ E.g., NARUC, AZ Com, CT DPUC, OK Com, FL Com, NC Com, NM 
Com.
---------------------------------------------------------------------------

    Certain IOUs echo the jurisdictional concerns raised by the state 
commissions.<SUP>334 They believe that the unbundling of the 
distribution function would create significant jurisdictional problems. 
Pacificorp also argues that unbundling of the distribution function 
would create significant jurisdictional conflict with respect to cost 
allocation.
---------------------------------------------------------------------------

    \334\ E.g., Com Ed, Citizens Utilities, PacifiCorp.
---------------------------------------------------------------------------

Commission Conclusion
    We conclude that the additional step of functionally unbundling the 
distribution function from the transmission function is not necessary 
at this time to ensure non-discriminatory open access transmission. Our 
approach to assuring such open access has two broad requirements: (1) 
Functional unbundling of transmission and generation (which includes 
separately stated rates for generation, transmission, and ancillary 
services, and a requirement that a transmission provider take service 
under its own tariff), except for bundled retail service and (2) an 
OASIS with standards of conduct. We believe that additional 
requirements are not needed now. We further address in Section IV.I the 
concerns raised regarding our proposed tests to distinguish 
transmission and local distribution.
b. Retail Transmission Service
Comments
    The majority of commenters addressing this issue believe that 
unbundling retail service is unnecessary to establish a competitive 
market and to achieve non-discriminatory open access 
transmission.<SUP>335 For example, PSNM argues that the Commission is 
not as well situated as are state regulators to oversee and supervise 
local reliability issues for retail customers. Central Illinois Public 
Service argues that due to the nature of transmission facilities and 
operations, it is not possible for the transmission provider to 
discriminate between the provision of wholesale and retail firm 
service. Several IOUs further contend that because the Commission is 
specifically precluded from mandating retail wheeling and has no 
authority over bundled retail service, the Commission cannot require 
retail service to be provided.<SUP>336
---------------------------------------------------------------------------

    \335\ E,g,, Allegheny Power, PacifiCorp, MidAmerican, PECO, 
Public Service Co. of CO, Com Ed, NARUC, NRRI, MN DPS, ND Com, FL 
Com.
    \336\ E.g., Allegheny Power.
---------------------------------------------------------------------------

    In contrast, some commenters argue that functional unbundling must 
apply to all transmission service in interstate commerce provided by 
public utilities, including the transmission component of bundled 
retail sales.<SUP>337 They believe that this is necessary to achieve 
comparability. For example, CCEM asserts that if the distribution 
function is not unbundled, the result will be service under two 
separate arrangements--an explicit wholesale transmission tariff filed 
at the Commission and an implicit retail transmission tariff governed 
by a state regulatory body. According to CCEM, failure to unbundle 
retail transmission will allow transmitting utilities to manipulate how 
they characterize and account for their own uses of transmission. ABATE 
contends that the Commission, for efficiency reasons, should encourage 
states to permit retail access. It asserts that the Commission must 
adopt a policy that signals to states how rates, terms, and conditions 
of retail service will be established; once a state sets such 
parameters, the Commission should review them.
---------------------------------------------------------------------------

    \337\ E.g., CCEM, ABATE.
---------------------------------------------------------------------------

Commission Conclusion
    Although the unbundling of retail transmission and generation, as 
well as wholesale transmission and generation, would be helpful in 
achieving comparability, we do not believe it is necessary. In 
addition, it raises numerous difficult jurisdictional issues

[[Page 21578]]

that we believe are more appropriately considered when the Commission 
reviews unbundled retail transmission tariffs that may come before us 
in the context of a state retail wheeling program. The Commission 
therefore reaffirms its decision to require the unbundling only of 
wholesale transmission from generation.<SUP>338
---------------------------------------------------------------------------

    \338\ But see discussion of buy/sell transactions in Section 
IV.I.
---------------------------------------------------------------------------

c. Transmission Provider
1. Taking Service Under the Tariff
    In the NOPR, we explained that a public utility must take 
transmission services for all of its new wholesale sales and purchases 
of energy under the same tariff of general applicability under which 
others take service.<SUP>339
---------------------------------------------------------------------------

    \339\ FERC Stats. & Regs. para. 32,514 at 33,080.
---------------------------------------------------------------------------

Comments
    A number of commenters argue that utilities should be required to 
take all of the transmission for their own use under their 
tariff.<SUP>340 CCEM asserts that a transmission owner should have to 
schedule, at arm's length, its retail transmission uses and pay posted 
rates into a separate account; otherwise the capacity might be 
overforecast at no cost.
---------------------------------------------------------------------------

    \340\ E.g., Michigan Systems, Cleveland, Municipal Energy Agency 
Nebraska, Missouri Basin MPA, TAPS, Wisconsin Municipals, LG&E, 
NIEP, CCEM.
---------------------------------------------------------------------------

    PECO requests that the Commission clarify that the requirement that 
a transmission provider take service under its own transmission tariffs 
does not apply to: (1) Retail service, (2) existing wholesale 
contracts, and (3) pooling arrangements. UNITIL claims that the 
requirement for a transmission provider to take service under its own 
tariff and to post its own tariff rate should not apply to pool 
transactions where a single pool-wide rate is applied.
    A number of IOUs contend that it is not necessary for the 
transmission provider to take service under the network tariff because 
both the transmission provider and the network customers cannot use the 
tariff to make off-system sales. LILCO states that it is appropriate to 
distinguish between a transmission owner's use of its transmission 
system to make: (1) Wholesale bulk power sales; and (2) off-system 
purchases to serve its native load retail customers. LILCO contends 
that in the second situation it should not be required to take 
transmission service under its own open access tariffs.
    EGA argues that transmission owners should be required to take 
transmission service under open access tariffs for both wholesale off-
system sales and purchases. It maintains that, as retail competition 
increases, utilities will eventually have to take retail service under 
their own tariffs. Power Marketing Association believes that 
comparability can be achieved only if transmission service provided in 
connection with coordination transactions is unbundled and the 
transmission provider takes such transmission service under its tariff.
    Consumers Power also claims that there is an inconsistency between 
the NOPR text, the tariffs, and the proposed regulatory language 
regarding whether the requirement for a utility to take service under 
its own tariff applies only to new wholesale transactions.
Commission Conclusion
    We conclude that public utilities must take all transmission 
services for wholesale sales under new requirements contracts and new 
coordination contracts under the same tariff used by others (eligible 
customers).\341\ For sales and purchases under existing bilateral 
economy energy coordination agreements, we will give an extension until 
December 31, 1996, for public utilities to take transmission service 
under the same tariff used by others.\342\ As further discussed in 
Section IV.F., we will also give an extension of time to December 31, 
1996, for certain existing power pooling and other multi-lateral 
coordination agreements to comply with this requirement. This will 
ensure that utilities live by their own rules for wholesale 
transactions and that we can achieve non-discriminatory open access 
transmission. In the case of a public utility buying or selling at 
wholesale, the public utility must take service under the same tariff 
under which other wholesale sellers and buyers take service.
---------------------------------------------------------------------------

    \341\ With the exception of certain contracts and agreements 
executed on or before 60 days after publication of the Final Rule in 
the Federal Register, the regulation we are adopting requires that 
public utilities take service under their open access tariff for 
wholesale sales or purchases of electric energy and unbundled retail 
sales of electric energy, effective on the date the public utility 
engages in such transactions.
    \342\ As discussed in Section IV.F., the Commission will not 
impose this requirement on existing bilateral non-economy 
coordination agreements, but persons may file complaints that such 
agreements need to be modified.
---------------------------------------------------------------------------

2. Accounting Treatment
    In the NOPR, we did not address any accounting aspects of our 
proposed rule.
Comments
    IOUs generally object to a requirement that they pay themselves for 
their use of the transmission system.<SUP>343 NEPCO claims that it is a 
general principle of accounting that an enterprise cannot recognize and 
record revenues to itself. NEPCO suggests that, to ensure that 
utilities' financial statements are not misleading, this aspect of 
functional unbundling can and should be accomplished through the 
ratemaking process, rather than by requiring utilities to actually 
charge themselves revenues for taking transmission services.<SUP>344
---------------------------------------------------------------------------

    \343\ E.g., EEI, Con Ed, VEPCO.
    \344\ See also NEPCO.
---------------------------------------------------------------------------

    Atlantic City Electric states that the added costs of properly 
administering and accounting for these transactions separately will 
increase prices to ultimate consumers. It contends that ensuring that 
operators do not give undue preference to transactions of the 
transmission provider makes it unnecessary for a utility to charge 
itself.
    CSW argues that some of the provisions of the tariffs were 
specifically designed for third parties and do not make sense as 
applied to the transmission provider (e.g., signing service agreements 
and running credit checks).<SUP>345
---------------------------------------------------------------------------

    \345\ See also Florida Power Corp.
---------------------------------------------------------------------------

    Most IOUs suggest that a revenue credit mechanism be used to 
account for a transmission provider's use of its system. Florida Power 
Corp states that revenue credits should be equal to the utility's 
posted rates for transmission service multiplied by the amount of 
capacity reserved and/or energy transmitted by the utility.
    Otter Tail proposes a revenue credit that allocates revenues based 
on use under the tariff of the utility's transmission investment and 
credits these revenues against the firm load customers' accounts.
    Duke asserts that the transmission provider should maintain records 
reflecting transmission for its own transactions under the tariff and 
develop appropriate revenue credits for transmission rates. It also 
believes that all firm users of the transmission system should receive 
credits for all non-firm uses.
    Allegheny Power states that the crediting of non-firm revenues to 
network customers would have to be done on an after-the-fact basis when 
their loads would be known. However, it believes that revenue crediting 
should occur only if the firm service customer has retained the utility 
to remarket the customer's unused capacity.
    Cajun proposes that all transmission revenues in excess of those 
implicitly included in the development of the transmission rates, 
including those that the utility has charged itself, be credited

[[Page 21579]]

back to the network service transmission customers on a load ratio 
share basis. If transmission service rates are formula rates that are 
recalculated annually, Cajun proposes that excess transmission revenues 
be used to offset the recalculated revenue requirement. If the rates 
are not formula rates, Cajun states that an explicit tracker with 
monthly crediting to the network customer must be used.
    To avoid cross-subsidization between affiliates and third parties, 
NRECA suggests that transmission revenues ``paid'' by a utility's 
generation function to its transmission function be credited back to 
the utility's nonaffiliated customers, and that any rate discounts 
extended to the generation function by the transmission function be 
filed with the Commission with a full explanation of why the discount 
was extended together with a showing that the discount was made 
available to all other similarly situated customers.
    APPA contends that the Commission's current system of revenue 
crediting could give transmission owners an unfair competitive 
advantage by allowing them to use the revenue credit to subsidize the 
price at which they sell power. It argues that transmission owners 
should pay the actual price of transmission rather than booking a 
revenue credit as an offset to the cost of transmission service.
    TAPS and Wisconsin Municipals argue that an essential element of 
true comparability is the ongoing pass-through to network customers of 
a load ratio share of transmission revenues generated by third-party 
and the transmission provider's off-system uses of the transmission 
system.
    Houston L&P suggests that the revenue crediting mechanism proposed 
in the NOPR could be established to recognize the utility's 
transmission service revenue and expenses in non-third-party wheeling 
transactions by reclassifying a portion of its revenue equal to the 
cost of transmission services provided to itself during such 
transactions. This mechanism would not reclassify expense accounts, but 
would distinguish that transmission portion of the total transaction's 
revenue that was associated with covering the cost of transmission 
service, using the rates charged in similar third-party transactions.
    PacifiCorp contends that the Commission should enforce the 
requirement that utilities account for revenues they pay themselves 
through the commission's audit powers and through complaint 
proceedings. It specifically recommends that each transmitting utility 
be required to indicate, in its Form No. 1 under Account 456, the 
megawatts and revenues associated with its firm and non-firm off-system 
sales.<SUP>346
---------------------------------------------------------------------------

    \346\ If the utility is not required to file a Form No. 1, 
PacifiCorp states that it should be required to file similar 
information annually.
---------------------------------------------------------------------------

    MT Com states that the embedded costs that the Commission 
functionalizes for jurisdictional purposes should be carefully 
reconciled with plant balances used to calculate other costs of 
service.
    CCEM wants each transmission provider to charge and book revenues 
into separate accounts for (1) service provided to itself and off-
system sales and third-party sales under the tariffs, (2) impact study 
costs that the provider performs for itself or an affiliate, and (3) 
ancillary service revenues, net of out-of-pocket expenses the 
transmission owner provides itself or an affiliate.
    Arizona Public Service recommends that any revenue crediting or 
booking be prospective only and that enforcement occur through the 
Commission's periodic audits and a utility's rate cases.
    Many IOUs argue that there should be no obligation to credit non-
firm transmission revenues to customers who are not using their firm 
capacity.<SUP>347 PacifiCorp contends that all non-firm revenues should 
be credited against total annual revenue requirements, resulting in 
lower rates to all customers. Wisconsin P&L maintains that non-firm 
sales revenue should be shared with all network customers.
---------------------------------------------------------------------------

    \347\ E.g., Consumers Power, Northern States Power, PacifiCorp, 
Allegheny Power.
---------------------------------------------------------------------------

    Otter Tail argues that non-firm transactions between existing 
utilities to support and achieve real-time system optimization should 
be permitted without charge to the transmission owner. CSW asserts that 
no credits should be made for the non-firm secondary service under the 
point-to-point tariff and that off-system purchases for native load 
should not result in a revenue credit.
    Southwestern suggests that the Commission not require the crediting 
of a transmission component associated with off-system purchases by the 
public utility. Southwestern argues that a credit would interfere with 
a utility's ability to buy the most economic energy for its native load 
customers. It also argues that requiring a credit is not comparable to 
what network customers pay. NEPCO points out that crediting 
transmission associated with purchases would require native load 
customers to pay the costs of the utility's purchasing off-system power 
while network customers do not have to pay a separate point-to-point 
charge for their off-system purchases. Southwestern claims that the 
crediting requirement would double-charge the transmitting utility and 
its native load customers because a utility's off-system purchases 
directly relate to the load it serves, and that load already is 
reflected in the transmission rate calculation. Southwestern also 
claims that it is unclear from the NOPR whether the Commission 
considers sales from the renewal of existing wholesale requirements 
contracts as being subject to crediting. It argues that transmission 
related to these sales should not be subject to the crediting 
requirement because this is service to native load customers.
    Brazos opposes imputing revenues associated with a utility's own 
use of its transmission system because this will artificially increase 
the cost of power and deny consumers the benefits of economy energy 
sales made at market-based prices.
Commission Conclusion
    While we used the word ``accounting'' in the NOPR, the real issue 
is assuring that utilities bear the costs associated with their own 
uses of the system in a manner comparable to how they charge others. 
Accordingly, this is a rate issue, not an accounting issue. However, we 
direct utilities to account for all uses of the transmission system and 
to demonstrate that all customers (including the transmission 
provider's native load) bear the cost responsibility associated with 
their respective uses.<SUP>348
---------------------------------------------------------------------------

    \348\ Additional guidance on this subject is in Section 
IV.G.4.g.(2)(a).
---------------------------------------------------------------------------

D. Ancillary Services

    In the NOPR, the Commission stated that several ancillary services 
are needed to provide basic transmission service to a customer. These 
services range from actions taken to effect the transaction (such as 
scheduling and dispatching services) to services that are necessary to 
maintain the integrity of the transmission system during a transaction 
(such as load following and reactive power support). Other ancillary 
services are needed to correct for the effects associated with 
undertaking a transaction (such as energy imbalance service).
    We proposed six ancillary services to be offered in an open access 
transmission tariff, which we called (1) scheduling and dispatching 
services, (2) load following service, (3) energy imbalance service, (4) 
system protection service, (5) reactive power/voltage control service, 
and (6) loss compensation service. We requested

[[Page 21580]]

comments on all aspects of ancillary services, including whether the 
identified ancillary services are appropriately defined, whether other 
services should be included, and how these services should be supplied.
    Commenters identified a number of other services that may be 
provided as part of interconnected operations. After considering the 
comments, we conclude that the following six ancillary services must be 
included in an open access transmission tariff:
    (1) Scheduling, System Control and Dispatch Service;
    (2) Reactive Supply and Voltage Control from Generation Sources 
Service;
    (3) Regulation and Frequency Response Service;
    (4) Energy Imbalance Service;
    (5) Operating Reserve--Spinning Reserve Service; and
    (6) Operating Reserve--Supplemental Reserve Service.
    A description of these services and our reasons for designating 
them as ancillary services are included in section 1 below. We also 
discuss in that section our rationale for excluding other services from 
the list of ancillary services that must be included in an open access 
transmission tariff. In section 2 below, we discuss which of the six 
ancillary services the transmission provider must provide or offer to 
provide to transmission customers, and which the transmission customer 
must purchase from the transmission provider. These requirements are 
summarized as follows:
    (1) Scheduling, System Control and Dispatch Service (Transmission 
Provider must provide and Transmission Customer must purchase from 
Transmission Provider);
    (2) Reactive Supply and Voltage Control from Generation Sources 
Service (Transmission Provider must provide and Transmission Customer 
must purchase from Transmission Provider);
    (3) Regulation and Frequency Response Service (Transmission 
Provider must offer to provide only to Transmission Customer serving 
load in Transmission Provider's control area and Transmission Customer 
must acquire, but may do so from Transmission Provider, a third party 
or self supply);
    (4) Energy Imbalance Service (Transmission Provider must offer to 
provide only to Transmission Customer serving load in Transmission 
Provider's control area and Transmission Customer must acquire, but may 
do so from Transmission Provider, a third party or self supply);
    (5) Operating Reserve--Spinning Reserve Service (Transmission 
Provider must offer to provide only to Transmission Customer serving 
load in Transmission Provider's control area and Transmission Customer 
must acquire, but may do so from Transmission Provider, a third party 
or self supply); and
    (6) Operating Reserve--Supplemental Reserve Service (Transmission 
Provider must offer to provide only to Transmission Customer serving 
load in Transmission Provider's control area and Transmission Customer 
must acquire, but may do so from Transmission Provider, a third party 
or self supply).
    Our requirement that these six ancillary services be included in an 
open access transmission tariff does not preclude the transmission 
provider from offering voluntarily to provide other interconnected 
operations services to the transmission customer along with the supply 
of basic transmission service and ancillary services.<SUP>349
---------------------------------------------------------------------------

    \349\ Of course, public utilities would have to have a rate 
schedule on file to provide other jurisdictional interconnected 
operations services.
---------------------------------------------------------------------------

1. Definitions and Descriptions
Comments
    Commenters generally agree that some ancillary services are needed 
for transmission of power. Some commenters, however, argue for a 
different name or description for the ancillary services we proposed in 
the NOPR. Others argue for a more extensive list of services.
    EEI believes that the term ``ancillary'' is a confusing description 
because the services are integral to providing transmission service. 
NERC, PSE&G, and others claim that ancillary services are not, as the 
term ``ancillary'' implies, subordinate or auxiliary to the 
transmission of power; rather such services are conjunctive and 
required to allow reliable operation of an electric system. BG&E and 
others contend that ancillary services should be defined as services 
for control area operation,<SUP>350 and not as services provided by an 
individual, noncontrol area utility. NERC proposes, and many IOU 
commenters support, an alternative name for these services, 
``Interconnected Operations Services.'' NERC contends that the 
alternative name better reflects the fact that the services are needed 
in the broader context of allowing control areas, transmission 
customers, and other operating entities to operate reliably and 
equitably.
---------------------------------------------------------------------------

    \350\ A control area is part of an interconnected power system 
with a common generation control system. It may contain one or 
several utilities. The operator of the control area is responsible 
for balancing generation and load and for maintaining reliable 
system operation.
---------------------------------------------------------------------------

    Some commenters propose a greater number of ancillary services. 
They argue that the services we proposed can be broken down into more 
discrete functions. A number of commenters provide rather lengthy lists 
of possible ancillary services to supplement those identified in the 
NOPR.<SUP>351
---------------------------------------------------------------------------

    \351\ E.g., Oak Ridge, Houston L&P, Carolina P&L, NYPP.
---------------------------------------------------------------------------

    NERC identifies twelve services, which it groups into three broad 
categories: interchange scheduling services, generation services, and 
transmission services. NERC's proposed interconnected operations 
services are:
    (a) interchange scheduling services:
    (1) System control and dispatch services; and
    (2) Accounting;
    (b) generation services:
    (1) Regulation service;
    (2) Energy imbalance service;
    (3) Frequency response service;
    (4) Backup supply service;
    (5) Operating reserve service: spinning reserve and supplemental 
reserve services;
    (6) Real power loss service;
    (7) Reactive supply (from generation resources) and voltage control 
service; and
    (8) Restoration service; and
    (c) Transmission services:
    (1) Facilities use; and
    (2) Reactive supply (from transmission resources).
    NERC also identifies dynamic scheduling as a unique type of 
dispatch service that control areas must have responsibility over to 
ensure reliability.
    Houston L&P proposes a substitute list of twenty services. NYPP 
proposes a substitute list of thirty-eight ``unbundled components for 
transmission service,'' which include twelve generation-related 
services and twenty-six operations-related services. Oak Ridge 
recommends that the Commission consider using seven ancillary services, 
which closely conform to the six services described in the 
NOPR.<SUP>352 Although Oak Ridge identifies several additional 
ancillary services, it recommends that these services not be included 
in the list of services to be required because they cannot be measured 
or because the cost

[[Page 21581]]

of metering and billing outweighs the cost of these services.
---------------------------------------------------------------------------

    \352\ Oak Ridge originally identified nineteen ancillary 
services, which included a recommended separation of the six NOPR 
ancillary services into twelve services and seven additional new 
services.
---------------------------------------------------------------------------

Commission Conclusion
    We will adopt NERC's recommendations for definitions and 
descriptions with modifications. Starting with NERC's Interconnected 
Operations Services, we identify some of these as ancillary services 
that must be offered with basic transmission service under an open 
access transmission tariff.<SUP>353 The definitions developed by NERC 
for the individual services reflect the current position of a broad 
spectrum of experts on the subject of interconnected operations. 
Adoption of NERC's terminology will provide a more universally accepted 
set of definitions of services. We will retain the term ``ancillary 
services,'' which will refer to those interconnected operations 
services that we will require transmission providers to include in an 
open access transmission tariff.
---------------------------------------------------------------------------

    \353\ NERC indicates that the list of services is a work in 
progress and therefore may not be a complete list. NERC has formed 
an independent Interconnected Operations Services Working Group 
(Working Group). The Working Group includes representatives with a 
broad range of industry interests (transmission-dependent, partial 
requirements, IPP, transmission-owning, public power). We encourage 
this effort and will consider future changes to the list of 
ancillary services or their descriptions to reflect the further 
development of concepts in this area.
---------------------------------------------------------------------------

    The interconnected operations services identified by NERC 
incorporate all of the ancillary services proposed in the NOPR. We 
believe, however, that several of the individual services identified by 
NERC do not warrant classification as unbundled ancillary services due 
to the small cost involved (e.g., accounting). NERC also has identified 
services that, while capable of being provided in the context of 
integrated operations, are more appropriately provided for in a 
separate service agreement or other contractual arrangement (e.g., 
dynamic scheduling, loss compensation service). NERC and others have 
attempted to identify all interconnected operation services that could 
be provided by a control area. The thoroughness of the comments 
received on this issue has been invaluable to the Commission's 
deliberations.
    We will require that an open access transmission tariff include the 
six ancillary services that we have identified as necessary for the 
transmission provider to offer to transmission customers. These are 
needed to accomplish transmission service while maintaining reliability 
within and among control areas affected by the transmission service. 
Other interconnected operations services, such as loss compensation 
service, may be provided by the transmission provider or third parties 
to facilitate a particular transaction or operating arrangement. We 
will not require other interconnected operations services as part of an 
open access transmission tariff. If a transmission provider supplies 
such services voluntarily, they may be added to a customer's service 
agreement with the transmission provider.
    As mentioned, we will adopt NERC's definitions with modifications, 
and we name and describe the six ancillary services below. After each 
service name, we list in parenthesis the service name in the NOPR that 
most closely corresponds to the service defined. In the discussion, we 
explain whether and how we modified NERC's term.
a. The Six Ancillary Services
(1) Scheduling, System Control and Dispatch Service (in the NOPR: 
Scheduling and Dispatching Service)
Comments
    NERC proposes a System Control and Dispatch Service, which provides 
for (i) interchange schedule confirmation and implementation with other 
control areas, including intermediary control areas that are providing 
transmission service, and (ii) actions to ensure operational security 
during the interchange transaction. A transmission customer may 
schedule interchange with another control area operator or with another 
entity inside another control area; however, the control area operators 
are responsible for confirming and implementing the interchange into or 
out of their respective areas on behalf of the transmission customer.
    NERC also proposes a separate Accounting Service, which provides 
for energy accounting and billing services associated with interchange. 
Accounting Service would be provided by the operator of the control 
area in which the transmission service takes place.
Commission Conclusion
    We adopt ``Scheduling, System Control and Dispatch'' as the name 
for an ancillary service. It substitutes for the NOPR's Scheduling and 
Dispatching Service.
    The name is NERC's recommendation with two modifications. First, we 
include the term ``scheduling'' in the name of this service because a 
control area operator/transmission provider must take on the function 
of scheduling on behalf of customers. Second, we will not require 
Accounting as a separate ancillary service. The purpose of separating 
accounting as a stand-alone service would be to allow customers to take 
it separately from scheduling and system control. However, we believe 
that accounting for scheduling, system control and dispatch is not 
separable from these other functions and that accounting costs are 
likely to be small. Therefore, accounting does not warrant separate 
service status. The cost of accounting for these services should be 
included in the cost of Scheduling, System Control and Dispatch 
Service.
(2) Reactive Supply and Voltage Control From Generation Sources Service 
(Formerly Reactive Power/Voltage Control Service)
Comments
    A number of commenters explain that reactive power and voltage 
control service is integrally related to the reliable operation of the 
transmission system. These commenters also note that reactive power and 
voltage support must be supplied at the location where it is 
needed.<SUP>354 It cannot be provided by a distant supplier.<SUP>355
---------------------------------------------------------------------------

    \354\ See, e.g., APPA.
    \355\ E.g., EEI, NERC, NYSEG, FPL, NSP.
---------------------------------------------------------------------------

    NERC indicates that reactive supply is necessary to maintain the 
proper transmission line voltage for the transaction. NERC states that 
reactive supply is provided from both generation resources and 
transmission facilities (e.g., capacitors), and lists its provision as 
two services, distinguished by the facilities that supply them.<SUP>356 
NERC further distinguishes reactive supply service based on the source 
of the need for the service: (1) Reactive supply needed to support the 
voltage of the transmission system and (2) reactive supply needed to 
correct for the reactive portion of the customer's load at the delivery 
point.
---------------------------------------------------------------------------

    \356\ See also APPA.
---------------------------------------------------------------------------

Commission Conclusion
    We adopt ``Reactive Supply and Voltage Control from Generation 
Sources'' as the name for an ancillary service. It substitutes for the 
NOPR's Reactive Power/Voltage Control Service.
    We accept NERC's identification of two ways of supplying reactive 
power and controlling voltage. One is to install facilities, usually 
capacitors, as part of the transmission system. We will consider the 
cost of these facilities as part of the cost of basic transmission 
service. Providing reactive power and voltage control in this way is 
not a separate ancillary service.
    The second is to use generating facilities to supply reactive power 
and voltage control. This use is the service

[[Page 21582]]

named here, which must be unbundled from basic transmission service.
    We note, however, that customers have the ability to reduce (but 
not eliminate completely) the reactive supply and voltage control needs 
and costs that their transactions impose on the transmission provider's 
system. For example, customers who control generating units equipped 
with automatic voltage control equipment can use those units to respond 
to local voltage requirements and thereby reduce a portion of the 
reactive power requirements associated with their transaction.<SUP>357
---------------------------------------------------------------------------

    \357\ The ability to reduce reactive power requirements will be 
affected by the location and operating capabilities of the 
generator. Any arrangement for the customer to self-supply a portion 
of reactive supply should be specified in the transmission 
customer's service agreement with the transmission provider.
---------------------------------------------------------------------------

    In addition, transmission customers that serve loads can minimize 
the reactive power demands that they impose on the transmission system 
by maintaining a high power factor at their delivery points. A poor 
power factor at a customer's delivery point creates a need for either 
transmission reactive facilities (i.e., capacitors) or local generator-
supplied voltage support.<SUP>358
---------------------------------------------------------------------------

    \358\ Transmission providers may propose delivery point power 
factor standards, including additional (penalty) charges for failure 
to maintain specified power factors, in service agreements with 
customers. We will evaluate the reasonableness of any such proposals 
by public utilities to determine whether they conform to prudent 
utility practices and are comparable to requirements imposed by the 
utility on other customers, including the utility's own requirements 
customers, and are otherwise just and reasonable.
---------------------------------------------------------------------------

    However, these transmission customer actions do not eliminate 
entirely the need for generator-supplied reactive power. The 
transmission provider must provide at least some reactive power from 
generation sources. For this reason, and because a transmission 
customer has the ability to affect the amount of reactive supply 
required, we will require that reactive supply and voltage control 
service be offered as a discrete service, and to the extent feasible, 
charged for on the basis of the amount required.<SUP>359
---------------------------------------------------------------------------

    \359\ Separation of reactive supply and voltage control from 
basic transmission service also may contribute to the development of 
a competitive market for such service if technology or industry 
changes result in improved ability to measure the reactive power 
needs of individual transmission customers or the ability to supply 
reactive supply from more distant sources. We recognize that these 
capabilities may not be fully developed at present and the ability 
to distinguish the reactive power needs of individual customers may 
be limited at first to generator control and power factor 
correction.
---------------------------------------------------------------------------

(3) Regulation and Frequency Response Service (in the NOPR: Load 
Following Service)
Comments
    Someone must supply extra generating capacity, called regulating 
margin, to follow the moment-to-moment variations in the load located 
in a control area. Following load variations is necessary to maintain 
scheduled interconnection frequency at sixty cycles per second (60 Hz).
    NERC and others support the need for someone to provide load 
following service to have generation follow a transmission customer's 
load changes; someone must supply power to meet any difference between 
a customer's actual and scheduled generation. Usually, the control area 
operator provides this service, but it is possible for a customer to 
arrange for someone else to follow its variations in load.
    Many commenters indicate that the industry commonly refers to this 
service as ``Regulation Service.'' <SUP>360
---------------------------------------------------------------------------

    \360\ E.g., NERC, EEI, Florida Power Corp.
---------------------------------------------------------------------------

    Also, NERC proposes that Frequency Response Service be identified 
as a related but distinct service. NERC indicates that all control 
areas are expected to have generation and control equipment to respond 
automatically to frequency deviations in their networks.
Commission Conclusion
    We adopt ``Regulation and Frequency Response'' as the name of an 
ancillary service. It substitutes for the NOPR's Load Following 
Service. This name conforms to the terminology recommended by NERC.
    We conclude that Regulation Service and Frequency Response Service 
are the same services that make up the Load Following Service 
referenced in the NOPR. While the services provided by Regulation 
Service and Frequency Response Service are different, they are 
complementary services that are made available using the same 
equipment. For this reason, we believe that Frequency Response Service 
and Regulation Service should not be offered separately, but should be 
offered as part of one service.
(4) Energy Imbalance Service (the Same in the NOPR)
Comments
    Many commenters explain that Energy Imbalance Service, as proposed 
in the NOPR, is necessary when transmission service is provided in a 
control area that contains the load being served.<SUP>361 Energy 
Imbalance Service supplies any hourly mismatch between a transmission 
customer's energy supply and the load being serving in the control 
area. That is, this service makes up for any net mismatch over an hour 
between the scheduled delivery of energy and the actual load that the 
energy serves in the control area. In contrast, Regulation and 
Frequency Response Service corrects for instantaneous variations 
between the customer's resources and load, even if over an hour these 
variations even out and require no net energy to be supplied.
---------------------------------------------------------------------------

    \361\ E.g., NERC, EEI.
---------------------------------------------------------------------------

Commission Conclusion
    We will adopt ``Energy Imbalance'' as the name for an ancillary 
service. This is the same name proposed in the NOPR. NERC's description 
is the same as the service proposed in the NOPR.
(5) Operating Reserve--Spinning Reserve Service and
(6) Operating Reserve--Supplemental Reserve Service (in the NOPR These 
Two Were Formerly System Protection Service)
Comments
    Many commenters express confusion regarding the NOPR term ``system 
protection.'' They indicate that the term ``system protection,'' is 
described in the NOPR as furnishing operating reserve, but has another 
meaning in the industry.<SUP>362
---------------------------------------------------------------------------

    \362\ E.g., EEI, Florida Power Corp, TVA, Wollenberg.
---------------------------------------------------------------------------

    Operating reserve is extra generation available to serve load in 
case there is an unplanned event such as loss of generation. Generation 
held for operating reserve should be located near the load, typically 
in the same control area. Operating reserve amounts are set by the 
region, subregion, or a reserve sharing group in which the transmission 
customer's load is electrically located.
    NERC and other commenters recommend the commonly-used name, 
``operating reserve,'' for this service. NERC also indicates that there 
are two types of operating reserve: spinning reserve and supplemental 
reserve.
    Spinning reserve is provided by generating units that are on-line 
and loaded at less than maximum output. They are available to serve 
load immediately in an unexpected contingency, such as an unplanned 
outage of a generating unit.
    Supplemental reserve is also generating capacity that can be used 
to respond to contingency situations. Supplemental reserve, however, is 
not available instantaneously, but rather within a short period 
(usually ten

[[Page 21583]]

minutes). Supplemental operating reserve is provided by generating 
units that are on-line but unloaded, by quick-start generation, and by 
customer-interrupted load, i.e., curtailing load by negotiated 
agreement with a customer to correct an imbalance between generation 
and load rather than increasing generation output.
Commission Conclusion
    We adopt Operating Reserve--Spinning Reserve Service and Operating 
Reserve--Supplemental Reserve Service as the names of two related, but 
distinct, ancillary services. They substitute for a single ancillary 
service in the NOPR, System Protection Service. The names conform to 
the terminology recommended by NERC. We distinguish them because these 
services may be subject to different reliability requirements; the 
resources that supply each service may not be the same; and the two 
services may be provided by different suppliers.
b. Other Services Discussed in the NOPR
    Commenters discussed whether two other services that were discussed 
in the NOPR should be designated as ancillary services.<SUP>363 
Although we do not designate these as ancillary services for purposes 
of this Rule, we discuss the names and descriptions here so that we can 
discuss our policy regarding these services.
---------------------------------------------------------------------------

    \363\ In addition, NERC designates ``facilities use service'' as 
an interconnected operations service. We note that the facilities 
use service described by NERC is simply basic transmission service, 
which must be provided under an open access tariff. We do not 
consider facilities use service to be an ancillary service.
---------------------------------------------------------------------------

(1) Real Power Loss Service (in the NOPR: Loss Compensation Service)
    In the NOPR, we proposed that Loss Compensation be an ancillary 
service.
Comments
    NERC recommends the term, ``Real Power Loss,'' to refer to energy 
consumed in transmission, much of it by resistance heating of the lines 
and transformers. Many parties, including NERC, comment that there are 
a number of ways to compensate the transmission provider for the losses 
that occur in providing transmission service. They indicate that real 
power loss service can be obtained from a variety of sources, such as 
the power supplier, the customer, a third-party, the transmission 
provider, or another control area. Also, the loss is commonly accounted 
for by a transmission customer receiving less energy at the point of 
delivery than it provides to the transmission provider at the point of 
receipt. The difference between delivered and received energy can be 
set equal to the energy lost in transmission.
Commission Conclusion
    We adopt the term ``Real Power Loss'' as the name of this 
interconnected operations service. It substitutes for the Loss 
Compensation service described in the NOPR. This name conforms to the 
terminology recommended by NERC.
    Although proposed as an ancillary service in the NOPR, we will not 
require that Real Power Loss be included as an ancillary service in an 
open access transmission tariff. It is not necessary to require the 
transmission provider to supply energy losses to the transmission to 
ensure comparable transmission access. Real Power Loss is more 
appropriately an interconnected operations service that transmission 
providers may offer voluntarily to provide to transmission customers.
    It is not necessary for the transmission provider to supply Real 
Power Loss to effect a transmission service transaction. The 
transmission provider is not uniquely situated to provide Real Power 
Loss service to its customers, nor does it have a comparative advantage 
over anyone in providing such a service. Indeed, to require the 
transmission provider to provide this service would effectively 
obligate the transmission provider to engage in a sale of power when 
such a sale is not needed to effect the transmission service 
transaction.
    As noted in the comments, customers have several options to cover 
losses that occur when electricity moves across transmission 
facilities.<SUP>364 The availability of open access permits the 
customer to obtain energy losses from many regional suppliers.
---------------------------------------------------------------------------

    \364\ See, e.g., Portland, APPA, PacifiCorp, EEI.
---------------------------------------------------------------------------

    Although we will not require the transmission provider to supply 
Real Power Loss to the transmission customer nor require the customer 
to purchase it from the transmission provider, the customer must make 
provision for Real Power Loss. It cannot take basic transmission 
service without such a provision. A customer seeking transmission 
service must bring to the transaction sufficient energy and capacity to 
replace the losses associated with its intended transaction.<SUP>365 
Consequently, we will require that the transmission customer's service 
agreement with the transmission provider identify the party responsible 
for supplying real power loss. In addition, we will require that the 
transmission provider indicate, either in its tariff or on its OASIS, 
what the energy and capacity loss factors would be for any transmission 
service it may provide so that potential customers will know the amount 
of losses to replace.
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    \365\ If a transmission provider does not charge for 
transmission used to supply losses for its own wholesale power sales 
and purchases, it may not charge others. If it charges others, it 
must charge for its own uses.
---------------------------------------------------------------------------

(2) Dynamic Scheduling (the Same in the NOPR)
    In the NOPR's discussion of Scheduling and Dispatch Service, we 
pointed out that dynamic scheduling is possible in some regions. We 
asked for comments on whether we should require dynamic scheduling as 
an ancillary service, given the complexity of the service.
Comments
    Most commenters would not have us require Dynamic Scheduling as an 
ancillary service.<SUP>366 Dynamic scheduling provides the metering, 
telemetering, computer software, hardware, communications, engineering, 
and administration required to allow remote generators to follow 
closely the moment-to-moment variations of a local load. In effect, 
dynamic scheduling electronically moves load out of the control area in 
which it is physically located and into another control area.
---------------------------------------------------------------------------

    \366\ E.g., Detroit Edison, El Paso, FPL, Minnesota P&L, NIPSCO.
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Commission Conclusion
    We adopt the name Dynamic Scheduling Service, but we will not 
designate it as an ancillary service that must be included in an open 
access transmission tariff.
    In the NOPR, we noted that Dynamic Scheduling could be used in a 
transmission transaction if it is technically feasible to do so without 
adversely affecting reliability. We did not propose in the NOPR that 
Dynamic Scheduling be named an ancillary service. Although Dynamic 
Scheduling is closely related to Scheduling, System Control and 
Dispatch Service, it is a special service that is used only 
infrequently in the industry. It uses advanced technology and requires 
a great level of coordination. Each Dynamic Scheduling application has 
unique costs for special telemetry and control equipment, making it 
difficult to post a standard price for the service.
    Consequently, we will not require that the transmission provider 
offer Dynamic Scheduling Service to a transmission customer, although 
it may do so voluntarily. If the customer wants to

[[Page 21584]]

purchase this service from a third party, the transmission provider 
should make a good faith effort to accommodate the necessary 
arrangements between the customer and the third party for metering and 
communication facilities.
c. Other Services Not Discussed in the NOPR
Comments
    Some commenters identified several other services that were not 
discussed in the NOPR, which they recommend we require to be provided 
as ancillary services.<SUP>367 Examples are emergency power, 
supplemental power, and inadvertent power.
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    \367\ E.g., NERC, Carolina P&L, Oak Ridge, Houston L&P.
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Commission Conclusion
    We believe that these other services generally refer to either (1) 
generation services that are not related to providing transmission or 
(2) a subpart of a service discussed above, the cost of which is not 
easily separable from the other service. Consequently, we will not name 
any of these services as an ancillary service that a transmission 
provider will be required to offer separately under an open access 
transmission tariff. However, generation-related services may be 
offered voluntarily to the transmission customer.
    We discuss below two of these proposed generation-related ancillary 
services, which NERC included among its proposed interconnected 
operations services.
(i) Backup Supply Service
Comments
    NERC explains that Backup Supply is electric generating capacity 
and energy that is provided to the transmission customer as needed (1) 
to replace the loss of its generation sources and (2) to cover that 
portion of the customer's load that exceeds its generation supply for 
more than a short time. NERC notes that Backup Supply Service is a 
long-term service, which distinguishes it from Operating Reserve 
Service and Energy Imbalance Service. Backup Supply service replaces 
temporary use of operating reserves; it serves load after operating 
reserves are returned to standby mode to maintain operating reserves at 
required levels. Backup Supply may last for hours, weeks, or longer. 
NERC indicates that a transmission customer could reduce its need for 
backup supply service by using interruptible load control or active 
demand-side management control, or both.
Commission Conclusion
    We accept the term ``Backup Supply'' as the name for this 
interconnected operations service, but we will not require this service 
as an ancillary service under an open access transmission tariff. 
Backup Supply Service is not required for comparable open access 
transmission service.
    Backup Supply Service is an alternative source of generation that a 
customer can use in the event its primary generation source becomes 
unavailable for more than a few minutes. Although we believe that the 
two short-term operating reserve services (spinning and supplemental) 
are necessary to support transmission, we conclude that long-term 
service is not necessary. Backup Supply is a generation service that 
may reasonably be viewed as the responsibility of the transmission 
customer, who may contract for backup service or curtail load.
    We will impose no obligation on the transmission provider to 
provide power to the customer for a time longer than specified in the 
tariff for the customer's own backup power supply to be made available. 
The transmission provider is obligated to protect against emergencies 
for a short time; it has no obligation to furnish replacement power on 
a long-term basis if the customer loses its source of supply. The 
transmission provider has no obligation to provide power for the weeks 
necessary for unit maintenance, for example.
    The transmission provider is not uniquely situated to provide 
Backup Supply Service to its transmission customers, nor does it have a 
comparative advantage over others in providing such service. Moreover, 
as Backup Supply Service may require substantial amounts of generation 
capability, it is inappropriate to require the transmission provider to 
assume significant generation responsibilities as we functionally 
unbundle transmission from generation.
    Although the transmission provider will not be required to offer 
this service to transmission customers, it may offer voluntarily to 
provide Backup Supply Service to its transmission customers. Any 
arrangements for the supply of such service by the transmission 
provider should be specified in the customer's service agreement.
(ii) Restoration Service
Comments
    NERC states that Restoration Service provides facilities and 
procedures to enable (1) a transmission provider to restore its system 
and (2) a transmission customer to start its generating units or 
restore its loads if local power is unavailable. Other commenters refer 
to Restoration Service as Blackstart Service, which may be provided by 
the operator of the host control area, another control area operator, 
or another generation supplier.<SUP>368
---------------------------------------------------------------------------

    \368\ E.g., Atlantic City, Oak Ridge.
---------------------------------------------------------------------------

    According to NERC, close coordination with the host control area 
operator is absolutely necessary during system restoration operations. 
Under current industry practice, each control area operator is 
responsible for implementing a restoration plan in coordination with 
non-control area utilities as well other power producers. Many large 
generating units require startup power to restart after being out of 
service. Startup power may be provided, for example, by self-contained 
diesel engine generator sets located at a generating plant. If electric 
power is not available from the grid, some and perhaps many plants must 
obtain the necessary power from their auxiliary generators to restart 
plants and return the grid voltage to the proper level. Other 
generators without blackstart capability may rely on power from the 
grid to restart, once the grid is energized by others. NERC notes, 
however, that it may be inappropriate to rely completely on power from 
the grid for restart power because power from the grid may be 
unavailable or insufficient. Consequently, at least some power plants 
must have internal auxiliary power sources.
Commission Conclusion
    We accept the term ``Restoration'' as the name for this 
interconnected operations service. We will not require the transmission 
provider to offer Restoration Service as a separate ancillary service 
in an open access transmission tariff.
    Comments on Restoration Service appear to describe two services, 
blackstart service and planning for system restoration. Presumably, 
each utility and power producer will do its part through voluntary 
coordination and self-interest to ensure a reliable and adequate source 
of startup power for its generating units. We will not require a 
transmission provider to provide blackstart capability to transmission 
customers. Generators without blackstart capability can instead 
purchase blackstart power from any power supplier connected to the grid 
at an appropriate power price, if such service is available after a 
contingency is corrected.

[[Page 21585]]

    The obligation to plan for restoration capability is a system 
control area function that rests with the transmission provider and the 
operator of the control area in which the transmission provider is 
located. The transmission provider (or its associated control area 
operator) generally makes arrangements with enough generators to 
provide the system with this capability at strategic locations on the 
transmission system. Thus, restoration planning is intrinsic to the 
transmission provider's basic transmission service and included in its 
cost.
2. Obligations of Transmission Providers and Transmission Customers 
With Respect to Ancillary Services
    In the NOPR, the Commission proposed that public utilities required 
to file open access transmission tariffs also be required to provide 
unbundled ancillary services to transmission customers. Although the 
NOPR included a list of ancillary services to be offered by 
transmission providers, the NOPR did not indicate whether a customer 
must take basic transmission service from the transmission provider to 
be eligible to require the transmission provider to supply ancillary 
services. Comments on these issues are summarized below.\369\
---------------------------------------------------------------------------

    \369\ Some commenters suggest that transmission providers be 
required to provide, or transmission customers be required to 
purchase or self-supply, certain services other than the six 
ancillary services that we will require to be included in an open 
access transmission tariff. Because we will not require the 
transmission provider to offer any services other than basic 
transmission service and the six ancillary services, comments on 
requirements to provide or take other services are not included in 
the summary.
---------------------------------------------------------------------------

Comments
    Several commenters \370\ distinguish generation-related ancillary 
services from others. Generation-related services are those that 
require the provider to have extra generating capacity or to provide 
electric energy. The remaining ancillary services are called 
transmission-related services or control area services. Transmission-
related services would involve, for example, voltage support from 
transmission facilities. An example of a control area service is system 
control and dispatch. Commenters do not agree on how each service 
should be classified.
---------------------------------------------------------------------------

    \370\ E.g., NERC, Tallahassee, IL Com.
---------------------------------------------------------------------------

    Many commenters state that only control area operators should be 
allowed to offer certain ancillary services, such as scheduling, system 
control and dispatch.\371\ They believe that otherwise reliability 
might suffer.
---------------------------------------------------------------------------

    \371\ E.g., BG&E, Minnesota P&L, Florida Power Corp.
---------------------------------------------------------------------------

    Minnesota P&L states that certain ancillary services (e.g. reactive 
power from generators, load following, frequency control) should be 
provided exclusively by the operator of the control area where the load 
resides.\372\ Minnesota P&L indicates that obtaining these services 
externally could jeopardize reliability. Several commenters claim that 
a control area operator must provide the scheduling, system control and 
dispatch service and reactive power supply service (except in cases 
where the customer's load is very close to the generating source).\373\ 
Numerous commenters indicate that load following (now called Regulation 
and Frequency Response Service) generally is provided only by a control 
area operator.\374\
---------------------------------------------------------------------------

    \372\ See also Florida Power Corp and Montana Power.
    \373\ E.g., Carolina P&L, Texas Utilities, NERC, PSE&G.
    \374\ E.g., SCE&G, Montana Power, NIPSCO, EEI, PacifiCorp. EEI 
and PacifiCorp indicate that dynamic scheduling of load following 
service is an exception to the general practice of the control area 
operator providing load following service.
---------------------------------------------------------------------------

    EEI and other commenters state that energy imbalance service must 
be provided by either the control area operator or some other entity 
that is in the control area where the customer's load is located and 
has real-time response capability.\375\ NYSEG points out that 
transmission providers generally are also control area operators and 
thus automatically provide energy imbalance service to maintain 
interchange flows and control area reliability. For this reason, NYSEG 
believes it is important that this service remain a responsibility of 
the transmission provider.
---------------------------------------------------------------------------

    \375\ E.g., Montana Power, TDU Systems.
---------------------------------------------------------------------------

    SC Public Service Authority contends that ancillary services can be 
provided only by an entity large enough to operate at a NERC regional 
scale. It states that ancillary services protocols must be established 
regionally to support regional transmission services.
    Other commenters disagree. They argue that all the generation-
related ancillary services identified in the NOPR can be obtained from 
sources other than the transmission provider.\376\ American Wind 
believes the ability of a transmission customer to self-supply 
ancillary services or purchase them from a third party will help to 
curb inflated prices for such services. Southwest TDU Group also claims 
that permitting entities outside the transmission provider's control 
area to provide ancillary services will enhance competition and reduce 
the need for Commission oversight of charges for ancillary services.
---------------------------------------------------------------------------

    \376\ E.g., Tallahassee, Wisconsin Municipals, IL Com.
---------------------------------------------------------------------------

    A majority of commenters support the view that the transmission-
providing public utility should provide ancillary services. Many 
commenters do not discuss the services individually but present their 
views generally on the provision of ancillary services. Missouri-Kansas 
Industrials and CCEM support a requirement that utilities make 
ancillary services available through a tariff. They argue that, from a 
customer's point-of-view, it is extremely critical that a transmission 
provider be required to furnish these services under a regulated, 
nondiscriminatory, cost-based tariff format. NIEP argues that, until a 
fully competitive market for ancillary services develops, transmitting 
utilities should be obligated to provide or arrange for any and all of 
the NOPR ancillary services, to the extent that the transmission 
customer desires such services. Direct Service Industries emphasizes 
that a transmission provider should be required to provide any 
ancillary service that it is capable of supplying. Direct Service 
Industries and Utilities For Improved Transition claim that open access 
tariffs should state clearly that the transmission provider must secure 
ancillary services for a transmission customer if the transmission 
provider is not able to provide these services itself. Large Public 
Power Council contends that, during the transition to a competitive 
market for generation-related ancillary services, transmission 
providers should be required to provide all ancillary services related 
to generation that existing customers now take on a bundled basis. OH 
Com notes that transmission owners, by virtue of their position as 
transmission owners, are necessarily the providers of last resort for 
certain ancillary services. OH Com therefore believes that only 
transmission providers should provide ancillary services.
    Several non-IOU, transmission-owning commenters, however, urge that 
the Commission not require transmission providers to provide ancillary 
services that they cannot physically supply, i.e., if they lack 
sufficient generation, lack control area facilities, or have slow-
responding generating units.\377\ NRECA and TDU Systems also state that 
many cooperatives and transmission

[[Page 21586]]

dependent systems presently obtain ancillary services from control area 
utilities under specific contract terms. Consequently, if their member 
systems are asked to provide transmission service, they may not be able 
to take on the obligation to secure ancillary services under their 
existing contracts for transmission customers. Soyland and Pacific 
Northwest Coop argue that a transmission provider should not be 
required to supply services that it does not provide to its native 
load.
---------------------------------------------------------------------------

    \377\ E.g., OVEC, OG&E, Memphis, Nebraska Public Power, TDU 
Systems, TANC, San Francisco, Brazos.
---------------------------------------------------------------------------

    Most IOU commenters and others oppose a requirement that the 
transmission provider be obligated to provide generation-related 
ancillary services. They offer the following reasons: (1) The need for 
such services differs from one transaction to the next; (2) a 
transmission provider is neither uniquely qualified to provide these 
services, nor is it essential that such provider be the one providing 
these services in order to effect a transaction; (3) until it is 
demonstrated that these services cannot be obtained from a source other 
than the transmission provider, it is inappropriate to require 
transmission providers to supply such services; and (4) a transmission 
provider should have no residual obligation as a provider of last 
resort to plan its system to have generating resources available for 
the supply of ancillary services.\378\ IL Com also contends that 
utilities should not be required to provide generation-related 
ancillary services under general transmission service tariffs if such 
services can be obtained from the bulk power market.
---------------------------------------------------------------------------

    \378\ E.g., PSNM, Atlantic City, Centerior, UWG, Texas 
Utilities, Entergy, LG&E, Montana Power, FPL, United Illuminating, 
Large Public Power Council, Christensen.
---------------------------------------------------------------------------

    Other IOU commenters argue that there is a fundamental 
inconsistency between an obligation to provide or obtain ancillary 
services for customers and the NOPR's unbundling requirement. For 
example, BG&E claims that it is inconsistent to require the traditional 
vertically integrated utility to functionally unbundle and also to 
remain responsible for providing at cost-based rates what should be 
competitively-priced generation services. Florida P&L and other IOU 
commenters argue that providing generation-related ancillary services 
effectively imposes the load-serving obligation of the transmission 
customer on the transmission provider.
    However, some IOU commenters contend that the transmission provider 
or its agent should be required to provide certain ancillary 
services.\379\ NIPSCO and PacifiCorp believe that load following (now 
called Regulation and Frequency Response Service) should be provided 
only by the transmitting utility, especially if the customer's load and 
resources are located in the control area operated by the transmitting 
utility. EEI contends that a third-party generator should have the 
opportunity to provide regulation service if it resides in the 
transmission provider's control area and coordinates its actions with 
the control area operator.
---------------------------------------------------------------------------

    \379\ E.g., NIPSCO, PacifiCorp, Orange & Rockland, Allegheny, 
NYSEG, EEI.
---------------------------------------------------------------------------

    IN Com and NY Com recommend that the Commission provide flexibility 
in assessing responsibility for the supply of ancillary services. MN 
DPS recommends that an individual transmission provider should not be 
required to file an individual tariff for ancillary services if it is a 
member of an RTG whose tariffs adequately cover the same services.
    EEI contends that a control area utility should not be required to 
provide ancillary services to a third party outside its control area. 
EEI also argues that, if the transmission provider is not a control 
area, it should not be required to procure ancillary services from a 
control area on behalf of a third party seeking service over its 
system. Rather, the third party should be responsible for procuring the 
ancillary services it needs. Other IOU commenters argue that the 
responsibility to acquire ancillary services belongs to the 
transmission customer, not the transmission provider.<SUP>380
---------------------------------------------------------------------------

    \380\ E.g., BG&E.
---------------------------------------------------------------------------

    Many IOU commenters express concern that ancillary services be 
offered and taken on a symmetrical basis, i.e., if transmission 
providers are uniquely situated to provide the service, customers 
should likewise be required to take and pay for the service from such 
transmission providers.\381\ BG&E claims that it is patently unfair to 
give third-party users the option not to purchase ancillary services 
that the transmission provider must offer. BG&E argues that, if 
transmission providers have an obligation to provide ancillary 
services, equity dictates that transmission customers have a 
corresponding obligation to take those services or compensate 
transmission providers for the costs associated with the unused 
capabilities. United Illuminating argues that the requirement to 
provide service without a corresponding obligation to purchase service 
unfairly burdens the transmission provider and skews competition in 
favor of transmission customers.
---------------------------------------------------------------------------

    \381\ E.g., CSW, BG&E, ConEd, United Illuminating, Ohio Edison, 
Atlantic City, Centerior, SoCal Edison, Duke, EEI.
---------------------------------------------------------------------------

    Other non-IOU commenters oppose a symmetric obligation to provide 
and purchase particular ancillary services.\382\ Ontario Hydro and 
others claim that the customer should decide on a case-by-case basis 
which ancillary services it needs to purchase.
---------------------------------------------------------------------------

    \382\ E.g., RUS, TDU Systems, DE Muni.
---------------------------------------------------------------------------

    BPA and BG&E assert that transmission providers should be able to 
require that the party receiving the power, which may not be the 
transmission customer, be responsible for acquiring ancillary services. 
This would allow the transmission provider to establish the appropriate 
contractual arrangements with the party that is actually receiving the 
energy and avoid shifting responsibility to a party that is merely 
arranging the transmission service.
    A number of IOU commenters express concern that customers may 
``lean'' on a transmission provider's system for ancillary services. 
That is, they worry that the transmission customer may not purchase an 
ancillary service but nevertheless rely on the transmission provider to 
provide it. Commenters propose various remedies to address this 
concern. NIEP, Dayton P&L and others argue that the Commission should 
require that, as a prerequisite to basic transmission service, the 
transmission customer has either arranged to obtain ancillary services 
from the transmission provider or has demonstrated it has an 
arrangement with an alternative supplier that is reliable and 
sufficient to satisfy the ancillary service needs associated with the 
transmission service transaction. NYPP believes that, if the customer's 
method of providing ancillary services does not meet the standards of 
the transmission provider, the transmission provider should be able to 
require that the transmission customer find another ancillary service 
supplier or purchase the service directly from the transmission 
provider at its tariff rates.\383\ EEI proposes that penalties be 
permitted as a backstop if the market cannot resolve the ``leaning'' 
problem. VEPCO suggests that utilities should have the option to 
require customers to maintain backup supply reserves.
---------------------------------------------------------------------------

    \383\ See also NYSEG, Ohio Edison.
---------------------------------------------------------------------------

Commission Conclusion
    The NOPR proposed that six ancillary services be included in an 
open access transmission tariff. Some commenters interpret the NOPR to 
require that transmission providers make a ``universal'' offer of 
unbundled ancillary

[[Page 21587]]

services, i.e., an offer to any transmission customer regardless of 
location and whether the transmission customer would also be taking 
basic transmission service from the supplier of ancillary 
services.\384\ Such interpretation is incorrect; it goes beyond what is 
required for comparability. These services are required to be provided 
only to customers taking basic transmission service. However, 
transmission providers may offer these services on a voluntary basis to 
other customers if technology permits.
---------------------------------------------------------------------------

    \384\ E.g., PSNM, Atlantic City, Centerior, Texas Utilities, 
Entergy, FPL, Utility Working Group.
---------------------------------------------------------------------------

    Transmission through or out of a control area requires fewer 
ancillary services from the operator of the control area than 
transmission within or into a control area to serve loads in the 
control area. If the requested transmission service transaction 
involves more than one control area, i.e., the receipt point and 
delivery point of transmission service are located in different control 
areas, certain ancillary services will be needed only in the control 
area where the transmission customer's load is located.
    We will distinguish two groups or categories of ancillary services: 
(1) Services that we will require the transmission provider to provide 
to all its basic transmission customers, and (2) services that we will 
require the transmission provider to offer to provide only to 
transmission customers serving load in the provider's control area. The 
first group is comprised of (i) Scheduling, System Control and Dispatch 
and (ii) Reactive Supply and Voltage Control from Generation Services. 
The second group is comprised of (i) Regulation and Frequency Response, 
(ii) Energy Imbalance, (iii) Operating Reserve--Spinning, and (iv) 
Operating Reserve--Supplemental.
    With respect to the first group of ancillary services, we conclude 
that the transmission provider that operates a control area is uniquely 
positioned to provide these services. Thus, as stated above, we will 
require the transmission provider that operates a control area to 
provide these ancillary services. We will also require that the 
transmission customer purchase these services from the transmission 
provider, as explained in the next section.
    With respect to the second group of ancillary services, we conclude 
that the transmission provider is not always uniquely positioned to 
provide these services, although in many cases it may be the only 
practical source. Thus, we will require the transmission provider to 
offer to provide the ancillary services in the second group to 
transmission customers serving load in the transmission provider's 
control area. We also will require the transmission customer serving 
load in the transmission provider's area to acquire these services, but 
it may do so from the transmission provider, a third party or self-
supply. These ancillary services must be provided by someone if the 
system is to be operated reliably; the customer may not decline the 
transmission provider's offer of ancillary services unless it 
demonstrates that it has acquired the services from another source. The 
transmission provider may require the customer to decide which of these 
ancillary services it will purchase from the transmission provider when 
it applies for basic transmission service.
    If the transmission provider is a public utility providing basic 
transmission service but is not a control area operator, it may be 
unable to provide some or all of the ancillary services we require 
without substantial investment. In this case, we will allow the 
transmission provider to fulfill its obligation to provide, or offer to 
provide, ancillary services by acting as the customer's agent. We will 
require the transmission provider to offer to act as agent for the 
transmission customer to secure these services from the control area 
operator.<SUP>385 The customer may have the transmission provider act 
as agent or may secure the ancillary services directly from the control 
area operator. As stated above, the customer may also secure the second 
group of ancillary service from a third party or by self-supply.
---------------------------------------------------------------------------

    \385\ The requirement to offer to act as agent is in lieu of the 
requirement for the transmission provider to supply the ancillary 
service to the transmission customer. Many commenters asked that we 
not require the transmission provider to acquire the capacity to 
provide ancillary services that it does not provide for itself but 
acquires from its control area operator. E.g., EEI, NRECA, BPA, TDU 
Systems.
---------------------------------------------------------------------------

    If the transmission provider is a public utility that is not a 
control area operator, but its control area operator is a public 
utility, the control area operator must offer to provide all ancillary 
services to any transmission customer that takes transmission service 
over facilities in its control area whether or not the control area 
operator owns or controls the facilities used to provide the basic 
transmission service.<SUP>386
---------------------------------------------------------------------------

    \386\ If the transmission provider is a control area operator 
but not a public utility, we can order transmission services only 
upon application, pursuant to section 211 and 212 of the FPA. 
However, the provision of transmission services by non-public 
utilities would be necessary to satisfy the reciprocity condition in 
public utilities' open access transmission tariffs.
---------------------------------------------------------------------------

    We discuss the requirement to supply and purchase each ancillary 
service individually below.
a. Ancillary Services Required To Be Provided by Transmission Provider 
for All of Its Transmission Customers
(1) Scheduling, System Control and Dispatch Service
    We conclude that this service is necessary to the provision of 
basic transmission service within every control area. As NERC and other 
commenters point out, Scheduling, System Control and Dispatch Service 
can be provided only by the operator of the control area in which the 
transmission facilities used are located.<SUP>387 This is because the 
service is to schedule the movement of power through, out of, within, 
or into the control area.
---------------------------------------------------------------------------

    \387\ E.g., Carolina P&L, Texas Utilities, PSE&G.
---------------------------------------------------------------------------

(2) Reactive Supply and Voltage Control Service From Generation Sources
    We conclude that this service is necessary to the provision of 
basic transmission service within every control area. Because reactive 
power cannot be transmitted for significant distances, the local 
transmission provider has to supply reactive power from generation 
sources. It is often uniquely situated to supply reactive power. The 
transmission provider or the operator of the control area in which the 
provider is located cannot avoid supplying it to the transmission 
customer, and the transmission customer cannot avoid taking at least 
some of this service from the transmission provider. Although a 
customer is required to take this ancillary service from the 
transmission provider or control area operator, it may reduce the 
charge for this service to the extent it can reduce its requirement for 
reactive power supply.
b. Ancillary Services Required To Be Offered Only to Transmission 
Customers Serving Loads in the Transmission Provider's Control Area
(1) Regulation and Frequency Response
    Regulation and Frequency Response Service is not required for 
transmission out of or through the transmission provider's control 
area. We conclude that this service must be offered only for 
transmission within or into the transmission provider's control area to 
serve load in the area. Customers may be able to satisfy the regulation 
service obligation by providing generation with

[[Page 21588]]

automatic generation control capabilities to the control area in which 
the load resides. Dynamic scheduling may also be used to electronically 
``move'' a remote generating unit into the appropriate control area. 
For customers to take advantage of these developments, a transmission 
provider is required to identify the regulating margin requirements for 
transmission customers serving loads in its control area and develop 
procedures by which customers can avoid or reduce such requirements.
(2) Energy Imbalance
    We conclude that Energy Imbalance service must be offered for 
transmission within and into the transmission provider's control area 
to serve load in the area.
    Energy imbalance represents the deviation between the scheduled and 
actual delivery of energy to a load in the local control area over a 
single hour. A transmission customer can reduce or eliminate the need 
for energy imbalance service in several ways. A customer can avoid 
taking energy imbalance service if it controls generation with load-
following capabilities located in the control area. The Final Rule pro 
forma tariff allows unlimited changes before the hour at no additional 
charge to a customer's hourly schedule of energy deliveries to the 
control area. By changing its schedule more frequently (based on 
updated load information, for example), a customer can reduce or avoid 
energy imbalance charges. Other customer options to reduce or avoid 
energy imbalance charges include (i) establishing the load as a 
separate control area island within the transmission provider's control 
area with its own generation and load and (ii) removing the customer's 
load from the transmission provider's control area through dynamic 
scheduling.<SUP>388
---------------------------------------------------------------------------

    \388\ Some of these options (e.g., establishing a separate 
control area), while technically feasible, may be too costly or 
otherwise inadvisable.
---------------------------------------------------------------------------

(3) Operating Reserve--Spinning
(4) Operating Reserve--Supplemental
    We conclude that Operating Reserve--Spinning and Operating 
Reserve--Supplemental must be offered for transmission within and into 
the transmission provider's control area to serve load in the control 
area. Reserves should be located near load in case of unplanned 
unavailability of generating units serving load in the control area. We 
will permit transmission providers to rely upon prevailing regional 
practices to set reserve criteria. Transmission providers are required 
to facilitate efforts by customers to meet Operating Reserve 
obligations with their own generating resources or from third-party 
sources if they can satisfy the regional criteria.
    If a customer uses either type of operating reserve, it must 
expeditiously replace the reserve with backup power to reestablish 
required minimum reserve levels.
3. Unbundling and Bundling Ancillary Services
a. Services That Can Be Bundled With Transmission Service
    In the NOPR, the Commission proposed that transmission providers 
should be required to offer ancillary services as discrete services, 
unbundled from basic transmission service.
Comments
    While most commenters support the approach to unbundling the 
ancillary services proposed in the NOPR, a number of commenters argue 
that, for technical and administrative reasons, certain services should 
be bundled with basic transmission service. For example, some 
commenters assert that Reactive Supply and Voltage Support service 
should be bundled with basic transmission service.\389\ They argue that 
this service is integrally related to the operation of the transmission 
system, that it must be provided at or near the point of need, and that 
its costs are difficult to isolate and account for.\390\ Other 
commenters argue that scheduling and dispatch service, for similar 
reasons, should be bundled with basic transmission service.\391\
---------------------------------------------------------------------------

    \389\ E.g., Carolina P&L, NYSEG, FPL, NSP, WP&L, Orange & 
Rockland, Arizona, Salt River, SC Public Service Authority, Brazos, 
NY Com.
    \390\ See, e.g., Carolina P&L Initial Comments at 56.
    \391\ See, e.g., CCEM, Carolina P&L, NYSEG, CINergy.
---------------------------------------------------------------------------

    A few commenters suggest that other services could be bundled with 
the basic transmission service. For example, NYSEG identifies energy 
imbalance service as a candidate for bundling. EEI identifies frequency 
regulation and NYMEX identifies frequency control as services that 
could be bundled with basic transmission service.
    Some commenters believe that the Commission should allow utilities 
to file transmission tariffs that bundle all necessary transmission and 
ancillary services, at least as an interim measure.\392\
---------------------------------------------------------------------------

    \392\ E.g., UT Com, Washington and Oregon Energy Offices, WA 
Com.
---------------------------------------------------------------------------

    On the other hand, other commenters believe that a greater level of 
unbundling of transmission and ancillary services is necessary to 
facilitate the development of competitive markets and to ensure that 
transmission customers are able to purchase only the services they 
require.\393\ Dayton P&L believes that all ancillary services should be 
offered as discrete services with separate prices. Texas Utilities 
asserts that generation-related ancillary services should be unbundled 
and separately priced.
---------------------------------------------------------------------------

    \393\ E.g., Direct Service Industries, Mt. Hope Hydro.
---------------------------------------------------------------------------

Commission Conclusion
    Although commenters raise valid concerns, they do not provide a 
compelling reason to require that our six ancillary services be bundled 
with basic transmission service. We have, however, changed the proposal 
in the NOPR to clarify that reactive supply and voltage support from 
transmission resources is part of basic transmission service.
    Unbundling ancillary services will promote competition and 
efficiency in their supply. Because most generation-based ancillary 
services potentially can be provided by many of the generators 
connected to the transmission system, some customers may be able to 
provide or procure such services more economically than the 
transmission provider can. Once they are unbundled, a more competitive 
market may emerge to supply such services.
    Also, unbundling makes possible a more equitable distribution of 
costs. Because customers that take similar amounts of transmission 
service may require different amounts of some ancillary services, 
bundling these services with basic transmission service would result in 
some customers having to take and pay for more or less of an ancillary 
service than they use. For these reasons, the Commission concludes that 
the six required ancillary services should not be bundled with basic 
transmission service.
    With respect to the specific question of whether Reactive Supply 
and Voltage Control from Generation Sources should be bundled with 
basic transmission service, we believe that this service should remain 
unbundled because, as explained above, transmission customers have some 
ability to effect how much of this service they need and a third party 
may be able to supply some portion of a customer's reactive power 
requirements.
b. Services That May Be Offered and Sold as a Package
    The NOPR indicated that ancillary services must be offered 
separately from one another but did not indicate if the

[[Page 21589]]

transmission provider may also offer a package of ancillary services.
Comments
    Several commenters support giving customers the option either to 
purchase ancillary services as separate and distinct services or to 
purchase a package of services from the transmission provider.<SUP>394 
Others, such as Tallahassee, recommend that utilities be prohibited 
from bundling the purchase of one service with another so that a 
transmission customer cannot rely on the transmission provider for just 
one or a few of the ancillary services.
---------------------------------------------------------------------------

    \394\ E.g., Direct Service Industries, Mt. Hope Hydro, ELCON, PA 
Com.
---------------------------------------------------------------------------

    EEI and ELCON argue that the Commission should permit customers the 
option to request that transmission providers offer packages of 
selected ancillary services.<SUP>395 They and other commenters express 
a concern that efficiencies can be lost under a policy that precludes 
combining ancillary services.
---------------------------------------------------------------------------

    \395\ EEI Initial Comments at V-4; ELCON Initial Comments at 21.
---------------------------------------------------------------------------

Commission Conclusion
    We conclude that a transmission provider must offer and price the 
individual ancillary services separately. It may not tie the purchase 
of one to the purchase of another.
    However, we will allow a transmission provider to assemble packages 
of ancillary services (not bundled with basic transmission service) 
that can be offered at rates that are less than the total of individual 
charges for the services if purchased separately. It may also offer 
rate discounts on any ancillary service. If a rate discount is offered 
to the transmission owner itself or to an affiliate of the transmission 
owner, the same discount must be offered to non-affiliates, as well. In 
addition, discounts offered to non-affiliates must be on a basis that 
is not unduly discriminatory. All discounts must be posted on the 
transmission provider's OASIS.
4. Reassignment of Ancillary Services
    In the NOPR, the Commission noted that ancillary services may not 
be suitable for reassignment and requested comments on this issue.
Comments
    Commenters express divided views on the reassignment issue. Some 
IOU commenters believe that, subject to technical limitations, 
ancillary services could be reassigned.<SUP>396 Other commenters, 
including many IOUs, oppose reassignment because they believe it is 
impractical.<SUP>397 In particular, PacifiCorp claims that the 
customer-specific nature of generation-related ancillary services 
prevents such services from being reassigned.
---------------------------------------------------------------------------

    \396\ E.g., WP&L, NYSEG.
    \397\ E.g., Consumers, PacifiCorp, Carolina P&L, PSNM, Salt 
River, PA Com, TDU Systems.
---------------------------------------------------------------------------

    TDU Systems argue that transmission customers that must pay for 
ancillary services they do not need should be able to resell them to 
someone else.<SUP>398 Mt. Hope Hydro claims that, if a bulk power 
transaction and the associated transmission service can be reassigned, 
it is reasonable that the ancillary services used to support the 
transaction also should be reassigned, particularly if the same 
facilities and contract path are used.<SUP>399
---------------------------------------------------------------------------

    \398\ TDU Systems Initial Comments at 87.
    \399\ Mt. Hope Hydro Initial Comments at 17.
---------------------------------------------------------------------------

Commission Conclusion
    We conclude that transmission customers will be allowed to reassign 
ancillary services along with the reassignment of basic transmission 
service. The Commission believes that a policy of transmission capacity 
reassignment may not be possible unless the ancillary services used to 
support the transmission are also reassignable.
5. Pricing of Ancillary Services
    In the NOPR, we asked for comments on ancillary service pricing and 
proposed specific ancillary services prices in the Stage One 
implementation rates. Many commenters commented on the Stage One rates. 
There is no Stage One in the Final Rule.
Comments
    Many commenters state that ancillary services are difficult to 
price. They suggest diverse pricing approaches. IN Com notes that, 
because utilities and regulatory commissions have no experience with 
pricing unbundled ancillary services, the process needs to evolve but 
the goal should be to encourage market pricing in competitive markets. 
Air Liquide believes the best pricing policy should be negotiated 
bilateral agreements, provided market power is mitigated.
    Other commenters express concern about how pricing proposed in the 
NOPR would affect the development and operation of competitive 
ancillary services markets. Industrial Energy Applications notes that 
low price caps on generation-related services, such as supplying 
losses, imbalance energy, operating reserve and backup power, which can 
be provided from many sources, inhibit competitive market development. 
There is little incentive for other providers to invest in facilities 
to provide these services. Dayton P&L and others contend that the 
Commission should not require transmission providers to provide 
generation-based ancillary services at cost-based rates and then allow 
third parties to resell such services at market-based rates. PacifiCorp 
expresses concern that the NOPR's pricing proposal would be overly 
restrictive in the emerging competitive market for generation-related 
ancillary services.
    Many commenters argue that cost-based price caps are appropriate 
for ancillary services if there are no alternative suppliers or until 
competitive markets develop.<SUP>400 CAMU suggests that the 
comparability standard is not met if market rates exceed the costs of 
providing ancillary services. Allegheny, Ohio Edison and Atlantic City 
support cost-based pricing for Reactive Power/Voltage Control. Ohio 
Edison recommends cost-based pricing for frequency regulation, and 
Atlantic City recommends it for scheduling and dispatch.
---------------------------------------------------------------------------

    \400\ E.g., Utilities For Improved Transition, Idaho, CINergy, 
Direct Service Industries, Mt. Hope Hydro, ABATE, TDU Systems, 
Missouri-Kansas Industrials, Washington and Oregon Energy Offices, 
IN Com.
---------------------------------------------------------------------------

    Several commenters suggest that the Commission require cost-based 
rates for ancillary services where no source other than the 
transmission provider exists and market-based rates for generation-
related ancillary services if competition exists.<SUP>401 Washington 
and Oregon Energy Offices recommend that, before permitting market-
based rates, at least two other non-affiliated parties should be able 
to offer a nearly identical ancillary service and that the Commission 
should use the same standards for allowing market-based rates for 
ancillary services that it has used for wholesale power sales. Mt. Hope 
Hydro argues that vertically integrated utilities should be permitted 
to charge cost-based rates that are limited to no more than the market 
price for ancillary services. It also contends that companies whose 
generation facilities are not supported by captive retail or 
transmission customers should be authorized to sell at market-based 
prices.
---------------------------------------------------------------------------

    \401\ E.g., PJM, Texas Utilities, Entergy, Carolina P&L.
---------------------------------------------------------------------------

    The vast majority of commenters from all interest groups who 
address market-based pricing for ancillary services agree that market-
based pricing is appropriate for ancillary services where competitive 
market conditions exist. However, commenters disagree over whether a

[[Page 21590]]

competitive market for ancillary services currently exists.
    In determining the extent of competition, many commenters 
distinguish between ancillary services that are (1) generation-related 
and (2) transmission-related. Commenters disagree over whether the 
Commission can declare generation-related ancillary services to be 
competitive on a generic basis. Many commenters contend that 
transmission-related ancillary services are not available in a 
competitive market; consequently, they agree that prices for such 
services should be cost-based.
Commission Conclusion
    We will consider ancillary services rate proposals on a case-by-
case basis.
    In response to comments,<SUP>402 we offer here some general 
guidance on ancillary services pricing principles.
---------------------------------------------------------------------------

    \402\ Many commenters were particularly concerned that rates for 
energy losses, a NOPR ancillary service, should be market-based. We 
need not address this concern in this Rule, however, because we will 
not require Real Power Losses to be offered as an ancillary service.
---------------------------------------------------------------------------

    (1) Ancillary service rates should be unbundled from the 
transmission provider's rates for basic transmission service, even 
though such services are a necessary adjunct to basic transmission 
service.
    (2) The fact that we have authorized a utility to sell wholesale 
power at market-based rates does not mean we have authorized the 
utility to sell ancillary services at market-based rates.
    (3) In the absence of a demonstration that the seller does not have 
market power in such services, rates for ancillary services should be 
cost-based and established as price caps, from which transmission 
providers may offer a discount to reflect cost variations or to match 
rates available from any third party. If a rate discount is offered to 
the transmission owner itself or to an affiliate of the transmission 
owner, the same discounted rate must be offered to non-affiliates, as 
well. In addition, discounts offered to non-affiliates must be on a 
basis that is not unduly discriminatory. All discounts must be posted 
on the transmission provider's OASIS.
    (4) The amount of each ancillary service that the customer must 
purchase, self-supply, or otherwise procure must be readily determined 
from the transmission provider's tariff and comparable to the 
obligations to which the transmission provider itself is subject. The 
provider must take ancillary services for its own wholesale 
transmission under its own tariff.
    (5) The location and characteristics of a customer's loads and 
generation resources may affect significantly the level of ancillary 
service costs incurred by the transmission provider. Ancillary service 
rates and billing units should reflect these customer characteristics 
to the extent practicable.
6. Accounting for Ancillary Services
Comments
    Some commenters suggest that there may be a need for revising the 
Uniform System of Accounts to track better the costs of providing 
discrete ancillary services. Other commenters believe that ancillary 
services are transmission-type services and suggested that the costs of 
generation-provided ancillary services be refunctionalized from power 
production expense to transmission expense.
    Oak Ridge asserts that a primary goal of those interested in 
restructuring the electricity industry should be to identify clearly 
the different functions that are today buried within the vertically 
integrated utility and bundled into one price. Oak Ridge, however, 
indicates that achieving this ideal of identifying unbundled services 
at appropriate prices will be difficult because of utility accounting 
practices.
    EEI asserts that since the current Uniform System of Accounts was 
designed to track costs incurred to provide bundled wholesale service, 
it does not track the discrete costs incurred to provide ancillary 
services. Therefore, according to EEI, a major update is needed to 
support the pricing of discrete ancillary services.
    ConEd states that ancillary services are integral and essential 
elements of providing transmission services. It notes that, 
historically, due to the vertical integration of utilities, those 
services have been bundled with the other services provided and the 
costs associated with providing ancillary services have not been 
specifically defined. ConEd claims that to a large degree, this is due 
to the fact that utility accounting mechanisms were not established 
with the intention of identifying the costs for ancillary services.
    UI asserts that if transmission customers are to be charged for 
certain ancillary services, it may be necessary to refunctionalize 
certain specific costs items from generation to transmission. UI points 
out that some of the reactive power to support system voltages and to 
provide transmission services, for example, is supplied from the 
variable reactive output of the generators. It states that these costs, 
to the extent they can be identified with the provision of transmission 
service, should be refunctionalized to the transmission account. 
However, UI states it may not be possible to develop a unit cost for 
specific transactions. Thus, UI states it may be more appropriate to 
roll these costs into the embedded transmission rate and allocate them 
among the various users of the transmission system.
Commission Conclusion
    To ensure comparable transmission access a Transmission Provider is 
obligated to offer or arrange to provide certain ancillary services to 
the Transmission Customer. Also, the Transmission Provider may offer to 
provide other ancillary services to the Transmission Customer. A 
Transmission Customer is obligated to purchase certain ancillary 
services from the Transmission Provider.
    Generation resources provide certain ancillary services, while 
transmission resources provide other ancillary services. Consequently, 
the costs of providing certain ancillary services are recorded in the 
utility's power production expense accounts, while others are recorded 
in the utility's transmission expense accounts.
    Currently, the Uniform System of Accounts requires that costs 
incurred in providing ancillary services be recorded as power 
production or transmission expense depending upon which resource the 
utility uses to supply the service. At this time, we are not convinced 
that the amounts involved or the difficulty associated with measuring 
the cost of ancillary services warrants a departure from our present 
accounting requirements. We will specify, however, that revenues a 
Transmission Provider receives from providing ancillary services must 
be recorded by type of service in Account 447, Sales for Resale, or 
Account 456, Other Electric Revenues, as appropriate.
E. Real-Time Information Networks
    In the Open Access NOPR, the Commission determined that in order to 
remedy undue discrimination, a utility must functionally unbundle its 
wholesale services, and that among the things required by functional 
unbundling is that the utility, when buying or selling power, rely upon 
the same electronic network that its transmission customers rely upon 
to obtain transmission information. Accordingly, the Commission 
accompanied its issuance of the Open Access NOPR with issuance of a 
notice of technical conference that initiated a proceeding in Docket 
No. RM95-9-000

[[Page 21591]]

to consider whether Real-Time Information Networks (RINS) or some other 
option would be the best means to ensure that potential customers of 
transmission services have access to the information necessary to 
obtain open access transmission service on a non-discriminatory 
basis.<SUP>403
---------------------------------------------------------------------------

    \403\ See Real-Time Information Networks, Notice of Technical 
Conference and Request for Comments, 60 FR 17726 (April 7, 1995).
---------------------------------------------------------------------------

    The Commission affirms its conclusion that in order to remedy undue 
discrimination in the provision of transmission services it is 
necessary to have non-discriminatory access to transmission 
information, and that an electronic information system and standards of 
conduct are necessary to meet this objective. Therefore, we issue, in 
conjunction with this Final Rule, a final rule adding a new Part 37 
that requires the creation of a basic OASIS and standards of 
conduct.<SUP>404
---------------------------------------------------------------------------

    \404\ In Phase II, we will continue to develop the requirements 
for fully functional OASIS. We expect to issue a final rule on Phase 
II OASIS requirements sometime in 1997.
---------------------------------------------------------------------------

    The Phase I OASIS rules require each public utility (or its agent), 
as defined in section 201(e) of the Federal Power Act, 16 U.S.C. 
824(e), that owns, controls, or operates facilities used for the 
transmission of electric energy in interstate commerce to develop and/
or participate in an OASIS. The Phase I OASIS rules describe what 
information must be provided on the OASIS during Phase I and how OASIS 
must be implemented.
    In addition, the new Part 37 contains a code of conduct applicable 
to all transmission providing public utilities. The code of conduct is 
designed to ensure that preferential access to information about 
wholesale transmission prices and availability is not available to 
employees of the public utility engaged in wholesale marketing 
functions or to employees of certain of the public utility's 
affiliates.

F. Coordination Arrangements: Power Pools, Public Utility Holding 
Companies, Bilateral Coordination Arrangements, and Independent System 
Operators

Comments
Timing of Reformation
    Many marketers, IPPs, and other nonmembers of pools request that 
the Commission immediately apply unbundling and transmission tariff 
requirements to all new transactions under existing pooling agreements. 
APPA states that the Commission should not deal with power pools as a 
``follow-on activity'' because treatment of pools is an integral step 
in achieving transmission comparability. AEC contends that until pools 
publish open access tariffs, the Commission should permit applications 
for section 211 transmission orders from one or more applicants 
directed to multiple respondents.
    Existing pools generally urge the Commission to allow time for the 
pools to propose alternative structures or agreements which would meet 
the objectives of the final rule. EEI states that the rule may create 
problems for power pools that will not be examined or understood by the 
Commission and the public until the Commission's pooling inquiry is 
completed; it requests that the pooling inquiry be completed before a 
final rule is issued. Duke recommends that implementation of open 
access transmission services by power pools be addressed in a separate 
proceeding because implementation of open access for power pools raises 
complex issues.
    EGA, among others, argues that new transactions under existing 
pooling agreements should not be grandfathered, but rather should be 
required to meet the functional unbundling requirements of the final 
rule. Some pool members argue that pool transactions are largely not 
wholesale transactions. For example, PECO (a member of PJM) requests 
the Commission to clarify that the delivery of pooled generation to 
pool members' native load is not a ``wholesale purchase'' of power and 
thus would not require taking transmission service under one's own open 
access transmission tariff. Another member of PJM, BG&E, interprets the 
proposed rule to require all PJM economy trades to be firm point-to-
point services; it claims that such a requirement ``jeopardizes the 
continued viability of the pool.''
System-Wide Tariffs
    Virtually all commenters on power pool issues state that the tariff 
requirements should not be applied directly to individual utilities who 
are members of ``tight'' power pools. ELCON, CCEM, and others argue 
that the pro forma tariff requirement should be applied directly to 
``tight'' or ``single system'' power pools to avoid discriminatory 
``pancaking'' of transmission rates. However, Duke argues that where 
there are both multiple owners and operators, as in ``loose'' pools, it 
is appropriate to have individual tariffs unless the pool members agree 
otherwise. DOE recommends a power pool file a single pool-wide tariff 
to offset problems associated with joint ownership or control of 
transmission. CT DPUC recommends that the Commission provide guidance 
for transmission access and pricing (so as to avoid needless disruption 
of present methods).
Flexible Treatment
    Most commenters on power pools support recognizing regional 
differences among power pools and urge flexibility. PSE&G (a member of 
PJM) states that open access tariffs must be specially crafted to deal 
with power pool members. NYPP and PJM state that they are considering 
innovations and urge that their efforts not be stifled by any final 
rule. CSW proposes a region-wide pricing model based on power flows. 
NPPD, a member of the Mid-Continent Area Power Pool (MAPP), says MAPP 
is considering adopting the megawatt-mile approach to transmission 
pricing. SoCal Edison states that California utilities are developing a 
market-based power pool and that it is crucial for the final rule to be 
flexible to permit innovations throughout the country.
    ELCON and power marketers, however, argue for uniformity and point 
out the difficulties of moving power from system to system where each 
system has varying standards or ``pool rules.'' These commenters 
support uniform application of the terms and conditions in the pro 
forma tariffs to create a national standard.
    NEPOOL emphasizes that since pools remain voluntary, the imposition 
of rules that are not acceptable to pool members simply increases the 
likelihood that members will withdraw and pools will disintegrate. For 
this reason, NEPOOL states that solutions to enhance competition 
(within a tight pool setting) are best identified through the consensus 
of pool members, which requires both time and flexibility on the part 
of the Commission.
    DE, DC, NJ and MD Coms emphasizes its concern that a one-size-fits-
all open-access policy, while perhaps benefiting subsets of individual 
suppliers and purchasers, may not be the best solution for the millions 
of retail customers who currently rely on power pools.<SUP>405 It wants 
the Commission to be aware that the individual commissions have begun a 
formal dialog among each other and with the PJM utilities to discuss 
possible regional solutions to transitional competitive issues.
---------------------------------------------------------------------------

    \405\ E.g., DE Com, DC Com, NJ Com, MD Com.
---------------------------------------------------------------------------

Open Membership
    NIEP and CCEM argue that the competitive playing field cannot be 
level unless nonmembers receive certain

[[Page 21592]]

power pool services on terms comparable to those for pool members. 
Members of pools state that ``return in kind'' transactions are 
efficient, but that such transactions are not appropriate for those 
entities that are not similarly situated to vertically integrated 
utilities.
    EEI maintains that those seeking the benefits of pool membership 
must accept the burdens imposed on existing pool members (otherwise, 
they would have an advantage, not comparability). EEI believes that new 
pool participants can negotiate and ``buy into'' the pool resources. 
Many commenters claim that unbundling certain power pool services to 
accommodate open access will solve the problem.
    MidAmerican states that if the Commission grants nonmembers access 
to pool transmission service, the Commission should allow a period of 
at least four years for pools to restructure and refile rate schedules 
to avoid the inequitable results which the Commission's requirements 
will impose on pool members.
    MidAmerican contends that the Commission should authorize pool 
members to unilaterally withdraw from their pools if any restructuring 
or revision of rate schedules is unacceptable to the member.
Holding Companies
    Allegheny, Southern, and other holding companies argue that 
coordination agreements among subsidiaries of a utility holding company 
system do not constitute a power pool and should not be subject to any 
obligations the Commission may place on power pools.
Bilateral Coordination Agreements
    Ohio Edison requests clarification that the Commission is not 
requiring new wholesale coordination transactions to be under the open 
access tariffs; they may be continued under existing coordination 
agreements. It stresses the importance of such agreements in making 
economy and emergency transactions.
    A number of commenters agree that existing coordination contracts 
should not be abrogated or modified, and that transactions under these 
existing contracts should not be governed by the provisions of the pro 
forma tariffs.<SUP>406 These commenters generally argue that existing 
coordination agreements should not be abrogated or amended by the final 
rule because: (1) They were not negotiated in the environment 
envisioned by the NOPR; (2) coordination sales are beneficial to 
consumers and ratepayers (and thus it would not be in the public 
interest to curtail them); and (3) the termination of coordination 
agreements, which in some cases have been in place for years and are 
tailored to parties' peculiar circumstances, could cause severe 
hardships in certain regions (especially with regard to scheduling and 
curtailment).
---------------------------------------------------------------------------

    \406\ E.g., Central Louisiana, Dayton P&L, LPPC, MEAG, Missouri 
Basin Group, Montana-Dakota Utilities, Nebraska Public Power 
District, Ohio Edison, PSNM.
---------------------------------------------------------------------------

    PSNM contends that such agreements are the result of mutually 
beneficial bargaining. LPPC and MEAG argue that current contracts 
negotiated among parties provide cost savings to consumers, which may 
be foregone if existing contracts are modified. Central Louisiana 
suggests that the pro forma tariff provisions should be flexible enough 
to achieve comparability if applied to both existing and new 
coordination agreements.
    Some commenters argue that there may be cases where it is 
inappropriate to modify existing coordination agreements to satisfy the 
requirements of the rule. They assert that coordination agreements 
providing for emergency transactions,<SUP>407 reliability,<SUP>408 and 
resource efficiency gains <SUP>409 need special attention. However, 
Soyland believes that existing agreements need to be reviewed if there 
is substantial increase in wholesale power market transactions, at the 
customer's option. TDU Systems argues that coordination contracts 
supporting system reliability should be honored and given scheduling 
and curtailment preference. TDU Systems contends that any amendments 
should be at the parties' discretion rather than by Commission mandate.
---------------------------------------------------------------------------

    \407\ E.g., Arizona, Ohio Edison.
    \408\ E.g., Soyland, NRECA.
    \409\ E.g., APPA.
---------------------------------------------------------------------------

    Several commenters suggest that the proposed rule is unclear about 
whether only existing transactions under agreements already approved by 
the Commission will be exempt from functional unbundling, or whether 
the proposed rule also would exempt (or grandfather) new transactions 
entered into pursuant to existing approved contracts.<SUP>410 Other 
commenters recommend that the Commission clarify that its policy on 
unbundling applies to all new transactions, whether pursuant to new or 
existing agreements.<SUP>411 ConEd and KCPL request clarification that 
purchases made to satisfy retail service are not subject to the 
requirements of the pro forma tariffs.
---------------------------------------------------------------------------

    \410\ E.g., APPA, CCEM, EGA.
    \411\ E.g., APPA, CCEM, LG&E, EGA.
---------------------------------------------------------------------------

    CCEM argues that all coordination transactions, including new 
transactions under existing agreements, should be unbundled to ensure 
that transmission providers are implementing the posted transmission 
rate. CINergy contends that the comparability standard should be 
applied to existing coordination agreements, including buy-resell 
agreements, to mitigate any unfair bulk power market advantages. 
Functional unbundling would ensure that a utility includes an EBB-
posted transmission rate in the transaction charge. CINergy and Power 
Marketing Association recommend that the Commission use its authority 
under section 206 to require all utilities to file amendments to their 
existing coordination agreements providing for transmission service to 
be taken pursuant to the parties' open access transmission tariffs. 
Power Marketing Association further recommends that the Commission 
establish expedited procedures to address the situation arising from 
conflicting pro forma tariffs and existing coordination provisions.
    Tallahassee also believes that the comparability standard should be 
applied to existing coordination agreements, but Tallahassee recommends 
that the Commission establish a transition period to allow for 
renegotiation among parties rather than imposing modifications to 
existing agreements. Renegotiation would provide an opportunity to 
retain previously bargained-for benefits. Detroit Edison also contends 
that many of the existing coordination agreements do not provide for 
the services required under the pro forma tariffs. Like Tallahassee, 
Detroit Edison recommends that the Commission allow sufficient time for 
parties to renegotiate existing agreements. CINergy suggests a three-
year transition period.
Coordination Pricing Practices
    EEI and PJM disagree with the Commission's assertion that current 
coordination pricing is no longer just and reasonable in the absence of 
an open access tariff. Ohio Edison and PA Com question the basis of the 
Commission's preliminary conclusion that current coordination pricing 
is no longer justified in the absence of a seller's tariff offer of 
non-discriminatory open access transmission services. PA Com asserts 
that the Commission's underlying assumption of general lack of 
transmission access by wholesale customers has not been established as 
fact in the proposed rule.

[[Page 21593]]

    MN DPS supports current coordination pricing methods provided that 
utilities have executed open-access tariffs. Missouri Basin Group 
argues that, if increased market competition materializes through open 
access, utilities will decreasingly rely on current coordination 
pricing if it no longer produces the most beneficial outcome. Missouri 
Basin Group recommends the Commission simply allow utilities to choose 
a pricing method even if a utility opts for a less beneficial outcome. 
Nebraska Public Power District also urges the Commission to avoid 
mandating coordination pricing methods. Nebraska Public Power District 
is concerned that this may impede establishing RTGs where such pricing 
is by mutual agreement and subject to ADR procedures.
    Several commenters agree that current coordination pricing may no 
longer be appropriate in an open access regime.<SUP>412 FL Com believes 
that current coordination pricing should be replaced by market-based 
rates if open access transmission service is imposed by the Commission.
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    \412\ E.g., Arizona, CINergy, Consumers Power, EEI, PJM.
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Commission Conclusion
    The term ``coordination'' is applied to a wide variety of wholesale 
power sales agreements within the industry, including interchange, 
interconnection, pooling, and other agreements. Broadly speaking, any 
non-requirements power sales agreement can be considered to be a 
coordination agreement.<SUP>413
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    \413\ For example, a 30-year contract to supply 50 MW of power 
can be considered to be a coordination arrangement because it is not 
a contract to meet all of the buyer's power requirements.
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    The Final Rule's general requirement for non-discriminatory 
transmission access and pricing by public utilities, and its specific 
requirement that public utilities unbundle their transmission rates and 
take transmission service under their own tariffs, apply to all public 
utilities' wholesale sales and purchases of electric energy, including 
coordination transactions. The Commission has determined that certain 
existing wholesale coordination arrangements and agreements must be 
modified to ensure that necessary transmission services for such 
arrangements and agreements are taken under open access transmission 
tariffs and thus that such arrangements and agreements are not unduly 
discriminatory. Below we discuss how and when various types of 
coordination agreements will need to be modified, and when public 
utility parties to coordination agreements must begin to trade power 
under those agreements using transmission service obtained under the 
same open access transmission tariff available to non-parties.
    Coordination arrangements, and the agreements governing them, vary 
widely. They range from relatively simple bilateral arrangements to 
complex tight power pools. Our discussion addresses four broad 
categories of arrangements and accompanying agreements: ``tight'' power 
pools, ``loose'' power pools, public utility holding company 
arrangements, and bilateral coordination arrangements. For purposes of 
implementing the non-discriminatory, open access requirements of the 
Final Rule, we are dividing bilateral coordination agreements into two 
general categories: bilateral economy energy agreements and other 
bilateral coordination agreements. Economy energy agreements typically 
provide for short-term economy trading ``if, as, and when available'' 
and are generally driven by the buyer and seller's generation costs. 
They do not require either the seller or the buyer to engage in a 
particular transaction. Other coordination agreements are typically 
longer term or open-ended. Some may involve joint ownership or joint 
planning of generation.<SUP>414 Others may provide joint operation of 
facilities so that the parties can coordinate their maintenance 
schedules or provide one another with emergency service. These longer-
term coordination agreements are distinguished from short-term economy 
trading agreements in that the parties have undertaken a contractual 
obligation to operate their facilities so as to support one another 
under the conditions specified in the arrangements.
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    \414\ Agreements dealing with joint ownership or operation of 
transmission facilities are discussed at Section IV.C.3.
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    As noted in the NOPR, power pools, in contrast to most bilateral 
arrangements, present complex issues that may require special 
implementation requirements.<SUP>415 This is because these arrangements 
may involve agreements containing an intricate set of rights, 
obligations, and considerations among the members of a pool. We provide 
for implementation requirements herein that vary depending upon the 
type of ``pooling'' arrangement involved.
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    \415\ The Commission did not define what it meant by ``power 
pools'' in the NOPR discussion. We use the term power pool in a very 
broad context here and have generally characterized three broad 
types of arrangements that represent some form of pooling: ``tight 
pools'', ``loose'' pools and other multilateral coordination 
arrangements, and holding companies. Even between the categories of 
tight and loose pools, however, there is no bright dividing line.
---------------------------------------------------------------------------

    The Commission has concluded that in order to adequately remedy the 
undue discrimination in transmission access and pricing by public 
utilities that are members of power pools or other coordination 
arrangements, such public utilities must remove preferential 
transmission access and pricing provisions from agreements governing 
their transactions. The filing of open access tariffs by the public 
utility members of a power pool is not enough to cure undue 
discrimination in transmission if those public utilities can continue 
to trade with a selective group within a power pool that 
discriminatorily excludes others from becoming a member and that 
provides preferential intra-pool transmission rights and rates. The 
same holds true of certain bilateral arrangements that allow 
preferential transmission pricing or access. These arrangements and 
agreements need to be changed. We expect such arrangements and 
agreements to be modified by the dates indicated in this Rule. However, 
if necessary, we will institute section 206 proceedings against public 
utilities that do not make such filings.
    The Commission's technical conferences on power pools, ISOs, and 
pro forma tariffs made clear to us the need to articulate guidance in 
this Rule on the restructuring or modification of unduly discriminatory 
coordination arrangements--particularly tight power pools.\416\ They 
also made clear that members of tight power pools, in particular, need 
time to make the necessary modifications to these arrangements. We 
recognize that members of some power pools are already in the process 
of formulating voluntary modifications to pooling agreements to be 
filed with the Commission (e.g., PJM, NYPP, NEPOOL). Therefore, we will 
provide adequate time for these filings as well as guidance to changes 
that need to be made.
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    \416\ A technical conference on pro forma tariffs was held on 
October 27, 1995. A technical conference on power pools was held on 
December 5 and 6, 1995 and a follow-up technical conference on ISOs 
and power pools was held on January 24, 1996.
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    In addition, although we do not at this time find it necessary to 
require power pools to form an independent system operator in order to 
remedy undue discrimination, we believe ISOs may prove to be an 
effective means for

[[Page 21594]]

accomplishing comparable access.\417\ We recognize that several 
utilities are exploring the possibility of forming ISOs. For example, 
discussions are ongoing in California, PJM, NYPP, and the Midwest. 
Therefore, because of the industry's interest (which we share) in the 
concept of an ISO and the potential for an ISO to provide non-
discriminatory transmission services to all market participants, we 
will provide guidance in this section on minimum ISO characteristics.
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    \417\ The DOJ and DOE suggested that the Commission examine 
operational unbundling as a way of enforcing comparability in 
transmission service. DOJ and DOE believe that functional unbundling 
may not be adequate to ensure comparability and so have recommended 
that some form of operational unbundling be required. While we 
believe that requiring this is premature, we note that an ISO is one 
way to achieve operational unbundling and we encourage the voluntary 
development of ISOs.
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1. Tight Power Pools
    For purposes of this Rule, the tight power pools are: New York 
Power Pool (NYPP), New England Power Pool (NEPOOL), Pennsylvania-New 
Jersey-Maryland Interconnection (PJM), and the Michigan Electric 
Coordinated Systems (MECS).
    Public utilities who are members of a tight pool must file, within 
60 days of publication of the Final Rule in the Federal Register, 
either: (1) An individual Final Rule pro forma tariff; or (2) a joint 
pool-wide Final Rule pro forma tariff. They are not required to take 
service for pool transactions under the tariff that is filed within 60 
days. However, they will be required to file a joint pool-wide Final 
Rule pro forma tariff no later than December 31, 1996, and must begin 
to take service under that tariff for all pool transactions no later 
than December 31, 1996. The purpose of this extension is to allow 
sufficient time for tight pools to amend their pooling agreements and 
to restructure their operations to conform to the requirements of the 
Final Rule. We also believe that the additional time is necessary to 
preserve efficient trading arrangements during the restructuring 
period.
    The Commission therefore will require that the public utility 
members of tight pools file reformed power pooling agreements no later 
than December 31, 1996. The reformed power pool agreements should 
establish open, non-discriminatory membership provisions (including 
establishment of an ISO, if that is a pool's preferred method of 
remedying undue discrimination) and modify any provisions that are 
unduly discriminatory or preferential. The membership provision must 
allow any bulk power market participant to join, regardless of the type 
of entity, affiliation, or geographic location.
    If the reformed agreement allows members to make transmission 
commitments or contributions in exchange for the discounted 
transmission rates, the pool may file a transmission tariff that 
contains an access fee for non-transmission owning members or non-
members, justified solely on the basis of transmission-related costs. 
Alternatively, the pool could make available a transmission rate that 
is structured the same as the discounted rate (e.g., non-pancaked) but 
with a higher rate that is justified on the basis of transmission-
related costs borne (or contributed) by the pool members. However, any 
such access fee or higher rate must be justified solely on the basis of 
transmission costs and cannot be tied to the costs of any other 
agreement among the pool members (e.g., generation reserve sharing).
2. Loose Pools
    For purposes of the Final Rule, a loose pool is any multi-lateral 
(more than 2 public utilities) arrangement, many of which contain 
discounted and/or special transmission arrangements. Examples are MAPP, 
Inland Power Pool, and the MOKAN pool. Other entities may qualify to be 
treated as a loose pool if they can show that they meet the definition 
above.
    Public utilities within a loose pool must file, within 60 days of 
publication of the Final Rule in the Federal Register, either: (1) An 
individual Final Rule pro forma tariff; or (2) a pool-wide Final Rule 
pro forma tariff. They are not required to take service for pool 
transactions under the tariff that is filed within 60 days. However, 
they will be required to file a joint pool-wide Final Rule pro forma 
tariff no later than December 31, 1996, and must begin to take service 
under that tariff for all pool transactions no later than December 31, 
1996. The purpose of this extension is to allow sufficient time for 
loose pools to amend their agreements and to restructure their 
operations to conform to the requirements of the Final Rule. We also 
believe that the additional time is necessary to preserve efficient 
trading arrangements during the restructuring period.
    The Commission therefore will require that the public utility 
members of loose pools file reformed power pooling agreements no later 
than December 31, 1996. They also must file a joint pool-wide tariff no 
later than December 31, 1996. The reformed power pool agreements should 
establish open, non-discriminatory membership provisions and modify any 
provisions that are unduly discriminatory or preferential. The 
membership provision must allow any bulk power market participant to 
join, regardless of the type of entity, affiliation, or geographic 
location.
    The Commission recognizes that loose pools typically do not operate 
as a single control area and that operational unbundling, perhaps 
through an ISO, might not be readily attainable at this time. 
Nonetheless, we encourage the members of loose pools to explore the 
advantages of the ISO concept.
    If the reformed agreement allows members to make transmission 
commitments or contributions in exchange for discounted transmission 
rates, the pool may file a transmission tariff that contains an access 
fee for non-transmission owning members or non-members, justified 
solely on the basis of transmission-related costs. Alternatively, the 
pool could make available a transmission rate that is structured the 
same as the discounted rate (e.g., non-pancaked) but with a higher rate 
that is justified on the basis of transmission-related costs borne (or 
contributed) by the pool members. However, any such access fee or 
higher rate must be justified solely on the basis of transmission costs 
and cannot be tied to the costs of any other agreement among the pool 
members (e.g., generation reserve sharing).
3. Public Utility Holding Companies
    Public utility members of registered and exempt holding companies 
that are also members of tight or loose pools are subject to the tight 
and loose pool requirements set forth above. The remaining holding 
company public utility members, with the exception of the Central and 
South West (CSW) System, are required to file a single system-wide 
Final Rule pro forma tariff permitting transmission service across the 
entire holding company system at a single price within 60 days of 
publication of the Final Rule in the Federal Register (service 
companies may, of course, file on behalf of their public utility 
affiliates). As discussed below, CSW presents special circumstances.
    The CSW System is comprised of four operating public utilities. Two 
of those utilities, Southwestern Electric Power Company (SWEPCO) and 
Public Service Company of Oklahoma (PSO) operate in the Southwest Power 
Pool (SPP). The other two, West Texas Utilities Company (West Texas) 
and Central Power and Light Company (CP&L), operate in the Electric 
Reliability

[[Page 21595]]

Council of Texas (ERCOT). SWEPCO and PSO exchange power with West Texas 
and CP&L through two high voltage, direct current interconnections (the 
North and East Interconnections).<SUP>418
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    \418\ The North and East Interconnections were ordered by the 
Commission pursuant to sections 210, 211 and 212 of the Federal 
Power Act. See Central Power and Light Company, et al., 17 FERC 
para. 61,078 (1981), order on reh'g, 18 FERC para. 61,100 (1982); 40 
FERC para. 61,077 (1987).
---------------------------------------------------------------------------

    Pursuant to the Commission orders concerning the North and East 
Interconnections, CP&L, West Texas, SWEPCO, and PSO have on file what 
are referred to as the ``to or from and over tariffs.'' <SUP>419 Those 
tariffs apply only to transmission service that involves the delivery 
of power and energy to or from and over the North and East 
Interconnections.<SUP>420 The tariffs do not apply to the transmission 
of power for CSW subsidiaries other than the operating companies. The 
tariffs in many respects are different from the Final Rule pro forma 
tariff and do not provide comparable services. Moreover, the pricing 
provided in the ``to or from and over'' tariffs is different from the 
pricing set forth in the Texas Commission's final open access 
rule.<SUP>421
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    \419\ Houston Lighting and Power Company (HL&P) and Texas 
Utilities Electric Company (TU) also have on file ``to or from and 
over tariffs'' pursuant to the Commission orders.
    \420\ See, e.g., CP&L and West Texas Interpool Transmission 
Service Tariff, Sec. 4.1.
    \421\ Compare 21 TEX REG 1397, LEXIS, mimeo at 18 (adopting 
hybrid pricing scheme with 70% of transmission rate based on 
regional postage stamp method and 30% based on the vector-absolute 
megawatt-mile method) with Id. at Article III.
    We note that the Texas Commission concluded that the ERCOT 
portion of the costs of the North and East Interconnections ``should 
be included in the cost of service, when the owners of the 
(Interconnections) amend the FERC tariffs for the use of the 
(Interconnections) to provide equal access to other utilities. 21 
TEX REG, LEXIS, mimeo at 24.
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    Given these special circumstances, we believe it appropriate to 
give CSW the opportunity to propose a solution to achieving 
comparability for the CSW system. Accordingly, we direct the public 
utility subsidiaries of CSW to consult with the Texas, Arkansas, 
Oklahoma and Louisiana Commissions and to file not later than December 
31, 1996 a system tariff that will provide comparable service to all 
wholesale users on the CSW System,<SUP>422 regardless of whether they 
take transmission service wholly within ERCOT or the SPP, or take 
transmission service between the reliability councils over the North 
and East Interconnections.<SUP>423
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    \422\ It may be appropriate to have different rates for 
transmission service wholly within ERCOT or the SPP, and for service 
between the reliability councils. However, the same rates, terms, 
and conditions applicable for third parties should also be 
applicable to the CSW System's wholesale transmission requirements.
    \423\ We recognize that this action may require amendment to the 
Commission's orders under FPA sections 210, 211, and 212, ordering 
the North and East Interconnections. In this regard, it should be 
clearly understood that the Commission's action in requiring 
comparable service by the CSW System is not in any way intended to 
result in public utility status to any ERCOT participants that are 
not public utilities--e.g., HL&P and TU. See 16 U.S.C. 824(b)(2).
---------------------------------------------------------------------------

    The Commission will give public utilities that are members of 
holding companies an extension of the requirement to take service under 
the system tariff for wholesale trades between and among the public 
utility operating companies within the holding company system. This 
extension is until December 31, 1996--the same extension we are 
granting to power pools. At that point, the public utility operating 
companies will be required to take service under the Final Rule pro 
forma tariff for wholesale trades among themselves. In addition, it may 
be necessary for registered holding companies to reform their holding 
company equalization agreement to recognize the non-discriminatory 
terms and conditions of transmission service required under the Final 
Rule pro forma tariff.
4. Bilateral Coordination Arrangements
    Any bilateral wholesale coordination agreement executed after the 
effective date of this Rule will be subject to the functional 
unbundling and open access requirements set forth in this Rule. With 
regard to existing bilateral agreements, however, the diversity of the 
types of agreements currently on file presents special implementation 
problems. The Commission is particularly concerned with future economy 
energy transactions that may occur pursuant to existing umbrella-type 
coordination agreements. Accordingly, we shall require all bilateral 
economy energy coordination contracts executed before the effective 
date of this Rule to be modified to require unbundling of any economy 
energy transaction occurring after December 31, 1996. All non-economy 
energy bilateral coordination contracts executed before the effective 
date of this Rule will be permitted to continue in effect, but will be 
subject to complaints filed under section 206 of the FPA. Under those 
procedures, the rates, terms, and conditions of individual coordination 
contracts may be challenged as unduly discriminatory or otherwise 
unlawful.
    To compute the unbundled coordination compliance rate, the utility 
must subtract the corresponding transmission unit charge in its open 
access tariff from the existing coordination rate ceiling. For example, 
if a utility has a coordination rate ceiling for hourly service of 
incremental cost plus 15 mills/kWh and a transmission tariff rate for 
hourly service of 3 mills/kWh, it shall revise the coordination rate 
ceiling to incremental cost plus 12 mills/kWh. The Commission cautions 
that the compliance filing will be strictly limited to removing the 
current transmission tariff price from the coordination price and will 
not be a medium for otherwise revising the residual coordination sales 
price.
    The transmission rate for the coordination transactions may be at 
or below the tariff rate. However, if a utility's transmission operator 
offers a discounted transmission rate to the utility's wholesale 
marketing department or an affiliate for the purposes of coordination 
transactions, the same discounted rate must be offered to others for 
trades with any party to the coordination agreement. In addition, 
discounts offered to non-affiliates must be on a basis that is not 
unduly discriminatory.<SUP>424 This may require parties to file 
modifications of the coordination arrangements.
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    \424\ All discounts must be posted on the transmission 
provider's OASIS.
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ISO Principles
    The Commission recognizes that some utilities are exploring the 
concept of an Independent System Operator and that the tight power 
pools are considering restructuring proposals that involve an ISO. 
While the Commission is not requiring any utility to form an ISO at 
this time, we wish to encourage the formation of properly-structured 
ISOs. To this end, we believe it is important to give the industry some 
guidance on ISOs at this time. Accordingly, we here set out certain 
principles that will be used in assessing ISO proposals that may be 
submitted to the Commission in the future.
    These principles are applicable only to ISOs that would be control 
area operators, including any ISO established in the restructuring of 
power pools. We recognize that some utilities are exploring concepts 
that do not involve full operational control of the grid. Without in 
any way prejudging the merits of such arrangements, the following 
principles do not apply to independent administrators or coordinators 
that lack operational control. We do not have enough information at 
this time to offer guidance about such entities, but

[[Page 21596]]

recognize that they could perform a useful role in a restructured 
industry.
    Because an ISO will be a public utility subject to our 
jurisdiction,<SUP>425 the ISO's operating standards and procedures must 
be approved by the Commission. In addition, a properly constituted ISO 
is a means by which public utilities can comply with the Commission's 
non-discriminatory transmission tariff requirements. The principles for 
ISOs are:
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    \425\ A public utility is any person that owns or operates 
facilities used for the transmission of electric energy in 
interstate commerce or the sale of electric energy at wholesale in 
interstate commerce. An ISO will operate facilities used for the 
transmission of electric energy in interstate commerce and thus will 
be subject to the Open Access and OASIS rules.
---------------------------------------------------------------------------

    1. The ISO's governance should be structured in a fair and non-
discriminatory manner. The primary purpose of an ISO is to ensure fair 
and non-discriminatory access to transmission services and ancillary 
services for all users of the system. As such, an ISO should be 
independent of any individual market participant or any one class of 
participants (e.g., transmission owners or end-users). A governance 
structure that includes fair representation of all types of users of 
the system would help ensure that the ISO formulates policies, operates 
the system, and resolves disputes in a fair and non-discriminatory 
manner. The ISO's rules of governance, however, should prevent control, 
and appearance of control, of decision-making by any class of 
participants.
    2. An ISO and its employees should have no financial interest in 
the economic performance of any power market participant. An ISO should 
adopt and enforce strict conflict of interest standards. To be truly 
independent, an ISO cannot be owned by any market participant. We 
recognize that transmission owners need to be able to hold the ISO 
accountable in its fiduciary role, but should not be able to dictate 
day-to-day operational matters. Employees of the ISO should also be 
financially independent of market participants. We recognize, however, 
that a short transition period (we believe 6 months would be adequate) 
will be needed for employees of a newly formed ISO to sever all ties 
with former transmission owners and to make appropriate arrangements 
for pension plans, health programs and so on. In addition, an ISO 
should not undertake any contractual arrangement with generation or 
transmission owners or transmission users that is not at arm's length. 
In order to ensure independence, a strict conflict of interest standard 
should be adopted and enforced.
    3. An ISO should provide open access to the transmission system and 
all services under its control at non-pancaked rates pursuant to a 
single, unbundled, grid-wide tariff that applies to all eligible users 
in a non-discriminatory manner. An ISO should be responsible for 
ensuring that all users have non-discriminatory access to the 
transmission system and all services under ISO control. The portion of 
the transmission grid operated by a single ISO should be as large as 
possible, consistent with the agreement of market participants, and the 
ISO should schedule all transmission on the portion of the grid it 
controls. An ISO should have clear tariffs for services that neither 
favor nor disfavor any user or class of users.
    4. An ISO should have the primary responsibility in ensuring short-
term reliability of grid operations. Its role in this responsibility 
should be well-defined and comply with applicable standards set by NERC 
and the regional reliability council. Reliability and security of the 
transmission system are critical functions for a system operator. As 
part of this responsibility an ISO should oversee all maintenance of 
the transmission facilities under its control, including any day-to-day 
maintenance contracted to be performed by others. An ISO may also have 
a role with respect to reliability planning. In any case, the ISO 
should be responsible for ensuring that services (for all users, 
including new users) can be provided reliably, and for developing and 
implementing policies related to curtailment to ensure the on-going 
reliability and security of the system.
    5. An ISO should have control over the operation of interconnected 
transmission facilities within its region. An ISO is an operator of a 
designated set of transmission facilities.
    6. An ISO should identify constraints on the system and be able to 
take operational actions to relieve those constraints within the 
trading rules established by the governing body. These rules should 
promote efficient trading. A key function of an ISO will be to 
accommodate transactions made in a free and competitive market while 
remaining at arm's length from those transactions. The ISO may need to 
exercise some level of operational control over generation facilities 
in order to regulate and balance the power system, especially when 
transmission constraints limit trading over interfaces in some 
circumstances. It is important that the ISO's operational control be 
exercised in accordance with the trading rules established by the 
governing body. The trading rules should promote efficiency in the 
marketplace. In addition, we would expect that an ISO would provide, or 
cause to be provided, the ancillary services described in this Rule.
    7. The ISO should have appropriate incentives for efficient 
management and administration and should procure the services needed 
for such management and administration in an open competitive market. 
Management and administration of the ISO should be carried out in an 
efficient manner. In addition to personnel and administrative 
functions, an ISO could perform certain operational functions, such as: 
determination of appropriate system expansions, transmission 
maintenance, administering transmission contracts, operation of a 
settlements system, and operation of an energy auction. The ISO should 
use competitive procurement, to the extent possible, for all services 
provided by the ISO that are needed to operate the system. All 
procedures and protocols should be publicly available.
    8. An ISO's transmission and ancillary services pricing policies 
should promote the efficient use of and investment in generation, 
transmission, and consumption. An ISO or an RTG of which the ISO is a 
member should conduct such studies as may be necessary to identify 
operational problems or appropriate expansions. Appropriate price 
signals are essential to achieve efficient investment in generation and 
transmission and consumption of energy. The pricing policies pursued by 
the ISO should reflect a number of attributes, including affording non-
discriminatory access to services, ensuring cost recovery for 
transmission owners and those providing ancillary services, ensuring 
reliability and stability of the system and providing efficient price 
signals of the costs of using the transmission grid. In particular, the 
Commission would consider transmission pricing proposals for addressing 
network congestion that are consistent with our Transmission Pricing 
Policy Statement. In addition, an ISO should conduct such studies and 
coordinate with market participants including RTGs, as may be necessary 
to identify transmission constraints on its system, loop flow impacts 
between its system and neighboring systems, and other factors that 
might affect system operation or expansion.
    9. An ISO should make transmission system information publicly 
available on a timely basis via an electronic information network 
consistent with the Commission's requirements. A free-flow

[[Page 21597]]

of information between the ISO and market participants is required for 
an ISO to perform its functions and for market participants to 
efficiently participate in the market. At a minimum, information on 
system operation, conditions, available capacity and constraints, and 
all contracts or other service arrangements of the ISO should be made 
publicly available. This information should be made available on an 
OASIS operated by the ISO.
    10. An ISO should develop mechanisms to coordinate with neighboring 
control areas. An ISO will be required to coordinate power scheduling 
with other entities operating transmission systems. Such coordination 
is necessary to ensure provision of transmission services that cross 
system boundaries and to ensure reliability and stability of the 
systems. The mechanisms by which ISOs and other transmission operators 
coordinate can be left to those parties to determine.
    11. An ISO should establish an ADR process to resolve disputes in 
the first instance. An ISO should provide for a voluntary dispute 
resolution process that allows parties to resolve technical, financial, 
and other issues without resort to filing complaints at the Commission. 
We would encourage the ISO to establish rules and procedures to 
implement alternative dispute resolution processes.
G. Pro Forma Tariff
    In the NOPR, the Commission stated that--

all utilities use their own systems in two basic ways: to provide 
themselves point-to-point transmission service that supports 
coordination sales, and to provide themselves network transmission 
service that supports the economic dispatch of their own generation 
units and purchased power resources (integrating their resources to 
meet their internal loads). <SUP>426

    \426\ FERC Stats. & Regs. para. 32,514 at 33,079.
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    Accordingly, the Commission proposed two pro forma tariffs in 
Appendices B and C of the NOPR: One for point-to-point service and one 
for network service. Our goal was to encourage the development of 
competitive bulk power markets by ensuring that all participants would 
be able to secure transmission services on a non-discriminatory basis. 
We attempted in the NOPR pro forma tariffs to articulate the minimally 
acceptable terms and conditions of service for point-to-point and 
network transmission service that were required to ensure non-
discriminatory transmission service.<SUP>427 We explained that, for the 
most part, specific pricing provisions were omitted. We asked for 
comments on whether these tariffs provided a good basis for defining 
the minimum acceptable non-price terms and conditions of 
service.<SUP>428
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    \427\ Id. at 33,092.
    \428\ On October 27, 1995, the Commission's staff sponsored a 
technical conference on the pro forma tariffs.
---------------------------------------------------------------------------

    Subsequently, in a June 28, 1995 order, we encouraged public 
utilities to file open access transmission tariffs as soon as 
possible.<SUP>429 Tariffs with terms and conditions of service 
substantively similar to the NOPR pro forma tariffs would become 
effective without a refund condition, assuming there were no other 
concerns, e.g., rate issues. We also indicated that these tariffs would 
be subject to revision based on the Final Rule.
---------------------------------------------------------------------------

    \429\ American Electric Power Service Corporation, et al., 71 
FERC para. 61,393, modified, 72 FERC para. 61,287 (1995).
---------------------------------------------------------------------------

Unified Pro Forma Tariff
    The Commission received many comments on both the point-to-point 
and network tariffs. Many commenters suggested improvements to the 
proposed tariffs. Others took issue with how to reconcile various 
aspects of service under the two tariffs (e.g., cost allocation, 
service priority, customer rights and obligations). As discussed below, 
the Commission has attempted to address these concerns in developing 
tariff requirements for the Final Rule. Importantly, while the 
Commission has retained point-to-point transmission service and network 
transmission service as distinct services, the requirements for the two 
services are now in a single pro forma tariff.<SUP>430 The Final Rule 
pro forma tariff eliminates many of the differences between the two 
NOPR pro forma tariffs, provides a unified set of definitions, and 
consolidates certain common requirements such as the obligation to 
provide ancillary services. The general terms and conditions of 
transmission service specified in the Final Rule pro forma tariff 
should be familiar to all utilities, particularly those that have 
voluntarily filed open access tariffs based on the NOPR pro forma 
tariffs.
---------------------------------------------------------------------------

    \430\ The Final Rule pro forma tariff is attached as Appendix D.
---------------------------------------------------------------------------

    The Commission believes that the modified, single pro forma tariff, 
in conjunction with the other requirements, is sufficient to remedy 
undue discrimination in the provision of transmission services. 
However, we note that in an accompanying notice of proposed rulemaking 
in Docket No. RM96-11-000, we are seeking comments on whether a 
different form of open access tariff--one based solely on a capacity 
reservation system--might better accommodate competitive changes 
occurring in the industry while ensuring that all wholesale 
transmission service is provided in a fair and non-discriminatory 
manner.
    We address below the comments received on the NOPR tariff and the 
specific modifications we have made in the Final Rule pro forma tariff.
1. Tariff Provisions That Affect The Pricing Mechanism
a. Non-Price Terms and Conditions
Comments
    Utilities For Improved Transition argues that any generic 
imposition of detailed tariffs on the electric industry will stifle the 
evolution of the industry. Rather, it asserts, utilities that supply 
transmission service should be permitted to apply general principles of 
comparability in their company-specific tariffs, using terms and 
conditions of service based on their own particular circumstances and 
those of their customers.
    Utility Working Group wants the final rule to allow utilities to 
depart from the pricing method implicitly contained in the NOPR pro 
forma tariffs. It argues that the final rule should recognize that some 
terms and conditions may not make sense in the context of innovative 
pricing proposals.
    DOE thinks that it is proper to base the tariffs on a familiar and 
simple pricing method. However, DOE suggests that, in the future, the 
Commission carefully assess the workability of the contract path model 
in a competitive bulk power market. DOE suggests that spot or real-time 
pricing should be considered.
    Numerous commenters contend that the NOPR pro forma tariffs are 
based upon the contract path, embedded cost methodology. According to 
EEI and other IOU commenters, conforming changes may be needed to 
various terms and conditions of the tariffs to implement pricing 
methodologies that are not based upon contract path. These commenters 
argue that any flow-based model would necessitate different non-price 
terms and conditions. The commenters generally recognize the technical 
difficulties of implementing a flow-based model.<SUP>431 These 
commenters assert that the NOPR pro forma tariffs, as written, are not 
independent of pricing.
---------------------------------------------------------------------------

    \431\ Additional comments concerning transition to flow-based 
pricing are summarized in Section IV.A.6.
---------------------------------------------------------------------------

    EGA criticizes the assumption underlying the contract path 
approach,

[[Page 21598]]

i.e., that the capacities of individual transmission paths can be 
determined independently and made available to third parties. EGA notes 
that, in light of the competitive implications associated with 
transmission pricing, some utilities may propose other non-price terms 
and conditions suitable for other pricing methods, including power-
flow-based tariffs. EGA expresses concern that the pro forma tariffs 
will be the only type of tariff allowed. EGA believes that the 
Commission should follow its transmission pricing policy guidelines and 
not impose a special burden on parties proposing tariffs that differ 
from the final rule pro forma tariffs, including non-price terms that 
support alternative pricing methods.
    Some commenters also interpret the lack of reference to opportunity 
cost and incremental cost in the NOPR pro forma tariffs as a rejection 
of their use.<SUP>432
---------------------------------------------------------------------------

    \432\ E.g., BPA, Utilities For Improved Transition, PG&E, Duke.
---------------------------------------------------------------------------

Commission Conclusion
    We agree that non-price terms and conditions cannot be designed 
independent of pricing and cost recovery. As discussed in detail below, 
the Final Rule pro forma tariff is intended to initiate open access, 
with non-price terms and conditions based on the contract path model of 
power flows and embedded cost ratemaking. It is designed based on the 
practices and procedures currently used by virtually all public 
utilities and complements the large number of tariffs already filed 
with the Commission. The Final Rule pro forma tariff is not intended to 
signal a preference for contract path/embedded cost pricing for the 
future. We recognize that the industry, in response to changes in 
institutions, competitive pressure, and technological innovations, is 
evolving rapidly. For example, various forms of flow-based pricing are 
beginning to be considered in conjunction with electronic transmission 
information systems. We seek to encourage this process and will in the 
future entertain non-discriminatory tariff innovations to accommodate 
new pricing proposals.<SUP>433
---------------------------------------------------------------------------

    \433\ We further clarify that, contrary to some commenters' 
interpretation, the Final Rule pro forma tariff is in no way a 
rejection of opportunity or incremental cost pricing.
---------------------------------------------------------------------------

    In response to various comments, we are revising certain non-price 
terms and conditions where suggested changes either improve the tariff 
services or reconcile tariff inconsistencies. The nature of these 
tariff revisions does not appear to have serious cost consequences. The 
mandated changes are generally compatible with the rate proposals 
already filed by many public utilities. As discussed in Section IV.H., 
those utilities will not be required to file corresponding rate changes 
due to our mandated tariff changes to non-price terms and conditions, 
although they will be permitted to do so.
    The Final Rule pro forma tariff includes specific terms and 
conditions rather than general principles. By initially requiring a 
standardized tariff,<SUP>434 we intend to foster broad access across 
multiple systems under standardized terms and conditions. However, in 
response to concerns raised by certain commenters, the tariff provides 
for certain deviations where it can be demonstrated that unique 
practices in a geographic region require modifications to the Final 
Rule pro forma tariff provisions. Accordingly, where applicable, the 
tariff permits the use of alternative non-price terms or conditions 
that are reasonable, generally accepted in the region, and consistently 
adhered to by the transmission provider.
---------------------------------------------------------------------------

    \434\ As noted in Section IV.H., public utilities may propose 
variations that are consistent with or superior to the terms and 
conditions in the Final Rule pro forma tariff.
---------------------------------------------------------------------------

    Finally, we will allow utilities to propose a single cost 
allocation method for network and point-to-point transmission services. 
These principles, as well as other modifications and clarifications to 
the NOPR pro forma tariffs, are discussed in detail below.
b. Load Ratio Sharing Allocation Mechanism for Network Service
Comments
    Some commenters believe that load ratio cost allocation is 
appropriate for network service.\435\ Other commenters argue that load 
ratio cost allocation is inappropriate, but disagree on the 
alternative. They offer a variety of other cost allocation and pricing 
methods.
---------------------------------------------------------------------------

    \435\ E.g., PSNM, WP&L.
---------------------------------------------------------------------------

    The most frequent comment is that network and point-to-point 
services should be priced on the same basis. Florida Power Corp wants 
network contract demand to be offered and priced on a 12 CP basis.\436\ 
ConEd and Duke argue that their systems are built and designed to meet 
a single peak; therefore, they contend that network service costs 
should be allocated with a load ratio calculation based on annual 
system peak rather than 12 CP. PSE&G claims that load ratio cost 
allocation works only if the customer has its own generation. Many 
commenters propose that ``behind the meter'' generation and load be 
eliminated from the network load ratio calculation.\437\
---------------------------------------------------------------------------

    \436\ Florida Power Corp's contract demand proposal would allow 
a network customer to nominate less than its full load for 
transmission service.
    \437\ E.g., Cajun, NRECA.
---------------------------------------------------------------------------

    CINergy notes that the transmission provider's monthly load ratio 
calculation includes its long-term off-system firm service. It proposes 
that off-system sales be eliminated from the load ratio calculation to 
enable the transmission provider to offer discounts on long-term 
service. Alternatively, CINergy proposes that the revenues from these 
long-term off-system sales be shared with network customers based on 
their load ratio.
    Atlantic City and Allegheny contend that cost allocation for 
network service should also reflect customers' relative energy use 
(i.e., not just customers' coincident demand). Consequently, these 
commenters propose that cost allocation consider the network customer's 
actual load factor. Allegheny also proposes adding a minimum revenue 
provision to the load ratio method to recognize cost responsibility for 
non-peak use. Allegheny further proposes to include an increasing 
return on equity as available transmission capacity decreases. EEI 
proposes that cost allocation be based on a customer's non-coincident 
peak demand.
    Lower Colorado River Authority proposes using load flow studies to 
determine planned use during the system peak with MW-mile billing 
units. It believes that this pricing method should be used for all 
transmission service to ensure comparable transmission pricing. 
Oklahoma G&E wants cost allocation to be based on the impacted MW-mile 
method, or alternatively, to determine embedded cost by voltage level. 
Centerior proposes the use of actual transfer capability instead of 
contract path capability in determining cost responsibility.
    Orange & Rockland recommends some form of a ``poolco'' approach 
using locational marginal cost pricing. DOE also recommends using 
location-specific spot pricing (a form of marginal cost) for operating 
and congestion costs.
    Public Generating Pool believes that load ratio share pricing is 
unworkable in the Pacific Northwest, in part because generation is 
generally located outside of the control area directly served by 
parties in the Northwest, and in part because BPA, which does not have 
a typical service territory, dominates the regional transmission 
market. Seattle states that cost allocation based solely on demand is 
inappropriate for systems

[[Page 21599]]

that consist predominantly of hydro generation.\438\
---------------------------------------------------------------------------

    \438\ Additional comments concerning the Pacific Northwest are 
summarized in Section IV.K.
---------------------------------------------------------------------------

    AEC & SMEPA and NRECA are concerned about pancaked rates for 
network service that is provided to load served by more than one 
network tariff. Other commenters advocate use of some form of regional 
pricing.\439\ American Wind proposes the use of a complex seasonal 
calculation, which appears to benefit wind energy. NY Com and Missouri-
Kansas Industrials also express a preference for seasonal pricing 
models.
---------------------------------------------------------------------------

    \439\ E.g., OH Coops, Municipal Energy Agency Nebraska, UT Com.
---------------------------------------------------------------------------

Commission Conclusion
    We conclude that the load ratio allocation method of pricing 
network service continues to be reasonable for purposes of initiating 
open access transmission. Network service permits a transmission 
customer to integrate and economically dispatch its resources to serve 
its load in a manner comparable to the way that the transmission 
provider uses the transmission system to integrate its generating 
resources to serve its native load. Because network service is load 
based, it is reasonable to allocate costs on the basis of load for 
purposes of pricing network service. This method is familiar to all 
utilities, is based on readily available data, and will quickly advance 
the industry on the path to non-discrimination. We are reaffirming the 
use of a twelve monthly coincident peak (12 CP) allocation method 
because we believe the majority of utilities plan their systems to meet 
their twelve monthly peaks. Utilities that plan their systems to meet 
an annual system peak (e.g., ConEd and Duke) are free to file another 
method if they demonstrate that it reflects their transmission system 
planning. Moreover, we recognize that alternative allocation proposals 
may have merit and welcome their submittal by utilities in future rate 
applications. They will be evaluated on a case-by-case basis and 
decided on their merits.
    As to the concerns raised by AEC & SMEPA and NRECA about pancaked 
rates for network service provided to load served by more than one 
network service provider, we have stated that if a customer wishes to 
exclude a particular load at discrete points of delivery from its load 
ratio share of the allocated cost of the transmission provider's 
integrated system, it may do so.\440\ Customers that elect to do so, 
however, must seek alternative transmission service for any such load 
that has not been designated as network load for network service. This 
option is also available to customers with load served by ``behind the 
meter'' generation that seek to eliminate the load from their network 
load ratio calculation.
---------------------------------------------------------------------------

    \440\ Florida Municipal Power Agency v. Florida Power & Light 
Company, 74 FERC para. 61,006 (1996), reh'g pending.
---------------------------------------------------------------------------

    As noted, the most frequent comment is that the network and point-
to-point services should be priced on a similar basis. This concern is 
addressed in the next section.
c. Annual System Peak Pricing for Flexible Point-to-Point Service
Comments
    Commenters express concern that, if annual system peak capability 
is used to determine rates for point-to-point service and 12 CP is used 
to allocate costs for network service, point-to-point service may be 
underpriced relative to network service.\441\ Therefore, many 
commenters propose pricing both services on the same basis.
---------------------------------------------------------------------------

    \441\ Under the annual system peak method, system costs are 
allocated on the basis of each customer's contribution to the 
utility's annual system peak. Under the 12 CP method, system costs 
are allocated based on the average of the customer's usage at the 
time of the utility's 12 monthly system peaks.
---------------------------------------------------------------------------

    EEI argues that flexible point-to-point service provides a premium 
service at a discount price. Therefore, EEI would increase the price 
unless the Commission either (1) eliminates the flexibility or (2) 
allows network customers to make non-firm sales at no additional 
charge. It recommends use of 12 CP for pricing both network and point-
to-point service, but would credit point-to-point revenues to the cost 
of service for network and native load to avoid over-collection from 
contract demand point-to-point users. Alternatively, EEI contends that 
point-to-point service could use annual system peak capability pricing 
with a ratchet,\442\ although EEI believes that 12 CP reflects the 
premium nature of long-term transmission. Under this alternative 
method, EEI notes that long-term non-flexible point-to-point service 
would use annual system peak pricing, while short-term service should 
be based on ``up to'' (ceiling) rates. In essence, EEI proposes a two-
tier point-to-point service, with the first tier (flexible service) of 
equal priority in all respects to network service.\443\ Ohio Edison 
also claims that, as proposed, flexible point-to-point service is a 
more valuable service than network service because it would be priced 
lower than network service. To correct for this difference, Ohio Edison 
would impose a separate rate for point-to-point non-firm use.
---------------------------------------------------------------------------

    \442\ A ratchet is a billing provision that imposes minimum 
payment obligations on utility customers.
    \443\ See also Centerior, SCE&G, Detroit Edison.
---------------------------------------------------------------------------

    According to NRECA, unless the same measure of demand is included 
in the calculation of network and point-to-point charges, actual 
revenue from these two firm services will be greater than the actual 
cost of service. FL Com believes that flexible point-to-point service 
allows a transmission customer to engage in network economy 
transactions without incurring a full network charge, thus gaining an 
advantage over the transmission provider. Atlantic City recommends that 
the Commission either (1) eliminate the flexibility of point-to-point 
service or (2) price such service on a 12 CP basis. It claims that the 
use of an annual system peak capability creates a higher value service 
at a lower cost than network service. Based on its 1994 system data, 
Atlantic City claims that there is a 33 percent difference in rates 
between network and point-to-point services. Atlantic City also opposes 
the requirement to offer point-to-point service on an hourly basis, 
claiming that, unlike the point-to-point service customer, native load 
and network service customers are responsible for system investment 
year-round. Atlantic City also argues that point-to-point customers 
should pay for all non-firm use, i.e., the Commission should eliminate 
the flexible nature of firm point-to-point service. PSE&G argues that 
point-to-point service should be used only for through-flow or out-flow 
transactions with all other transactions treated as network service. 
Thus, according to PSE&G, point-to-point service would not need 
flexibility.
    If an annual system peak capability is used, Oklahoma G&E would 
redefine point-to-point service to eliminate the flexibility. FPL 
recommends either eliminating the flexibility to nominate secondary 
receipt and delivery points and receive non-firm service between them 
or pricing point-to-point service as premium service (i.e., at a higher 
price than network service). Florida Power Corp claims that flexibility 
should be associated with network service, not point-to-point service. 
It also argues that revenues from point-to-point service should be 
credited against total transmission costs. It would similarly exclude 
point-to-point demands from the derivation of the network rate. Utility 
Working Group claims that if flexible point-to-point service is 
retained, such service should be priced at a higher (unspecified) rate 
or the non-firm secondary use should be separately priced. It believes 
that all users should

[[Page 21600]]

pay for non-firm use, or if there is no additional charge under the 
point-to-point tariff, network customers and the transmission provider 
should be treated equally. SMUD argues that a user who does not want 
flexibility should have an option to elect a lower-priced non-flexible 
point-to-point service.
Commission Conclusion
    We agree that pricing both services on a consistent basis may be 
appropriate. Consequently, we will allow a transmission provider to 
propose a formula rate that assigns costs consistently to firm point-
to-point and network services. While not requiring the use of any 
particular rate methodology, we will no longer summarily reject a firm 
point-to-point transmission rate developed by using the average of the 
12 monthly system peaks.
    Our previous rationale for not using the average of the twelve-
monthly peaks as a denominator in the development of non-customer 
specific transmission rates was enunciated in Southern Company 
Services, Inc., 61 FERC para. 61,339 (1992) (Southern). In Southern, 
the Commission was concerned that establishing a system-wide, non-
customer specific transmission service rate that did not appropriately 
account for diversity <SUP>444 among various transmission customers 
might result in the over-recovery of revenues for point-to-point 
service. Inherent in our ruling in Southern was the understanding that 
once a sufficient pattern of customer usage under the tariff was 
established, the company was free to file a customer-specific rate 
using the average of the 12 monthly system peaks for cost allocation. 
We still believe that it is appropriate for utilities to use a 
customer-specific allocated cost of service <SUP>445 to account for 
diversity, but based on the changed circumstances since Southern (which 
we discuss below) we will now permit an alternative.
---------------------------------------------------------------------------

    \444\ In this context, diversity occurs when a customer's peak 
demand is not coincident with the transmission provider's system 
peak demand.
    \445\ The use of this rate design is particularly applicable 
where customers who were taking bundled service convert to 
transmission-only service under the point-to-point tariff and 
ensures that transmission costs are allocated to point-to-point 
customers and network customers in a consistent manner.
---------------------------------------------------------------------------

    We also note that the circumstances in Southern are distinguishable 
from those now present in the industry. Southern proposed a rigid, 
inflexible firm point-to-point transmission service where the customer 
paid separately for each delivery and receipt point combination. The 
only flexibility permitted was to use alternative receipt and delivery 
points on a non-firm basis at no additional charge. As the name 
implies, the flexible nature of the point-to-point transmission service 
proposed in the NOPR is more akin to the service provided to native 
load and network service customers. Contrary to what was proposed in 
Southern, point-to-point service does not require separate charges for 
each firm service receipt and delivery point combination. Rather, 
customers pay on the basis of the higher of the total delivery points 
or total receipt point combination. Flexible point-to-point 
transmission customers continue to be able to access alternative 
receipt and delivery points on a non-firm basis without additional 
charges (as long as they remain within their capacity reservation). In 
addition, firm point-to-point customers can reassign and resell unused 
portions of their reserved firm capacity to third parties. With 
flexible firm and non-firm point-to-point transmission service, the 
transmission provider must make firm point-to-point transmission 
capacity available to the customer regardless of its load 
characteristics or use.
    For these reasons, we will allow all firm transmission rates, 
including those for flexible point-to-point service, to be based on 
adjusted system monthly peak loads. The adjusted system monthly peak 
loads consist of the transmission provider's total monthly firm peak 
load minus the monthly coincident peaks associated with all firm point-
to-point service customers plus the monthly contract demand 
reservations for all firm point-to-point service.
    The flexibility and reassignment rights of this transmission 
service require the transmission provider to hold the firm contract 
capacity available regardless of the customer's own load 
characteristics or its actual use. In other words, a transmission 
provider's obligation to plan for, and its ability to use, a 
transmission customer's reserved capacity is clearly defined by that 
customer's contract reservation. For these reasons, it is appropriate 
to consider a firm reservation as the equivalent of a load for cost 
allocation and planning purposes.
    In order to prevent over-recovery of costs for those who use this 
approach, we will require transmission providers to include firm point-
to-point capacity reservations in the derivation of their load ratio 
calculations for billings under network service. In addition, revenue 
from non-firm services should continue to be reflected as a revenue 
credit in the derivation of firm transmission tariff rates. The 
combination of allocating costs to firm point-to-point service and the 
use of a revenue credit for non-firm service will satisfy the 
requirements of a conforming rate proposal enunciated in our 
Transmission Pricing Policy Statement.<SUP>446
---------------------------------------------------------------------------

    \446\ FERC Stats. & Regs. para. 31,005 (1994).
---------------------------------------------------------------------------

d. Opportunity Cost Pricing
(1) Recovery of Opportunity Costs
Comments
    EEI and IOUs generally support the notion that transmission 
customers should pay some form of opportunity cost when transmission is 
constrained and request that the final rule clearly define redispatch 
and opportunity costs. These commenters generally agree that the final 
rule should codify these terms consistent with recent Commission orders 
addressing opportunity costs.
    Duke requests that the final rule clarify that the transmission 
customer should pay all the opportunity costs associated with modified 
dispatch. Centerior argues that redispatch costs include consideration 
of parallel flows and scheduled deliveries, which, according to 
Centerior, cause redispatch costs to be incurred.
    Florida Power Corp and NYSEG state that redispatch costs should be 
either rolled in or charged on an incremental basis, consistent with 
the Commission's ``or'' pricing policy. Florida Power Corp recommends 
that an opportunity cost recovery provision be added to the ``Rates and 
Charges'' sections of the tariffs. NYSEG recommends that the tariffs 
implement the Commission's recent ruling in Florida Power & Light 
Company, 66 FERC para. 61,227 (1994), allowing lost opportunity costs 
to be recalculated annually. NYSEG believes that: (1) Redispatch costs 
should be collected for any period in which the transmission customer 
causes a constraint, including the period of time it takes to construct 
incremental facilities necessary to alleviate the constraint; (2) 
network customers should be responsible for any opportunity costs 
incurred as a result of their non-firm use of the system if such costs 
rise to a level above their load ratio share of system costs; and (3) 
point-to-point customers should be responsible for any opportunity 
costs incurred as a result of their non-firm use of the transmission 
provider's system up to their reserved firm entitlement.
    Ohio Edison believes that, given the unique nature of network 
service, it is inappropriate to require network service customers to 
incur redispatch costs in order to create additional capacity. PECO 
requests that the final rule clearly indicate (1) from whose 
perspective

[[Page 21601]]

``least cost'' redispatch is judged and (2) that the ``least cost'' 
redispatch obligation is subordinate to reliability.
    Concerned that transmission providers could manipulate the 
calculation of redispatch charges to increase profits, NRECA proposes 
that transmission providers develop formal redispatch protocols that 
would be provided to all customers. NRECA argues that all information 
necessary to calculate redispatch costs should be made available on the 
RIN. Customers assessed redispatch charges should be provided with all 
the necessary information to evaluate such charges, including full 
audit rights. NRECA, Cajun, and PacifiCorp object to the inclusion of 
``lost opportunity'' costs in redispatch charges. NRECA proposes that 
only actual non-firm sales or purchases should be included in the 
calculation of opportunity costs.
    United Illuminating and Seattle state that all opportunity costs 
should be assessed to short-term and non-firm transmission service 
customers that cause the transmission provider to redispatch its 
generation to unload a constrained transmission line. According to 
United Illuminating, it is not appropriate to roll opportunity costs 
into the rates charged other transmission users because existing users 
do not have the choice to pay the opportunity costs or to allow their 
transaction to be curtailed.
    UtiliCorp, on the other hand, states that all ``out of rate'' 
uneconomic dispatch costs should be rolled in and recovered from all 
users of the transmission system. UtiliCorp argues that directly 
assessing these costs to a particular customer would unfairly penalize 
a customer who could not gain access to a system until after the 
tariffs take effect.
    CCEM argues that only lost opportunity costs associated with the 
loss of firm purchases or sales should be recoverable. CCEM also 
believes that the transmission provider should calculate the redispatch 
costs in advance and transmission customers should be able to opt out 
of redispatch if costs rise above a certain level.
Commission Conclusion
    We will retain redispatch provisions in the Final Rule pro forma 
tariff, but clarify that redispatch is required only if it can be 
achieved while maintaining reliable operation of the transmission 
system in accordance with prudent utility practice.
    We find that the recovery of redispatch cost requires that: (1) A 
formal redispatch protocol must be developed and made available to all 
customers; and (2) all information necessary to calculate redispatch 
costs should be made available to the customer for audit.
    As discussed in the Section IV.H., the Commission is according 
substantial flexibility to public utilities to propose appropriate 
pricing terms, including opportunity cost pricing, in their compliance 
tariff. However, as with any compliance filing, the rates proposed must 
meet the standards for conforming proposals in the Transmission Pricing 
Policy Statement.
    In Northeast Utilities and Penelec, we fully explained our 
rationale for allowing utilities to charge opportunity costs.<SUP>447 
We concluded that a public utility is entitled to full compensation for 
all ``legitimate'' and ``verifiable'' costs it incurs to provide firm 
transmission service.<SUP>448 We explained that where a utility can 
demonstrate that additional opportunity costs are incurred as a direct 
result of providing transmission service, our pricing principles would 
permit recovery of those costs. The Commission further explained in the 
Transmission Pricing Policy Statement that when transmission capacity 
is constrained and a utility does not expand capacity, we have allowed 
the utility to charge transmission customers the higher of embedded 
costs or legitimate and verifiable opportunity costs, but not the sum 
of the two (i.e., ``or'' pricing is permitted; ``and'' pricing is not). 
The opportunity costs are capped by incremental expansion 
costs.<SUP>449
---------------------------------------------------------------------------

    \447\ Northeast Utilities Service Company (Northeast Utilities), 
56 FERC para. 61,269 (1991), order on reh'g, 58 FERC para. 61,070, 
reh'g denied, 59 FERC para. 61,042 (1992), order granting motion to 
vacate and dismissing request for rehearing, 59 FERC para. 61,089 
(1992), aff'd in relevant part and remanded in part, Northeast 
Utilities Service Company v. FERC, 993 F.2d 937 (1st Cir. 1993); 
Pennsylvania Electric Company (Penelec), 58 FERC para. 61,278 at 
62,871-75, reh'g denied, 60 FERC para. 61,034 (1992), affd, 
Pennsylvania Electric Company v. FERC, 11 F.3d 207 (D.C. Cir. 1993).
    \448\ Penelec, 58 FERC at 61,872; 60 FERC para. 61,034 at 61,126 
(1992).
    \449\ FERC Stats. & Regs. para. 31,005 at 31,138.
---------------------------------------------------------------------------

    Transmission providers proposing to recover opportunity costs must 
adhere to the following requirements:
    (1) A fully developed formula describing the derivation of 
opportunity costs must be attached as an appendix to their proposed 
tariff.
    (2) Proposals must address how they will be consistent with 
comparability.
    (3) All information necessary to calculate and verify opportunity 
costs must be made available to the transmission customer.
(2) Fuel Adjustment Clause Treatment for Redispatch Costs
    If the transmission provider proposes to separately collect 
redispatch costs on a direct assignment basis from a specific 
transmission customer, we will require that the transmission provider 
credit these revenues to the cost of fuel and purchased power expense 
included in its wholesale fuel adjustment clause.
e. Expansion Costs
Comments
    ELCON argues that direct assignment of 100% of the costs of 
expanding a constrained transmission system to a particular customer is 
unfair. NY Energy Buyers believes that the costs of expanding the 
transmission system should be shared among all customers seeking 
transmission service. Alternatively, NY Energy Buyers states that if 
direct assignment of system expansions is adopted, such costs should be 
payable both by new wholesale customers and by new retail load. 
According to NY Energy Buyers, it would be preferable for the utility 
to treat all requesters during a given period as making one request for 
a large increment of capacity, with all requesters paying the same 
average incremental cost. New native load also should be considered to 
be a requester of transmission capacity and allocated an appropriate 
share of any expansion costs.
    CA Energy Co believes that incremental pricing will discriminate 
against all later competitors by charging higher rates. It advocates 
rolled-in pricing with the requirement that all users requesting system 
expansion commit to service for a term that will cover their 
proportionate expansion cost assignments.
    FPL proposes that costs associated with normal load growth and the 
repair and/or replacement of older facilities be rolled in with the 
other embedded transmission costs and shared on a load ratio basis. 
However, it believes that transmission expansions associated with the 
addition of a new resource should be separately assigned.
    On the other hand, Orange & Rockland maintains that unless 
expansion costs are directly assigned, an unfair subsidization will 
occur. According to PECO, transmission customers should be assigned 
costs for system upgrades under both the network and point-to-point 
tariffs. Consumers Power claims that the network tariff is unclear 
about which facilities are directly assignable, and proposes that all 
costs that exceed the

[[Page 21602]]

embedded average cost qualify for direct assignment.
    SMUD requests that the final rule clarify that if a transmission 
customer invests in incremental facilities, it will be entitled to 
ownership-like rights to the capacity addition.
    In order to avoid possible argument over the necessity and cost of 
system expansions for a particular transmission request, NIEP requests 
that the final rule require utilities to use a ``least-cost'' approach 
to transmission expansion that includes comparable transmission 
expansion practices for all wholesale customers.
    According to Duke, the concern that the transmission provider's 
retail customers will retain an advantage by having expansion costs 
placed on third parties is misplaced. Duke argues that, under ``or'' 
pricing, the issue of who is responsible for expansion costs would 
still arise. It contends that the Commission will have to decide on a 
case-by-case basis whether expansion costs are incurred for the benefit 
of a specific party or are part of overall network costs. Duke 
generally supports the current ``or'' pricing policy.
    Citing the Commission's Transmission Pricing Policy Statement, FL 
Com supports the flexibility of charging both embedded cost and 
incremental cost transmission rates, i.e., ``and'' pricing. It argues 
that, because of the dynamic and interconnected nature of the 
transmission system, tariff customers causing expansion costs should be 
held responsible for both the incremental cost of the addition and some 
portion of the existing transmission system needed to support the 
addition. FL Com states that the comparability standard is at odds with 
the Commission's non-conforming transmission pricing policy, 
particularly with respect to ``and'' pricing.
Commission Conclusion
    Under the Final Rule pro forma tariff, we will allow transmission 
providers to propose any method of collecting expansion costs that is 
consistent with our transmission pricing policy. We disagree with 
ELCON's assertion that directly assigning the costs for expanding a 
constrained transmission system is necessarily unfair. As we stated in 
Northeast Utilities, if the cost of expansion is directly attributable 
to a customer's request for transmission service and the expansion 
would not be undertaken ``but for'' that customer's request, then it is 
reasonable to assign the cost of expansion to that customer. If we were 
not to allow the direct assignment of expansion costs to the customer 
causing the expansion, then other customers would subsidize the new 
customer's use of the transmission system. We continue to believe that 
``or'' pricing sends the proper price signal to customers and promotes 
efficiency. Under the tariff, any assignment of future expansion costs 
must meet the standards for conforming proposals in the Transmission 
Pricing Policy Statement. Recovering expansion cost based upon ``and'' 
pricing will not be allowed.
    Any request to recover future expansion costs will require a 
separate section 205 filing. The Commission will evaluate, on a case-
by-case basis, who is responsible for expansion costs in those filings 
and whether direct assignment of those costs is appropriate.
f. Credit for Customers' Transmission Facilities
Comments
    Most commenters agree that the Commission must clearly define when 
a network customer's transmission facilities warrant a credit from the 
transmission provider. Several commenters state that customers must 
bear the burden of demonstrating that their facilities are used by and 
useful to the transmission provider, provide direct benefits, and 
support the operation of the transmission system.<SUP>450 EEI cautions 
against providing a credit for facilities that may be integrated with, 
but of no effective benefit to, the operation of the bulk power system.
---------------------------------------------------------------------------

    \450\ E.g., EEI, Consumers Power.
---------------------------------------------------------------------------

    The costs associated with customer-owned facilities that are used 
by the transmission provider should, in PECO's opinion, be recovered 
from the transmission provider under the customer's own transmission 
tariff.
    FPL cautions that the position of certain parties that transmission 
facilities warrant a credit if they would have been included in the 
transmission provider's rates could produce absurd results. It claims 
that it could actually end up paying a network customer with 
substantial transmission investment for the right to provide that 
customer service. FPL contends that it will receive absolutely no 
service from its network customers because FPL would not need, nor 
could it use, any of the customers' transmission facilities to 
integrate FPL's loads and resources. FPL argues that crediting under 
the so called ``rate base'' test obligates the transmission provider to 
purchase a load-ratio share of the customer's transmission facilities. 
FPL states that, under network service, the transmission provider and 
the network customer will not create a single system.
    AEP recommends that a network customer receive a credit if its 
transmission facilities meet the following criteria: (1) At points of 
interconnection, there must be a through-flow of power from the network 
customer's system to the transmission provider's system under normal 
operating conditions; and (2) the customer's facilities must: (a) 
Increase the transfer capability of an interface on the transmission 
provider's system; (b) provide an alternative path for power flows 
during transmission facility outages, thus increasing the reliability 
or stability of the combined system; or (c) otherwise satisfy the 
transmission provider's planning criteria for the installation of 
network facilities.
    WP&L argues for a broader standard and states that a transmission 
customer should be entitled to a credit if the transmission owner would 
have installed similar facilities to provide service for its own native 
load under similar circumstances. Florida Power Corp states that the 
credit for each facility should be determined on a case-by-case basis.
    PacifiCorp argues that a utility may take advantage of the 
transmission credit and shift major transmission investment onto 
another transmitting utility and its transmission customers by simply 
becoming a network customer. PacifiCorp claims that such a situation 
may, for example, exist for BPA as a transmitting utility. According to 
PacifiCorp, preliminary studies indicate at least one potential network 
customer may be entitled to a transmission credit which would exceed 
that customer's charges for BPA's network integration service.
    APPA, Blue Ridge, and Cajun maintain that a customer's facilities 
should be evaluated on a basis comparable to the facilities included in 
the rates of transmission providers in a region. APPA argues that a 
claim that the transmission customer's facilities do not benefit the 
transmission system must be weighed against the fact that some 
facilities included in the transmission provider's rate base may not 
directly benefit the transmission customer. Cajun advocates setting 
clear standards for the identification of customer-owned transmission 
facilities eligible for crediting and clear guidelines for determining 
the amount of the credit.
    SMUD not only supports the credit under the network tariff, but 
also would extend the credit to facilities used to complete a 
transaction under the transmission provider's point-to-point tariff.

[[Page 21603]]

Commission Conclusion
    Because of the diverse concerns raised by the commenters, we are 
unable to resolve on the basis of this record the extent to which, or 
under what circumstances, cost credits related to customer-owned 
facilities would be appropriate under an open-access transmission 
tariff. We conclude that such credits are more appropriately addressed 
on a case-by-case basis, where individual claims for credits may be 
evaluated against a specific set of facts.
    We stress that while certain facilities may warrant some form of 
cost credit, the mere fact that transmission customers may own 
transmission facilities is not a guaranteed entitlement to such a 
credit. The presumption of many commenters that a customer's 
subscription to transmission service somehow transforms the provider's 
and customer's systems into an expanded integrated whole to the mutual 
benefit of both is not a valid one. As we ruled in Florida Municipal 
Power Agency v. Florida Power & Light Company (FMPA), it must be 
demonstrated that a transmission customer's transmission facilities are 
integrated with the transmission system of the transmission provider. 
Specifically, we stated that:


    The integration of facilities into the plans or operations of a 
transmitting utility is the proper test for cost recognition in such 
cases. The mere fact that a section 211 requestor has previously 
constructed facilities is not sufficient to establish a right to 
credits.<SUP>451

    \451\ 74 FERC para. 61,006 at 61,010 (1996), reh'g pending.
---------------------------------------------------------------------------

The fact that a transmission customer's facilities may be 
interconnected with a transmission provider's system does not prove 
that the two systems comprise an integrated whole such that the 
transmission provider is able to provide transmission service to itself 
or other transmission customers over those facilities--a key 
requirement of integration.<SUP>452 We also note that consistent with 
our ruling in FMPA, if a customer wishes not to integrate certain loads 
and resources, and thereby exclude them from their load ratio share of 
the allocated cost of the integrated system, it may do so. Customers 
that elect to do so, however, should recognize that they may need to 
secure alternative transmission arrangements such as point-to-point 
transmission service on an as-available basis in order to utilize those 
resources for reserves.
---------------------------------------------------------------------------

    \452\ We caution all transmission providers that while our 
discussion here addresses the requirements necessary for a 
customer's transmission facilities to become eligible for a credit, 
the principles of comparability compel us to apply the same standard 
to the transmission provider's facilities for rate determination 
purposes.
---------------------------------------------------------------------------

    Where disputes over credits for customer-owned transmission 
facilities arise, we encourage all parties to first pursue alternative 
means to resolve their differences rather than seek formal resolution 
at the Commission. In any event, the Commission anticipates that 
disputes over the appropriate level of transmission facility credits 
should not preclude transmission customers from initiating service 
under the tariff. Where the parties are unable to reach agreement on 
the appropriate credit for customer-owned transmission facilities, the 
parties may make an appropriate filing with the Commission.
g. Ceiling Rate for Non-Firm Point-to-Point Service
Comments
    Commenters generally support a ceiling rate for non-firm 
transmission service, capped at the firm rate.<SUP>453 Others request 
clarification as to whether the point-to-point tariff rates are fixed 
or are ceiling rates. Central Illinois Public Service's major concern 
is that, if the rates are fixed, the tariffs may result in higher 
prices for capacity and energy than those currently allowed for bundled 
service.
---------------------------------------------------------------------------

    \453\ E.g., Duke, SCE&G, AEP, FPL.
---------------------------------------------------------------------------

    NYSEG argues that unequal pricing is a natural phenomenon of the 
open marketplace and requests assurance that offering transmission 
service at prices below a cost-based ceiling rate will not expose a 
transmission provider to claims of undue discrimination.
    AEC & SMEPA opposes using the firm rate as the cap for non-firm 
transmission service. It states that, given the substantially lower 
quality of non-firm service (with no obligation to plan for such 
service), no cost-of-service principle justifies charging rates for 
non-firm service as high as the rate for firm service.
    EGA and NRECA state that any discounts from the maximum firm rate 
must be uniform, transparent, readily understood, and posted on a RIN. 
According to CCEM and NRECA, the transmitting utility must have 
nondiscriminatory discount practices and must contemporaneously offer 
discounts to transmission customers at the same time and on the same 
basis as discounts for internal sales operations or affiliates.
Commission Conclusion
    We believe that it is important to continue to allow pricing 
flexibility. In accordance with the Commission's current policies, the 
rate for non-firm point-to-point transmission service may reflect 
opportunity costs. Any provisions for opportunity cost pricing for non-
firm service must meet the requirements already discussed. If a utility 
chooses to adopt opportunity cost pricing, the non-firm rate is 
effectively capped by the availability of firm service and is not 
subject to a separately-stated price cap. If a utility chooses not to 
adopt opportunity cost pricing, the non-firm rate is capped at the firm 
rate. We also wish to ensure that non-firm transmission service is 
priced in a nondiscriminatory fashion. Accordingly, if a transmission 
provider offers a rate discount to its affiliate, or if the 
transmission provider attributes a discounted rate to its own 
transactions, the same discounted rate must also be offered at the same 
time to non-affiliates on the same transmission path and on all 
unconstrained transmission paths. We will further require that any 
affiliate discounts from the maximum firm rate must be transparent, 
readily understandable, and posted on the transmission provider's OASIS 
in advance so that all eligible customers have an equal opportunity to 
purchase non-firm transmission at the discounted rate.<SUP>454 In 
addition, discounts offered to non-affiliates must be on a basis that 
is not unduly discriminatory and must be reported on the OASIS within 
24 hours of when available transmission capability (ATC) is adjusted in 
response to the transaction. As discussed in the RIN section, 
information, including the price for all non-firm transaction 
discounts, must be posted on the OASIS to ensure comparability.
---------------------------------------------------------------------------

    \454\ The same requirements will apply to discounts from firm 
transmission service. Similarly, if a transmission provider offers 
an affiliate a discount for ancillary services, or attributes a 
discounted ancillary service rate to its own transactions, it must 
offer at the same time the same discounted rate to all eligible 
customers. Discounted ancillary services rates must be posted on the 
OASIS pursuant to new Part 37 of the Commission's regulations.
---------------------------------------------------------------------------

2. Priority for Obtaining Service
Comments
    The term ``priority'' is used in the comments in several senses. 
The intent of the comment depends on which kind of ``priority'' is 
intended. In general, there are comments about the order in which 
parties can obtain new service, which we call ``reservation priority,'' 
and there are comments about the order in which parties lose service 
they already have, which we call ``curtailment priority.'' Commenters 
may establish different reservation priorities for various services, 
such as network, off-system sales, firm, ability to reserve a portion 
of new transmission

[[Page 21604]]

capacity to be constructed, and so on. Curtailment priorities also 
differ with the type of service. However, many commenters assert that 
certain parties should or should not have ``priority'' without 
distinguishing the kind of priority or type of service for which 
priority is intended.
a. Reservation Priority for Existing Firm Service Customers
Comments
    Many IOUs, state commissions, and cooperatives strongly believe 
that native load should have priority to reserve transmission capacity 
under the tariffs.
    EEI suggests that existing and future allocations of transmission 
capacity must be based on proper transmission pricing or, in its 
absence, priority of service. According to EEI, retail and existing 
wholesale requirements service should have the highest priority for use 
of transmission capacity, followed by long-term point-to-point service. 
Dayton P&L supports a continued preference for native load growth 
because native load customers have borne the majority of the costs of 
the transmission system. Detroit Edison, EEI, and Florida Power Corp 
claim that, because native load and network customers pay higher rates 
during all hours, such customers should have higher priority for 
service requests than others requesting transmission service. These 
commenters also claim that the transmission provider should be able to 
reserve firm capacity for native load and network service customers.
    Similarly, NARUC wants wholesale and retail native load customers 
to be held harmless from functional unbundling of wholesale 
transmission services. Because these customers have borne the vast 
majority of the costs of the utility's transmission facilities, NARUC 
argues that priority of service, quality of service, and allocation of 
joint and common costs to native load customers should not be affected 
by the transition to an open access transmission regime.
    PA Com does not share the Commission's concern that a transmission 
provider may discriminate against a third party transmission customer 
vis-a-vis native load. It finds nothing impermissible in this sort of 
discrimination, arguing that the interconnected system was financed by, 
designed for, and built to serve native load.
    NRECA explains that most transmission customers that seek network 
service will already be receiving similar service (albeit in a bundled 
form) from their transmission providers. It argues that these customers 
should receive the same priority of service as the transmission 
provider's native load customers for as long as they continue to take 
network service, whether under a current bundled wholesale supply 
contract, a private transmission contract, or a network tariff.<SUP>455
---------------------------------------------------------------------------

    \455\ See also American Forest & Paper, AMP-Ohio.
---------------------------------------------------------------------------

    East Kentucky requests that the final rule clarify that member 
distribution cooperatives of G&Ts will have priority over third parties 
in the use of the G&T's existing transmission facilities. TVA comments 
that native load customers and emergency service to neighboring systems 
should have a higher service priority than transmission services sold 
to third parties (where an alternative power supply is available to the 
third party).
Commission Conclusion
    We reiterate that we are not requiring the transmission provider to 
unbundle transmission service to its retail native load nor are we 
requiring that bundled retail service be taken under the terms of the 
Final Rule pro forma tariff. However, the amount of transmission 
capacity available to wholesale and unbundled retail customers under 
the Final Rule pro forma tariff is clearly affected by the amount of 
transmission capacity that the transmission provider reserves for the 
use of its native load customers and the future load growth of those 
customers. The transmission provider may reserve in its calculation of 
ATC transmission capacity necessary to accommodate native load growth 
reasonably forecasted in its planning horizon. However, the 
transmission provider is obligated to provide transmission service to 
others under the Final Rule pro forma tariff out of capacity reserved 
for native load growth up to the time the capacity is actually needed 
for such future needs. Furthermore, as we explained previously, while 
existing wholesale customers do not have any ownership-like rights to 
the capacity they used during the term of their contract, they will 
have a right of first refusal to that capacity after the expiration of 
their contracts or when their contracts become subject to renewal or 
rollover.<SUP>456
---------------------------------------------------------------------------

    \456\ See discussion in Section IV.A.5.
---------------------------------------------------------------------------

b. Reservation Priority for Firm Point-to-Point and Network Service
Comments
    A number of commenters argue that all firm service should not be 
treated equally. These commenters argue that the price of the service 
should determine the priority that the service receives. A large number 
of IOUs and potential network customers (existing requirements 
customers) argue that in light of the pricing implicit in the NOPR, 
(i.e., 12 CP for network versus annual system peak for point-to-point) 
network service should have priority over point-to-point service 
(because, all other things being equal, the price for network service 
will be higher).
    BG&E believes that a customer receiving service priority equal to 
native load and network customers should pay comparable rates. Thus, 
BG&E argues that either flexible firm point-to point service should be 
priced the same as network service, or point-to-point service should 
have a lesser priority than native load and network service customers 
if point-to-point service is priced lower than network service.
    DE Muni believes that native load and network customers must have 
priority access to interfaces (particularly where they are constrained) 
after system reliability concerns have been satisfied. The same 
argument is advanced by commenters concerning long-term service versus 
short-term service. Public Generating Pool argues that long-term 
service should always have priority over short-term service because 
long-term customers contribute more towards fixed-cost recovery than do 
short-term customers.
    Cajun objects to having its service and service to its customers, 
which it characterizes as network service, receive the same priority as 
firm point-to-point service customers who take service for periods as 
short as one hour. Cajun points out that it, as well as other network 
and native load customers, have been paying and will be paying for the 
transmission facilities in place to serve their needs for many years. 
According to Cajun, the transient firm point-to-point customer should 
not have equal standing. Cajun suggests, however, that a long-term firm 
point-to-point customer taking service for ten years or more should 
have service priority equal to native load and network service 
customers.
    SC Public Service Authority argues that the availability of short-
term firm service with a priority equal to long-term service would 
provide a means for short-term customers to obtain the advantages of 
long-term firm service at a much lower total cost. As a result, it 
argues that a few point-to-point customers would opt for long-term firm 
service, and the burden of the residual costs of the transmission 
system would fall on network customers.
    EEI claims that priority for point-to-point service should be on a 
continuum of firmness, with reservation (as well as

[[Page 21605]]

curtailment) priority based upon duration of service and specific 
negotiated terms. EEI proposes that the point-to-point tariff be 
modified to provide a first-tier category of flexible point-to-point 
transmission service that is comparable in priority, price, length, and 
terms of service to network service. EEI believes that this 
modification will resolve the problems that are associated with 
establishing priorities between network service and point-to-point 
service if the Commission retains different CP cost allocation methods 
for each service.
    On the other hand, CCEM, a group of power marketers, supports the 
concept that all firm service should be treated equally, regardless of 
the term or the nature of service.
Commission Conclusion
    An essential element of non-discriminatory transmission access is 
the right of transmission customers to reserve and purchase 
transmission service that is of the same quality as that used by the 
transmission provider in serving its wholesale requirements customers 
and retail load. Thus, we reject the proposal of some commenters that 
transmission providers need not provide firm point-to-point service 
that is of the same ``firmness'' as the transmission provider's service 
to native load. However, the fact that both network service and point-
to-point service are provided on an equally firm basis does not mean 
that both types of service must be priced or reserved in the same 
manner.
    The comments about reservation priorities for firm services boil 
down to two concerns. First, due to the differences in pricing firm 
point-to-point service and network service implicit in the NOPR (i.e., 
twelve-monthly CP pricing for network versus annual system peak for 
point-to-point), some commenters believe that network service should 
have priority over point-to-point service. Second, some commenters 
maintain that according firm, short-term point-to-point service a 
priority equal to long-term service provides a means for short-term 
customers to avoid making a fair contribution to the long-term costs of 
the system.
    With respect to the first concern, we have eliminated the 
differences in pricing by permitting utilities to adopt point-to-point 
reservations as the customer load. As discussed above, for purposes of 
the Final Rule pro forma tariff, utilities are free to propose a single 
cost allocation method for the two services.
    The second area of concern arises because of the first-come first-
served reservation priority in the NOPR point-to-point tariff. The 
Commission recognizes that the tariffs, as proposed in the NOPR, 
provide the opportunity for a customer to reserve certain valuable 
rights (e.g., the right to short-term firm service during peak periods) 
while avoiding in part the long-term costs of the system (perhaps by 
relying on non-firm service during lengthy off-peak periods when there 
is a substantially reduced chance of interruption). However, the 
Commission has a countervailing concern that the transmission provider 
should not be able to withhold valuable transmission capacity from 
potential customers if that capacity is not being used by those who are 
paying for the long-term costs of the system.
    Accordingly, the Final Rule pro forma tariff provides a mechanism 
to address this concern while safeguarding the rights of potential 
customers to obtain access to unused capacity. The tariff provides that 
reservations for short-term firm point-to-point service (less than one 
year) will be conditional until one day before the commencement of 
daily service, one week before the commencement of weekly service, and 
one month before the commencement of monthly service. These conditional 
reservations may be displaced by competing requests for longer-term 
firm point-to-point service. For example, a reservation for daily firm 
point-to-point service could be displaced by a request for weekly firm 
point-to-point service during an overlapping period. Before the 
applicable reservation deadline, a holder of a conditional firm point-
to-point reservation would have the right of first refusal to match any 
longer-term firm point-to-point reservation before being displaced. 
After the deadline, the reservation becomes unconditional, and the 
service would be entitled to the same priorities as any long-term 
point-to-point or network firm service.<SUP>457
---------------------------------------------------------------------------

    \457\ The service itself, as opposed to reservations, is subject 
to the curtailment provisions discussed below.
---------------------------------------------------------------------------

    The Final Rule pro forma tariff does not propose point-to-point or 
network service with various degrees of firmness beyond the simple 
categories of firm and non-firm. When a customer requests firm 
transmission service, reservation priorities are established based 
first on availability, and in the event the system is constrained, 
based on duration of the underlying firm service request; customers may 
choose the ``firmness'' of service they want by electing to take non-
firm service, or by reserving and paying for firm service. We have not 
included any degrees of firmness in the Final Rule pro forma tariff 
because having intermediate categories of firmness under point-to-point 
or network service would, we believe, unnecessarily complicate the 
priority system. However, utilities are free to propose and fully 
support different reservation priority provisions for firm service in 
subsequent rate filings as long as those provisions are not unduly 
discriminatory, fully comply with the principles of comparability, and 
are priced appropriately.
c. Reservation Priorities for Non-Firm Service
Comments
    IOUs, state commissions, and potential network customers tend to 
support the service reservation priorities for non-firm service set 
forth in the NOPR pro forma tariffs (i.e., transmission service by 
network customers for economy purchases to serve network load has a 
higher priority than non-firm point-to-point service, which has a 
higher priority than a firm point-to-point customer using transmission 
service at secondary points of receipt and delivery). However, because 
network customers pay a higher rate than point-to-point customers, 
these commenters argue that network customers should be permitted to 
use their off-peak load ratio share of the transmission system to make 
off-system sales. Many commenters argue that point-to-point customers 
can use their secondary service for both purchases and sales; thus, 
they believe it is discriminatory to limit network customers to 
purchases at secondary points.
    Commenters that are opposed to the service reservation priority 
scheme in the NOPR pro forma tariffs argue that transmission providers 
will discriminate against third party users in favor of their native 
load economy purchases. These commenters argue that all non-firm 
service should have equal priority.
    Other commenters, such as CINergy, would base priority on the 
duration of service. CINergy claims that this method would eliminate 
what it claims is an advantage (over network) given in the NOPR to 
point-to-point service in making short-term purchases. TVA notes that 
it establishes priority for non-firm service based on duration of 
service requested, with customers in each service category receiving 
priorities based on the rate they wish to pay.
    Some commenters believe that the transmission price should affect 
the

[[Page 21606]]

priority of customers to obtain non-firm transmission capacity.<SUP>458 
However, other commenters argue that this seems to be precluded by the 
NOPR pro forma tariffs' service priority provisions.
---------------------------------------------------------------------------

    \458\ E.g., Duke, Orange & Rockland.
---------------------------------------------------------------------------

    Although PSE&G believes that the NOPR pro forma tariffs suggest a 
first-come, first-served allocation method for capacity in excess of 
that needed for firm transmission service, it proposes a fixed period 
of time for all potential users to submit bids for service (e.g., one 
week prior for monthly service), allowing the bid price to determine 
priority (i.e., the higher bid prices receive service priority over 
lower bid prices). According to PSE&G, customers could bid an ``up to'' 
rate subject to a price floor, with all revenues flowed back to firm 
service customers. TVA also advocates departing from the first-come, 
first-served approach for allocating some uses of the transmission 
system, claiming that price is an effective means to establish priority 
for non-firm and short-term firm services.
    Utility Wind Interest Group requests that non-firm service used for 
transmitting renewable resources be given a higher priority than non-
firm service used for transmitting conventional resources because 
renewable resources cannot store their fuel supply.
Commission Conclusion
    We continue to believe that network economy purchases should have a 
reservation priority over non-firm point-to-point and secondary point-
to-point uses of the transmission system. Network transmission 
customers are obliged to pay all of the costs of the transmission 
system without regard to the resources from which energy is scheduled. 
Therefore, it is appropriate that the transmission associated with a 
network customer's economy purchases (i.e., transmission that is used 
to substitute one resource for another on an as-available basis) enjoys 
a higher priority than non-firm point-to-point transmission service.
    Regarding the reservation priority for non-firm service under 
point-to-point service, we will adopt a reservation priority based upon 
duration of non-firm service, with price acting as a tie-breaker for 
competing service requests of an equal duration. If there is 
insufficient transmission capacity to accommodate all non-firm 
transmission requests, the reservation of longer duration should 
displace the shorter. For example, a reservation for a month of non-
firm service will displace a reservation for a week of non-firm 
service. Also, a reservation for a week will displace a reservation for 
a day, which will displace a reservation for an hour of non-firm 
service. If a customer requests non-firm and later another customer 
requests longer-term non-firm service before either term of service 
begins, the first customer to request service has the right of first 
refusal to change its request to the longer term of service. A firm 
point-to-point customer's use of transmission service at secondary 
points of receipt and delivery will continue to have the lowest 
reservation priority.
3. Curtailment Provisions
a. Pro-Rata Curtailment Provisions
Comments
    A large number of IOUs that are control area operators argue for 
discretion to curtail the transaction that most effectively relieves 
the constraint, in lieu of mandatory pro-rata curtailments, which they 
argue are inappropriate and not cost effective.
    Other commenters that do not support pro-rata curtailment argue 
that preference should be given to native load or existing customers 
because these customers have paid the majority of the costs of the 
transmission system. A large number of customers note that their 
existing contracts contain ``enhanced'' curtailment priorities (i.e., 
service to others will be curtailed before service to customers with 
such curtailment priority) due to the large capital outlays made by 
them in connection with their service.\459\
---------------------------------------------------------------------------

    \459\ E.g., TANC, Turlock, SMUD.
---------------------------------------------------------------------------

    Public Generating Pool believes that the proposed curtailment 
provisions may not be flexible enough for transactions in the 
Northwest. It argues that hydro spill should be avoided, and suggests 
that transactions from federal and/or non-federal hydroelectric 
generation facilities should not be curtailed pro rata with other 
transactions that do not rely on such facilities. Public Generating 
Pool urges that regional agreements (e.g., regional transmission group 
agreements) that would achieve this goal should be given deference.
    Other commenters support pro-rata curtailments for firm 
service.<SUP>460 PSNM states that this has been its operating practice 
in the past, and PSNM expects to continue such an approach in the 
future.
---------------------------------------------------------------------------

    \460\ E.g., PSNM and Nebraska Public Power District.
---------------------------------------------------------------------------

    Power marketer commenters generally support the pro-rata 
curtailment adding that a standardized curtailment priority applied 
nationally would provide greater open access and eliminate 
discriminatory curtailments.
    Commenting on a related subject, EEI maintains that the network 
tariff provision for termination of service in the event a customer 
fails to curtail load <SUP>461 may not be realistic for service to a 
Transmission Dependent Utility. EEI suggests that the Commission 
supplement this provision with a substantial penalty provision, coupled 
with an indemnification requirement.
---------------------------------------------------------------------------

    \461\ Proposed Pro Forma Network tariff section 9.7--System 
Reliability.
---------------------------------------------------------------------------

Commission Conclusion
    It was not our intent in the NOPR to require all transactions to be 
curtailed on a pro-rata basis regardless of whether the transaction 
relieves a constraint. We intended to permit curtailments of 
transactions that substantially relieve a constraint.<SUP>462 We 
intended and continue to believe that curtailment on a pro-rata basis 
is appropriate for curtailing the transactions that substantially 
relieve the constraint. In order to allay the concerns of the 
commenters addressing this issue, we are clarifying the curtailment 
provision of the tariff to explicitly allow the transmission provider 
discretion to curtail the services, whether firm or non-firm, that 
substantially relieve the constraint. Of course, any curtailment must 
be made on a non-discriminatory basis, including curtailment of the 
transmission provider's own use of the transmission system. Customers 
that believe the curtailment policy is administered unfairly may file a 
section 206 complaint at the Commission.
---------------------------------------------------------------------------

    \462\ The Final Rule pro forma tariff contains language allowing 
the transmission provider the discretion to interrupt firm 
transmission service in an emergency or other unforeseen condition 
in a manner suggested by these commenters. Section 11.6, Curtailment 
of Firm Service, of the Final Rule pro forma tariff provides:
    However, the Transmission Provider reserves the right to 
interrupt, in whole or in part, firm Transmission Service provided 
under this Tariff when, in the Transmission Provider's sole 
discretion, an emergency or other unforeseen condition impairs or 
degrades the reliability of its transmission system.
    The reference to curtailments being allocated on a proportional 
(pro rata) basis addresses situations where multiple transactions 
could be curtailed to relieve a constraint.
---------------------------------------------------------------------------

    Concerning the request of certain Pacific Northwest commenters, we 
would consider granting deference to an alternative curtailment method 
to avoid hydro spill if such a regional practice is generally accepted 
and adhered to across the region, as discussed further in Section IV.K.
    Finally, we agree with EEI's observation that terminating network

[[Page 21607]]

service under the tariff to a transmission dependent utility that fails 
to curtail load as required may not be appropriate. As a result, we 
clarify that under network and point-to-point service, the transmission 
provider may propose a rate treatment (penalty provision) to apply in 
the event a customer fails to curtail load as required under the Final 
Rule pro forma tariff. Such proposals will be evaluated on a case-by-
case basis on compliance.
b. Curtailment Provisions for Non-Firm Service
Comments
    A number of commenters seek clarification of the curtailment 
provision for non-firm service under the two tariffs. They note that 
economy purchases by the network customer are accorded a higher 
curtailment priority than non-firm service under the point-to-point 
tariff. However, under the point-to-point tariff there is no 
acknowledgement of this higher priority for network service. 
Curtailments for non-firm transmission service under the point-to-point 
tariff are simply based upon duration of service, without reference to 
a higher priority for network economy purchases.
    A number of commenters, including Industrial Energy Applications, 
suggest that a price-based curtailment queue for non-firm transmission 
will facilitate economy energy deals in highly competitive wholesale 
power supply markets and allow the parties to directly address delivery 
risk through the pricing mechanism.
    Blue Ridge argues that the final rule should provide equal 
curtailment priority for all types of non-firm transmission service. 
Utilities For Improved Transition argues that network customers should 
be able to transmit non-firm power imports under the network tariff 
with the same curtailment priority that is assigned to all other firm 
network uses of the transmission system.
    A number of commenters note that the tariffs allow non-firm service 
to be interrupted only for emergency or reliability reasons or to 
provide firm service. These commenters contend that, under this 
requirement, curtailment of non-firm service is unlikely.<SUP>463 As a 
result, they believe that non-firm service is elevated to firm service. 
To remedy this situation, these commenters argue that transmission 
providers should have the ability to curtail non-firm service for any 
economic reason.
---------------------------------------------------------------------------

    \463\ E.g., Florida Power & Light Company, Southern California 
Edison Company.
---------------------------------------------------------------------------

Commission Conclusion
    We have clarified in the Final Rule pro forma tariff that a network 
customer's economy purchases have a higher curtailment priority than 
non-firm point-to-point transmission service.
    A higher curtailment priority should be provided to network economy 
energy purchases for the reasons stated in AES Power, Inc..<SUP>464 In 
that case, we recognized that the network transmission customer has 
already ``paid'' for the transmission of its economy purchases (i.e., 
transmission that is used to substitute one resource for another on an 
as available basis) through its payment of a load ratio share of the 
system.
---------------------------------------------------------------------------

    \464\ 69 FERC para. 61,145 at 62,300 (1994) (proposed order), 74 
FERC para. 61,220 (1996) (final order).
---------------------------------------------------------------------------

    Many commenters oppose the point-to-point service provision 
allowing non-firm service to be interrupted only for emergency or 
reliability reasons or to provide firm service. Upon further 
consideration, we agree that this provision is too narrow. Accordingly, 
the Final Rule pro forma tariff is revised to allow the transmission 
provider to curtail non-firm service for reliability reasons or 
economic reasons (i.e., in order to accommodate (1) a request for firm 
transmission service, (2) a request for non-firm service of greater 
duration, (3) a request for non-firm transmission service of equal 
duration with a higher price, or (4) transmission service for economy 
purchases by network customers from non-designated resources.). 
However, all curtailments must continue to be made on a non-
discriminatory basis including curtailments of the transmission 
provider's own non-firm uses of the transmission system under the 
tariff. A firm point-to-point customer's use of transmission service at 
secondary points of receipt and delivery will continue to have the 
lowest curtailment priority.
4. Specific Tariff Provisions
a. Network and Point-to-Point Customers' Uses of the System
Comments
    Generally, transmission providers argue that the tariffs give too 
much flexibility to customers, while transmission customers argue that 
even more flexibility is required. The arguments are generally tied to 
pricing rather than technical problems with providing any level of 
service.
    A common transmission provider argument is that the proposed firm 
point-to-point tariff provides a premium service comparable to network 
service, but at a lower rate. It has been suggested that either the 
flexibility to use non-firm service at secondary points of receipt and/
or delivery at no additional charge under the point-to-point tariff be 
eliminated or that point-to-point customers should pay a premium price 
for such flexibility.<SUP>465 Transmission providers generally argue 
that flexible point-to-point service puts the transmission owner and 
the network customer at a competitive disadvantage. They assert that 
the point-to-point customer is able to use non-firm transmission to 
reach secondary receipt and delivery points for both sales and 
purchases, but the network customer may use only non-firm transmission 
to reach secondary points for purchases. Thus, they argue, the flexible 
point-to-point users can sell non-firm power with a small or even no 
transmission component (because the underlying transmission is 
effectively free). Electric Consumers Alliance and Cajun believe that 
the owner and network customer competing for that sale should not be 
charged for the identical transaction. Absent a change to the point-to-
point tariff, a number of transmission providers and state commissions 
(including Midwest Commissions) argue that to provide balance to the 
tariffs, the network tariff should permit the network customers to have 
non-firm transmission to secondary receipt and delivery points at no 
additional charge for both purchases and sales within its load-ratio 
transmission entitlement. Utilities For Improved Transition refers to 
this proposed network tariff modification as ``headroom.''
---------------------------------------------------------------------------

    \465\ E.g., EEI, Utility Working Group, SoCal Edison.
---------------------------------------------------------------------------

    CCEM opposes the headroom concept, arguing that ``free'' use of 
capacity will give transmission providers an unfair competitive 
advantage. CCEM also cites Order No. 636 in support of its position.
    Conversely, a number of customer groups believe the point-to-point 
tariff should be made more flexible by broadly defining the concept of 
points of receipt and delivery. They argue that all points of 
connection between the transmitting utility and the purchasing utility 
should be treated as a single point of delivery (POD) or point of 
receipt (POR).<SUP>466 In this manner, a customer would not have to pay 
for every point of receipt or point of delivery, but could select a 
contract demand level of service. The customer could then use the 
service at multiple

[[Page 21608]]

points without incurring separate reservation charges for each point.
---------------------------------------------------------------------------

    \466\ E.g., Arkansas Cities, NRECA.
---------------------------------------------------------------------------

    A number of commenters contend that the Commission should not force 
specific tariffs on public utilities in the Pacific Northwest due to 
their unique status.<SUP>467 In particular, NWRTA recommends that the 
final rule recognize that the Pacific Northwest's integrated 
transmission system, including large components owned by non-public 
utilities, was constructed to support a unique region-wide 
hydroelectric-dependent generating system. NWRTA recommends that the 
final rule be sufficiently flexible to accommodate these unique 
characteristics without prejudicing the interests of users or providers 
of transmission services.
---------------------------------------------------------------------------

    \467\ E.g., Public Power Council, Washington Water Power, NWRTA.
---------------------------------------------------------------------------

    Similarly, Public Generating Pool states that the NOPR pro forma 
network tariff departs from the status quo arrangements in the 
Northwest and is generally unworkable because generation is usually 
remote from the control area serving the network load and because BPA, 
which does not have a typical service territory, dominates the regional 
transmission market. Public Generating Pool suggests that the 
Commission require, and the region develop, a ``generation 
integration'' transmission tariff that would offer network-type service 
to a source or sources of generation unbundled from the ``network 
services'' designed to integrate load. Similar contract demand network 
tariffs have already been proposed by some IOUs.
Commission Conclusion
    We will not allow network customers to make off-system sales within 
the load-ratio transmission entitlement at no additional charge. 
Commenters have raised no new arguments to persuade us to do so. The 
primary purpose of network service is to integrate resources to serve 
loads. Use of transmission by network customers for non-firm economy 
purchases, which are used to displace firm network resources, must be 
accorded a higher priority than non-firm point-to-point service and 
secondary point-to-point service under the tariff. Off-system sales 
transactions, which are sales other than those to serve a network 
customer's native load, must be made using point-to-point service. They 
can be made on either a firm or non-firm basis.
    A large number of transmission providers support the ``headroom'' 
concept, arguing that without it the flexible point-to-point service 
puts them at a competitive disadvantage. This would be true if a 
utility serving load were required to use network service exclusively. 
However, we do not require any utility to take network service to 
integrate resources and loads. If any transmission user (including the 
public utility) prefers to take flexible point-to-point 
service,<SUP>468 they are free to do so. Any point-to-point customer 
may take advantage of the secondary, non-firm flexibility provided 
under point-to-point service equally, on an as-available basis.
---------------------------------------------------------------------------

    \468\ See Florida Municipal Power Agency v. Florida Power & 
Light Company, 74 FERC para. 61,006 at 61,013 and n.70 (1996).
---------------------------------------------------------------------------

b. Minimum and Maximum Service Periods
Comments
    Commenters raise issues regarding the minimum term of one hour for 
firm point-to-point service. Their concerns center on price and 
priority. Transmission providers point out that their native load 
customers pay the fixed cost of the transmission system every hour of 
the year. They argue that comparability is not achieved by permitting 
others to have service for one hour with equal priority to native load 
and other long-term customers. Others worry that the one-hour minimum 
term will: (1) Promote the selective use of the transmission system; 
(2) impair the ability of a utility to plan its system; and (3) 
adversely impact longer term transactions.
    Tallahassee and KY Com are concerned that one-hour firm service may 
encourage speculative advance requests for service during the system 
peak day (Cajun refers to this as cream skimming). These commenters 
express concern that such requests could displace other valid 
transactions or constrain a corridor or interface to the detriment of 
network service or native load customers. Tallahassee proposes a one-
day minimum term for firm service.<SUP>469
---------------------------------------------------------------------------

    \469\ See also VEPCO, CSW, NYSEG, WP&L.
---------------------------------------------------------------------------

    East Kentucky is concerned that users of the transmission system 
could, under the Commission's proposed open-access rule, purchase 
short-term firm service during peak months in lieu of annual firm 
service to reduce expenses associated with the purchase of firm 
transmission service. By buying short-term firm service only during the 
peak months, an entity can significantly reduce its transmission 
expenses by purchasing non-firm service during off-peak months when the 
available transmission capacity far exceeds the demand on the 
transmission system. For this reason, some commenters request that 
short-term firm service be priced to generate revenues over the peak 
months equal to the charge for annual firm service.
    Duke argues that, because all curtailments are equal, the addition 
of each one hour firm transaction will lower the reliability profile of 
native load customers and other customers with long-term commitments. 
It suggests that different classes of services be established that 
offer transmission customers the flexibility to obtain an intermediate 
level of transmission service (between native load firm and non-firm) 
for transactions of shorter duration.
    On the other hand, some TDUs and power marketers support the one-
hour minimum term. TAPS argues that transmission providers should not 
be permitted to restrict the availability of hourly, daily or weekly 
transmission service at reasonable prices, as some transmission 
providers have proposed in open access cases. Brazos supports a minimum 
duration of service equal to the minimum scheduling period of the 
transmission owner. Turning to the maximum term of service, Chugach 
objects to the imprecise requirement that transmission service be 
offered for a term equal to the life of a particular generation 
resource. Chugach, joined by VEPCO, suggests that the Commission 
require transmitting utilities to offer five-year terms (with longer 
contract terms by negotiated agreement).
    Although BPA supports eliminating arbitrary term limitations and 
facilitating long-term resource commitments, it is concerned that the 
Commission's failure to specify a maximum term for firm transmission 
service (particularly where no specific resource is being wheeled) 
requires transmitting utilities to effectively sell off their 
transmission capacity to third parties. In BPA's view, such a 
requirement goes well beyond the intent of the Energy Policy Act.
    PSE&G argues that the term limit for firm transmission service 
should be consistent with the transmission provider's planning horizon 
(e.g., for PSE&G, 10 years), which will ensure comparability of firm 
third party customers with native load. According to ConEd, failure to 
specify a maximum term for service creates uncertainty for planning 
purposes. PECO believes that utilities should have the right to limit 
the term of service to either: (1) The expected useful life of 
facilities used in providing service; or (2) the term of permits and 
land rights needed for those facilities.

[[Page 21609]]

Commission Conclusion
    We will adopt a one-day minimum term for firm point-to-point 
service. The one-day minimum term for firm point-to-point service, 
along with modifications to the procedures for requesting firm point-
to-point service, will moot a number of reliability concerns and 
allegations about possible ``cream-skimming.'' As discussed supra, firm 
service requests with longer durations of service will have bumping 
rights over shorter term firm service requests. Also, the one-day 
minimum will not disadvantage anyone because the transmission provider 
will be subject to the same one-day term for its firm point-to-point 
uses of the transmission system. Because of the longer-term nature of 
network service, it will be subject to a one-year minimum term.
    We will not specify a maximum term for either point-to-point or 
network transmission service. However, we recognize the concerns raised 
by commenters that a commitment of uncertain duration makes planning 
difficult. Therefore, we will modify the tariff to require that an 
application for transmission service specify the length of service 
being requested. This will provide the transmission provider with the 
certainty it needs for planning and the transmission customer with the 
flexibility to request the service it needs.
c. Amount of Designated Network Resources
Comments
    The NOPR pro forma network tariff specifies that a customer may 
designate only those resources that the customer owns or has committed 
to purchase pursuant to an executed contract. Transmission providers 
argue that there is a need for some limitation on the resources that 
network customers can designate to serve their loads. Otherwise, they 
assert, a utility would be required to incur costs (planning, 
constructing, and operating its transmission system) that are out of 
proportion to the customer's load and its share of the utility's cost 
of service. However, EEI, VEPCO, and Utilities For Improved Transition 
believe that the Commission's proposal to use a purchase obligation 
standard is too narrow, inflexible, and susceptible to manipulation. 
These IOU commenters argue that it could include very short-term 
obligations and contingent obligations to purchase. EEI suggests that 
the Commission should establish a minimum term so that a customer could 
not designate resources for which it has only a one-month contract. The 
principal problem VEPCO sees is that purchase obligations may not be 
clear. According to VEPCO, a transmission customer may claim an 
obligation when it has no substantial payment obligation and thus no 
economic deterrent to designating that purchase obligation as a 
potential resource to serve its loads. It alleges that the result is 
that the transmitting utility can be forced to tie up transmission 
capacity for service from a resource that may have little probability 
of being used; consequently, less capacity will be available for other 
uses. VEPCO further argues that, since upgrade costs are typically 
rolled in, the customer may not have a strong incentive to minimize 
transmission construction. EEI argues for system-specific limits based 
on capacity needs to serve the network loads reliably. Alternatively, 
if the ``own'' or ``purchase'' provision is to be used, EEI contends 
that the customer should be required to have a significant and ongoing 
obligation to purchase power (e.g., minimum one-year contracts that 
impose obligations on a first-call basis).
    These IOUs also recommend that the Commission not decide on a 
single way to limit network resources. They note that proposals based 
on percentage limits (e.g., 125%) subject to exceptions for reliability 
concerns may be a reasonable approach. According to these IOUs, the 
Commission should permit flexibility to develop not unduly 
discriminatory provisions until experience suggests which are the best 
ways to satisfy the objective. To prevent over-designating network 
resources, Missouri-Kansas Industrials suggest placing a limit of 200% 
of the subscriber's load.
    Arkansas Cities supports limiting the definition of network 
resources to those that the customer owns or contracts for. It argues 
that this reasonably accommodates the planning process. Arkansas Cities 
argues that any type of percentage adder would unreasonably restrict 
the process.
    ELCON states that virtually any issue regarding the nature of 
network service can be resolved by reference to the price of such 
service. According to ELCON, if a transmission customer seeks to 
incorporate unlimited (i.e., unspecified) generation sources into its 
network load, the customer should pay a higher rate than a network 
customer that can identify a need for service to/from specified 
generating units.
    A related issue is how interface capacity should be allocated 
between network customers and the transmission provider. IOUs generally 
argue that interface capacity should be allocated based upon the load 
ratio of the customers. Tariff customers generally argue that there 
should be no restriction on the amount of interface capacity that they 
may designate.
Commission Conclusion
    We do not believe that a superior alternative has been suggested to 
our purchase obligation for limiting network resources. Accordingly, we 
will not change the limitation on the amount of resources a network 
customer may designate. A transmission provider taking network service 
to serve network load under the tariff also is required to designate 
its resources and is subject to the same limitations required of any 
other network customer.
    Limiting the amount of resources to those that the customer owns or 
commits to purchase will protect a utility from having to incur costs 
that are out of proportion to the customer's load. The transmission 
provider's concern that the purchase limitation will result in 
excessive network resources is unfounded. A transmission customer, like 
a transmission provider, has an incentive not to oversubscribe its 
capacity requirements because the cost of excessive reserve margins 
will be prohibitive. Requiring a strict percentage limitation could 
distort the planning process by limiting the size of resource additions 
a transmission customer may undertake. Allowing discretionary 
exceptions to the percentage limit will inevitably lead to disputes and 
claims of discrimination.
    With respect to the allocation of interface capacity under network 
service, we clarify that a customer is not limited to a load ratio 
percentage of available transmission capacity at every interface. A 
customer may designate a single interface or any combination of 
interface capacity to serve its entire load, provided that the 
designation does not exceed its total load.
d. Eligibility Requirements
    Under the NOPR pro forma tariffs, the transmission provider and 
anyone who can file a section 211 request is eligible to request 
service.
Comments
    In general, most commenters agree with the eligibility 
requirements. However, several IOUs argue that the tariffs should be 
modified specifically to preclude the use of the tariffs for retail 
wheeling.<SUP>470
---------------------------------------------------------------------------

    \470\ E.g., El Paso, Southern, NSP.
---------------------------------------------------------------------------

    NIEP believes the eligibility provision should include all entities 
that not only generate power themselves, but also purchase power 
generated by others for

[[Page 21610]]

resale, including municipalities, federal entities with rights to 
purchase, and other entities with load but no generation resources.
    Power Marketing Association and others argue that the network 
tariff should be modified to specifically allow service to marketers.
    PacifiCorp argues that independent owners of generation resources 
should not be allowed to acquire network integration service directly. 
It suggests that, if the eligible utility does not have a load in the 
control area, the service sought is to accommodate off-system sales, 
which is a point-to-point service.
Commission Conclusion
    As we previously explained, a non-discriminatory open access 
transmission tariff must be made available, at a minimum, to any entity 
that can request transmission services under section 211 and to foreign 
entities.<SUP>471 Eligibility to take service is further discussed in 
Section IV.C.1.
---------------------------------------------------------------------------

    \471\ See discussion in Section IV.C.1.
---------------------------------------------------------------------------

e. Two-Year Notice of Termination Provision
Comments
    Ohio Edison, Utilities For Improved Transition, LA DWP, and VEPCO 
believe that point-to-point transmission customers should not be 
allowed to terminate transmission service prior to the end of their 
contract term, especially in light of their reassignment rights. For 
network service, VEPCO, Florida Power Corp, Utilities For Improved 
Transition, and Duke believe that the notice of termination period 
should be at least five years, to coincide with the utility's 
construction horizon. In particular, VEPCO wants transmission customers 
terminating service prior to the end of the contract term to pay for 
network upgrades constructed for their benefit that would be stranded 
due to early termination of service.
    CCEM supports a six-month notice of termination as appropriate for 
a term of service of one year or greater; any longer notice period 
would unduly limit a transmission customer's purchasing options.
    NYSEG and EEI want the flexibility to negotiate a reasonable, 
mutually agreeable notice of termination period to recognize such 
things as the term of the contract and the amount of service at issue.
    LEPA, VT DPS, and NorAm believe that written notice of termination 
should not be required for transactions of two years or less.
Commission Conclusion
    We will delete the notice of termination provision from the tariff. 
We believe that commenters have raised a number of valid concerns about 
including the notice of termination provision. In particular, the 
notice of termination will have no effect on short-term service of less 
than two years. In addition, the two-year notice provision does not 
coincide with either a transmission provider's planning or construction 
horizon. Because we are eliminating the notice of termination provision 
from the tariff, transmission service will have to be reserved and paid 
for over the length of the contract term. Of course, by eliminating 
this tariff provision, we are not precluding parties from negotiating 
mutually agreeable terms for early termination on a case-specific 
basis. However, we note that point-to-point customers are able, under 
the reassignment provision, to resell unused transmission capacity.
f. Reciprocity Provision
    In the NOPR, the Commission explained that it was requiring a 
reciprocity provision in the non-discriminatory open access 
transmission tariffs so that public utilities offering transmission 
access to others would be able to receive service from transmitting 
utilities that are not public utilities (e.g., municipal power 
authorities and federal power marketing administrations that receive 
service under a public utility's tariff).
Comments
Reciprocity Requirement
    The vast majority of the jurisdictional IOUs commenting on this 
issue favor a reciprocity requirement. In contrast, the non-
jurisdictional transmission customers (primarily publicly-owned 
entities and cooperatives) generally oppose such a requirement. The few 
state commissions commenting on this issue generally support the stated 
goal of the reciprocity requirement, but question our legal authority 
to require it.<SUP>472 The few IPP and power marketer commenters that 
address this issue do not object to reciprocity if it does not apply to 
non-transmission owners.<SUP>473
---------------------------------------------------------------------------

    \472\ E.g., IL Com, KY Com, VT DPS, GA Com.
    \473\ E.g., CCEM, CA Energy Co.
---------------------------------------------------------------------------

    Several commenters believe that all transmission-owning utilities, 
whether public or investor-owned, must be required to provide open 
access service for a truly competitive wholesale power market to be 
realized.<SUP>474 Sierra states that specific legislation by Congress 
and/or state lawmakers may be necessary to ensure that currently non-
public utilities comply with the Commission's open access requirements.
---------------------------------------------------------------------------

    \474\ E.g., Sierra, MidAmerican, Tucson Power.
---------------------------------------------------------------------------

    A number of commenters maintain that the Commission should enforce 
reciprocity by allowing public utilities to deny transmission service 
to non-public utility transmitting entities when reciprocal 
transmission service is not offered.<SUP>475
---------------------------------------------------------------------------

    \475\ E.g., Puget, Sierra, NSP.
---------------------------------------------------------------------------

    Phelps Dodge and Otter Tail believe that non-public utility 
transmitting entities will continue their existing bundled service 
contracts indefinitely to avoid complying with the reciprocity 
requirement. Therefore, to promote transmission access through 
reciprocity, Phelps Dodge and Otter Tail suggest requiring the 
unbundling of existing contracts by a date certain to convert such 
contracts to transmission service agreements under the transmission 
provider's open access tariff.
    A number of commenters argue that the Commission's only legal 
authority to impose a reciprocity requirement on non-public utilities 
is that provided by section 211 of the FPA.<SUP>476 Large Public Power 
and others suggest that mandating reciprocity is not necessary because 
the stated goals of the reciprocity requirement can be met by voluntary 
transmission access and through section 211 filings.
---------------------------------------------------------------------------

    \476\ E.g., NRECA, Omaha Public Power District, Dairyland, AEC & 
SMEPA, PA Com, IL Com, TDU Systems.
---------------------------------------------------------------------------

    Many commenters do not oppose reciprocity if it is modified to 
incorporate the protections present in sections 211 and 212 and the 
benefits available under sections 205 and 206.<SUP>477 TDU Systems 
explains that section 211 contains a number of protections, e.g., 
transmitting utilities cannot be required to provide transmission 
service if such service impairs their ability to provide reliable 
service, disrupts existing contracts with entities seeking service, or 
is inconsistent with state law regarding retail marketing areas. It 
also notes that section 212 contains rate provisions that protect a 
non-public utility transmission provider from being forced to provide 
electric service at a non-compensatory rate. Seminole EC argues that, 
without section 205/206 rights, non-public utilities cannot adjust 
their tariffs or challenge tariff provisions that they believe should 
not apply to them.
---------------------------------------------------------------------------

    \477\ E.g., NRECA, SC Public Service Authority, Seminole EC, TDU 
Systems.
---------------------------------------------------------------------------

    Several commenters also suggest that, without sections 211, 212, 
and 205 rights and protections, reciprocity

[[Page 21611]]

provisions allow the transmission provider to deny transmission based 
on its own determination of the transmission customer's attempt to 
comply with reciprocity, which SC Public Service Authority contends is 
letting the ``fox guard the henhouse.'' TAPS states that in no event 
should the claimed lack of reciprocity constitute grounds for refusal 
to offer a service agreement, or unilateral denial, delay or 
termination of service. TAPS, and other cooperative, municipal, and 
public power commenters suggest that some procedure must be developed 
to bring reciprocity disputes before the Commission. Wisconsin 
Municipals argues that this provision should be modified, claiming that 
a customer's receipt of a revenue credit for transmission facilities it 
contributes to the transmission provider's system should satisfy the 
reciprocity requirement.
    Rather than filing tariffs with the Commission, Dairyland suggests 
allowing cooperatives that are not public utilities to file a 
compliance transmission tariff with the Rural Utilities Service (RUS) 
as it relates to the issue of reciprocity, thereby affording non-
jurisdictional cooperative utilities rights and privileges similar to 
those afforded jurisdictional utilities.
Application of Reciprocity Requirement
    Several commenters argue that reciprocity should apply to both the 
seller and purchaser engaged in a transaction under an open access 
tariff to ensure that: (1) Transmission customers cannot avoid their 
reciprocity obligation by requesting service through an agent that owns 
no transmission facilities; (2) a generator cannot take transmission 
service in order to sell power to a non-jurisdictional entity, thereby 
allowing the non-jurisdictional entity to escape the reciprocity 
provision, and (3) a buyer cannot take service in order to purchase 
power from a non-jurisdictional entity, thereby allowing the entity to 
escape the reciprocity requirement. <SUP>478
---------------------------------------------------------------------------

    \478\ E.g., EEI, Consumers Power, Montana-Dakota Utilities, CSW, 
Duke, BPA.
---------------------------------------------------------------------------

    Entergy also is concerned that reciprocity can be evaded through 
the use of power marketers. Therefore, Entergy proposes that, if the 
transmission customer is neither the producer, transmitter, nor 
distributor of the power and energy to be transmitted, but instead acts 
as a marketer, the marketer must designate an electric utility that 
either produces, transmits, or distributes such power and energy as 
being subject to the requirement to provide comparable service.
    CCEM and NIEP support the reciprocity provision because they apply 
only to transmission owners. CCEM and NIEP contend that non-
transmission-owning customers should not be required to procure 
transmission capacity or hire a proxy solely to meet a reciprocity 
requirement.
    In contrast, CA Energy Co insists that the reciprocity provisions 
of the proposed tariffs must be amended to clarify that IPPs can obtain 
access even if the IPPs own no transmission assets. CA Energy Co argues 
that the Commission must exempt IPPs from the reciprocity requirement 
if IPPs are to be assured equal access and thus remain effective 
competitors.
Publicly-Owned Entities
    Publicly-owned entities argue that they differ from IOUs and cannot 
provide completely reciprocal services. <SUP>479 LPPC identifies a 
number of differences between publicly-owned utilities and IOUs, such 
as: the publicly-owned utilities' use of tax-exempt debt, which could 
be jeopardized if they are required to make their transmission systems 
available for private use; restrictions on the rate-setting methods 
publicly-owned utilities can use; and statutory restrictions on the 
services publicly-owned utilities can offer. <SUP>480 LPPC asks that 
the reciprocity provision be dropped or changed to recognize these 
differences. <SUP>481 It argues that the purposes of the NOPR are met 
by transmission tariffs voluntarily offered by its members that 
generally meet the standard of open access.
---------------------------------------------------------------------------

    \479\ E.g., Blue Ridge, SMUD, LPPC, Salt River, Oglethorpe.
    \480\ See also Omaha PPD, Salt River, MEAG, TAPS.
    \481\ See also Omaha PPD.
---------------------------------------------------------------------------

    NE Public Power District notes that to the extent that the 
Commission requires cost-based rates, the Commission must recognize 
that publicly-owned utilities do not establish rates in the same manner 
as IOUs; for example, NE Public Power District does not include 
depreciation or return on equity as costs in its rates, nor does it pay 
federal income taxes. It suggests that the Commission should not apply 
a one-size-fits-all approach to pricing transmission service, should 
consider the special circumstances of publicly-owned utilities in 
exercising its authority under section 212, and should give publicly-
owned utilities the opportunity for an evidentiary hearing before 
requiring them to adopt rate-setting conventions that are appropriate 
for public utilities.<SUP>482
---------------------------------------------------------------------------

    \482\ See also Heartland.
---------------------------------------------------------------------------

    CAMU asserts that the tax-exempt financing of government bodies may 
be jeopardized due to limitations on the private use of facilities that 
are financed through tax exempt bonds.<SUP>483 It suggests that a 
solution may be to impute the cost of capital based on the average cost 
of all area utilities. Wisconsin Municipals says that the Commission 
should seek an opinion from the IRS regarding whether reciprocal use 
would jeopardize tax-exempt status; if it is determined it would, the 
owner of the transmission facilities should be allowed to recover any 
increased costs associated with the loss of tax-exempt status.<SUP>484
---------------------------------------------------------------------------

    \483\ See also Wisconsin Municipals, Omaha PPD, Salt River, 
MEAG, MMEWC, NE Public Power District.
    \484\ See also TAPS.
---------------------------------------------------------------------------

    DE Muni is concerned that a utility may ``impose'' the open access 
tariffs on a non-public utility customer such as a municipal system and 
then demand reciprocal access to that customer's transmission 
facilities to serve the municipal's retail customers.
    San Francisco argues that there is no legal authority in the FPA or 
case law to impose the open access requirement on non-public utility 
entities. Moreover, San Francisco is concerned that the reciprocity 
requirement may impair its ability to deliver its own power pursuant to 
the requirements of the Raker Act.
    Salt River opposes the reciprocity provision because it could 
``administratively vest discriminatory market power in FERC 
jurisdictional public utilities.'' Salt River further argues that 
``duly adopted open access transmission tariffs or rate schedules of 
publicly-owned utilities should be presumed to satisfy FERC's 
reciprocity requirement, and the legislative action of the publicly-
owned utility's ratemaking body should be given deference in a dispute 
brought before FERC relating to the tariff or rate schedule.''
    Public Generating Pool argues that a non-public utility 
transmission customer should not have to provide the same service a 
public utility provides. It argues that a publicly-owned entity may 
lack the resources to provide the high level of service a public 
utility can provide.
    Tallahassee seeks clarification that reciprocity does not mean that 
investor-owned utilities can require municipal utilities to offer 
services that are identical to those offered by the

[[Page 21612]]

investor-owned utilities. It argues that it is not practical to require 
small utilities to provide all of the services bigger utilities provide 
and that legal obligations imposed on municipal utilities may interfere 
with their ability to provide certain types of open access provisions. 
Tallahassee concludes that reciprocity should be equated with 
comparability (the transmission user must offer service that is 
comparable to the service it offers to itself).
    TANC asks for clarification and suggests various changes to the 
reciprocity provision. It asks whether the reciprocity requirement will 
apply to it, since it is part owner of a transmission facility (the 
California Oregon Transmission Project (COTP)) but has contractually 
dedicated its entitlement to use of this facility to its members. It 
argues that if the requirement does apply, its obligation should be 
limited to the member's share of TANC's entitlement. TANC also asks 
whether when it receives transmission service on behalf of a member, 
that member's non-COTP transmission facilities must be made available 
to the transmission provider. If that is the case, TANC asks what 
voltage level of facilities must TANC and its members make available? 
TANC believes that if a TANC member independently requests transmission 
service from a utility, that member would be obligated to make 
reciprocal service available to the utility on the share of the COTP 
that member ``controls'' through TANC's entitlement. TANC argues that 
neither TANC and its members nor TANC and its COTP co-owners should be 
treated as ``affiliates'' under the proposed reciprocity provision. It 
argues that the comparable service tariff it must provide as a member 
of the Western Regional Transmission Association should satisfy the 
reciprocity requirement.
    TANC also asks for clarification as to how the reciprocity 
provision would be administered. A non-public utility cannot file a 
tariff with the Commission, so presumably it and the public utility 
from which it wants transmission service would negotiate; if, however, 
the public utility does not agree that reciprocal service is being 
offered, it will deny access to its transmission facilities, and the 
non-public utility would have to come to the Commission to resolve the 
dispute. SC Public Service Authority expresses a similar concern. It 
argues that the reciprocity provision will prevent non-public utilities 
from obtaining comparable access. The public utility from which the 
non-public utility wants access will be able to delay access by 
claiming that the reciprocity provision is not satisfied. Even the 
possibility of such a delay may discourage customers from contracting 
with non-public utilities. SC Public Service Authority suggests that 
this problem can be fixed by allowing non-public utilities to file 
comparable access tariffs with the Commission.
    NE Public Power District asserts that while government-owned 
utilities are subject to limited regulation under sections 211-213 of 
the FPA, ``that limited grant of jurisdiction cannot be transmuted into 
amenability of state- and municipally owned utilities to the sort of 
detailed regulation that the NOPR would impose through requiring 
insertion of so-called 'reciprocity' clauses in the transmission 
tariffs of jurisdictional public utilities, by inviting the filing of 
'class' Sec. 211 applications, or by making adherence to the rules 
emerging from the NOPR proceeding an automatic requirement for 
utilities that are subject to a section 211 application.''
    NE Public Power District explains that it has pending before the 
Commission a proceeding in which it has taken the position that it is 
not subject to the Commission's jurisdiction. (citing Docket No. TX95-
3-000).<SUP>485 NE Public Power District also argues that it would be 
unconstitutional under the Tenth Amendment and the Guarantee Clause of 
the United States Constitution for the Commission to assert 
jurisdiction. It further argues that the proposed regulations would 
constitute an unfunded Federal mandate within the meaning of the 
Unfunded Mandates Reform Act of 1995 and that the Commission has not 
followed the requirements of that Act.
---------------------------------------------------------------------------

    \485\ We note that the application in Docket No. TX95-3-000 by 
Municipal Energy Agency of Nebraska was withdrawn on November 16, 
1995.
---------------------------------------------------------------------------

    NE Public Power District explains that under Nebraska law it is 
prohibited from granting or conveying to any private entity any 
interest or control of any of its property or facilities, and section 
211 does not authorize the Commission to order wheeling for an end-user 
or to replace a contractual wholesale sale. Thus, it argues that the 
Commission does not have authority to use mandatory reciprocity clauses 
to obtain compliance with a policy it has no right to impose directly. 
(citing Sunray and AGD). NE Public Power District also questions 
whether the Commission may lawfully declare exclusive-use provisions 
invalid under the Sierra-Mobile doctrine without conducting a 
proceeding under section 206 with regard to each specific facility and 
making the necessary findings.
    Salt River responds to complaints that public power entities have a 
competitive advantage, due to subsidies and preferences, over investor-
owned utilities:

    This Commission is not the appropriate forum and this proceeding 
is not the appropriate proceeding to consider the investor-owned 
utilities' ``level playing field'' complaint as it relates to public 
power, and the Commission should reject any suggestion that it do 
so.<SUP>486

    \486\ Salt River Reply Comments at 2. See also NCMPA.
---------------------------------------------------------------------------

    Cleveland urges the Commission not to address in the NOPR 
proceeding either congressional policy as reflected in the tax laws or 
the propriety of other long-standing federal statutes in considering 
complaints that publicly-owned entities receive subsidies from the 
government that IOUs do not. It points to three tax breaks available to 
IOUs: (1) Investment tax credits; (2) deferred taxes resulting from 
different book and tax depreciation; and (3) use of tax-exempt 
financing in certain circumstances.
    NRECA/APPA argues that the Commission should not, as requested by 
EEI, address alleged ``undue'' subsidies received by consumer-owned 
utilities and delve into such subsidy issues as municipal financing 
policy, rural electrification and development policies, and the merits 
of privatizing the federal power marketing administration. NRECA/APPA 
alleges that these are complex issues that are within the domain of 
other federal agencies.
G&T and Distribution Cooperatives
    NRECA explains that under Dairyland Power Cooperative,<SUP>487 the 
Commission does not have jurisdiction over cooperatives that have REA/
RUS loans.<SUP>488 NRECA further explains that rural electric 
cooperatives are exempt from federal taxation only if 85 percent of 
their revenues are derived from their members and open access could 
jeopardize their tax relief.<SUP>489 RUS notes that while the Energy 
Policy Act expanded the Commission's authority to order transmission 
access, it did not

[[Page 21613]]

amend the Rural Electrification Act (RE Act) so as to curtail the 
plenary powers of RUS to carry out a program of rural electrification.
---------------------------------------------------------------------------

    \487\ 37 FPC 12, 37 FPC 495 (1967), aff'd sub nom. Salt River 
Project v. FPC, 391 F.2d 470 (D.C. Cir.), cert. denied, 393 U.S. 857 
(1968).
    \488\ See also Basin EC, Big Rivers EC (citing Golden Spread, 39 
FERC para. 61,322, reh'g denied, 40 FERC para. 61,348 (1987)), RUS 
(asserting that RUS has exclusive authority over rural power 
cooperatives that have RUS loans).
    \489\ See also McKenzie EC, NW Iowa Cooperative, TDU Systems, 
RUS (asserting that if cooperative voluntarily gives up its tax 
exempt status, the Commission should allow the related tax expense 
to be included in the rates charged to the non-member customers 
only), Brazos, Tri-State G&T, TAPS.
---------------------------------------------------------------------------

    Citing various cases, Brazos says that the Commission must be 
mindful of the purposes of the RE Act and, if available transmission on 
Brazos is taken for use by third parties, ``a question remains as to 
the capacity of the remaining portions of the system to function with 
`decent service and at decent rates.' '' <SUP>490
---------------------------------------------------------------------------

    \490\ Brazos Initial Comments at 6.
---------------------------------------------------------------------------

    Various rural electric cooperatives state that the Commission must 
recognize that consumer-owned electric utilities are very different 
from investor-owned utilities.<SUP>491 Mor-Gran-Sou EC is concerned 
that the final rule will have a detrimental impact on rural areas, just 
as it believes deregulation of the banking industry, airline industry 
and telecommunications industry has had.
---------------------------------------------------------------------------

    \491\ E.g., NW Iowa Cooperative, TDU Systems, Big Rivers EC, 
Mor-Gran-Sou EC, San Luis Valley REC, Tri-County EC; see also RUS, 
MEAG, Brazos.
---------------------------------------------------------------------------

    Many cooperatives request that the term ``affiliates'' be defined: 
(1) To apply only to corporate ``affiliates'' over which the 
transmission customer exercises legal control; and (2) to exclude the 
distribution cooperative members of a generation and transmission (G&T) 
cooperative.<SUP>492 Seminole EC explains that a G&T is a cooperative 
formed by a group of distribution cooperatives; therefore, a G&T has no 
legal powers to require action by its member cooperatives. In fact, 
according to Seminole EC, the distribution cooperatives govern the G&T.
---------------------------------------------------------------------------

    \492\ E.g., NRECA, Cajun, AEC & SMEPA, Seminole EC, TDU Systems.
---------------------------------------------------------------------------

    Similarly, TDU Systems notes that the term ``affiliates'' could be 
construed to apply to a joint action agency and its municipal and 
cooperative members. TDU Systems point out that a joint action agency, 
itself a creature of statute, may not have the power to require its 
members to provide transmission service.
    AEC & SMEPA contends that including the transmission customer's 
affiliates in the reciprocity obligation is broader than the obligation 
of the transmission provider, which does not include transmission 
service by the provider's affiliates. AEC & SMEPA suggests that either: 
(1) The transmission provider's affiliates should be included in the 
basic obligation to provide transmission service; or (2) the 
reciprocity provision should delete the reference to affiliates of the 
transmission customer.
    NRECA comments that it is unclear whether ``facilities owned or 
controlled by the transmission customer'' include transmission 
contracts. NRECA believes that transmission contracts cannot be 
included in this definition, at least as applied to ``transmitting 
utilities'' under sections 211 and 212.
Transmission Provider
    Seminole EC questions whether the requirement to offer ``open 
access'' service requires reciprocal service to be provided solely to 
the transmission provider or an open access tariff available to any and 
all qualified applicants. Seminole EC and NRECA request that the 
Commission adopt the former interpretation in the final rule.
    In contrast, Tucson Power and Phelps Dodge believe that, if a non-
public utility transmitting entity chooses to take service under any 
open access tariff, such access should be conditioned on its own 
agreement to provide comparable service to all eligible customers under 
an open access tariff.
    Tucson Power believes that, without such access to all eligible 
customers, reciprocity will fail to achieve true ``comparability.'' 
Tucson Power explains that reciprocal transmission service would appear 
to be limited by the terms of the specific original request for 
transmission. For example, Tucson Power fears that a non-jurisdictional 
entity requesting 25 MW of point-to-point firm service could argue that 
its reciprocal transmission obligation is limited to the same 25 MW of 
point-to-point firm service for an equivalent duration. Tucson Power 
argues that such a limitation on providing reciprocal service would 
prove useless. Further, Tucson Power believes that reciprocity should 
be interpreted to require a non-public utility entity to expand or 
upgrade facilities to meet the transmission requests of all eligible 
entities and should contain the same pricing provisions as applied in 
this proceeding for jurisdictional utilities.
    Seminole EC questions whether the reciprocity requirement to 
provide ``comparable'' service to the transmission provider simply 
means offering the same kind of service to the transmission provider 
that the transmission customer receives (i.e., network, firm point-to-
point, or non-firm).
    NRECA claims that the reciprocity requirement should not be 
construed to impose on non-public utilities an unreasonable obligation 
to build. Seminole EC adds that an unreasonable obligation to build 
could effectively preclude requests for tariff service; the 
transmission customer could be better off litigating a section 211 
request rather than accepting the obligation to undertake a massive 
construction program.
Commission Conclusion
    We conclude that it is appropriate to require a reciprocity 
provision in the Final Rule pro forma tariff. This provision would be 
applicable to all customers, including non-public utility entities such 
as municipally-owned entities and RUS cooperatives, that own, control 
or operate interstate transmission facilities and that take service 
under the open access tariff, and any affiliates of the customer that 
own, control or operate interstate transmission facilities. Any public 
utility that offers non-discriminatory open access transmission for the 
benefit of customers should be able to obtain the same non-
discriminatory access in return.
    In the NOPR, we explained that the reciprocity provision would 
``requir(e) any user or agent of the user of the tariff that owns and/
or controls transmission facilities to provide non-discriminatory 
access to the tariff provider.'' <SUP>493 We wish to clarify that, in 
stating that a user must provide non-discriminatory access to the 
tariff provider, we intend that reciprocal service be limited to the 
transmission provider. However, in situations in which a non-public 
utility is a member of an RTG or a power pool, it also would have to 
provide service to the other members of the RTG or power pool. We do 
not believe it is appropriate to expand the reciprocity condition 
beyond these situations at this time because, as discussed further 
below, the IRS currently is evaluating its tax-exempt financing 
regulations in light of competitive changes in the industry.
---------------------------------------------------------------------------

    \493\ FERC Stat. & Regs. at 33,050.
---------------------------------------------------------------------------

    We are aware that many non-public utilities are very willing to 
offer reciprocal access, and that some are willing to provide access to 
all eligible customers through an open access tariff. However, they are 
fearful that a public utility may deny service based simply on a claim 
that the open access tariff offered by a non-public utility is not 
satisfactory. To assist these non-public utilities, we have developed a 
voluntary safe harbor procedure that should alleviate these concerns. 
Under this procedure, non-public utilities would be allowed to submit 
to the Commission a transmission tariff and a request for declaratory 
order that the tariff meets the Commission's comparability (non-
discrimination) standards. We would post these requests on the 
Commission Issuance Posting System (CIPS) and would provide them with 
an NJ (non-

[[Page 21614]]

jurisdictional) docket designation. If we find that a tariff contains 
terms and conditions that substantially conform or are superior to 
those in the Final Rule pro forma tariff, we would deem it an 
acceptable reciprocity tariff and would require public utilities to 
provide open access service to that particular non-public 
utility.<SUP>494 In order to find that a non-public utility's tariff is 
consistent with our comparability standards, we would need sufficient 
information to conclude that the non-public utility's rate is 
comparable to the rate it charges others. In addition, once we find 
that a tariff is an acceptable reciprocity tariff, an applicant in a 
section 211 case against a non-public utility would have the burden of 
proof to show why service to the applicant under the same terms as the 
reciprocity tariff is not sufficient and why a section 211 order should 
be granted.
---------------------------------------------------------------------------

    \494\ Public utilities would also be required to provide service 
during the pendency of any request for declaratory order. Otherwise, 
public utilities could continue to delay providing service.
---------------------------------------------------------------------------

    The safe harbor procedures that we have outlined above would be 
purely voluntary for non-public utilities. The procedures are intended 
to provide non-public utilities an opportunity to confirm that they are 
willing to provide comparable transmission service. If, however, a non-
public utility chooses not to seek a Commission determination that its 
tariff meets the Commission's comparability standards, a public utility 
could refuse to provide open access transmission service only if such 
denial is based on a good faith assertion that the non-public utility 
has not met the Commission's reciprocity requirements.
    In addition to the safe harbor procedures, we note that a non-
public utility that is a member of an RTG can meet our comparability 
standards through the RTG, and can provide an open access tariff that 
meets our comparability standards by filing a tariff with the 
administrator of the RTG.<SUP>495 Similarly, a non-public utility that 
is a member of a power pool could meet our comparability standard if 
the power pool adopts a joint pool-wide open access tariff.
---------------------------------------------------------------------------

    \495\ See, e.g., Southwest Regional Transmission Association, 73 
FERC para. 61,147 at 61,414 (1995).
---------------------------------------------------------------------------

    Some commenters have challenged the Commission's jurisdiction to 
require any non-public utility that takes jurisdictional service to 
provide reciprocal non-discriminatory transmission services and to 
unbundle its rates. We are not requiring non-public utilities to 
provide transmission access. Instead, we are conditioning the use of 
open access services on an agreement to offer open access services in 
return. Non-public utilities can choose not to take service under 
public utility open access tariffs and can instead seek voluntary 
service from the public utility on a bilateral basis.
    In response to arguments raised by publicly-owned utilities and 
cooperatives, we are not prepared to revise or eliminate the 
reciprocity condition. Our reason is simple and compelling. We are 
undertaking this Rule and imposing significant responsibilities on 
public utilities to ensure the Nation's transmission grid is open and 
available to customers seeking access to the increasingly competitive 
commodity market for electricity. While we do not have the authority to 
require non-public utilities to make their systems generally available, 
we do have the ability, and the obligation, to ensure that open access 
transmission is as widely available as possible and that this Rule does 
not result in a competitive disadvantage to public utilities. Non-
public utilities, whether they are selling power from their own 
generation facilities or reselling purchased power, have the ability to 
foreclose their customers' access to alternative power sources, and to 
take advantage of new markets in the traditional service territories of 
other utilities. While we do not take issue with the rights these non-
public utilities may have under other laws, we will not permit them 
open access to jurisdictional transmission without offering comparable 
service in return. We believe the reciprocity requirement strikes an 
appropriate balance by limiting its application to circumstances in 
which the non-public utility seeks to take advantage of open access on 
a public utility's system. However, we recognize that Congress has 
determined that certain entities in the bulk power market can utilize 
tax-exempt financing by issuing bonds that do not constitute ``private 
activity bonds'' <SUP>496 or by financing facilities with ``local 
furnishing'' bonds.<SUP>497 In both circumstances, Congress has 
entrusted the Internal Revenue Service (IRS) with the responsibility 
for implementation and for determining what uses of the facilities are 
consistent with maintaining tax-exempt status for bonds used to finance 
such facilities. It is not our purpose to disturb Congress's and the 
IRS's determinations with respect to tax-exempt financing.
---------------------------------------------------------------------------

    \496\ See 26 U.S.C. 141.
    \497\ See 26 U.S.C. 142.
---------------------------------------------------------------------------

    We are encouraged that the IRS is presently reconsidering its 
private activity bond regulations in light of, among other things, the 
changing circumstances in the electric industry, including this 
proceeding.<SUP>498 We are hopeful that the IRS in its rulemaking will, 
to the maximum extent possible, remove regulatory impediments that 
limit the ability of industry participants to provide reciprocal open 
access service. Until that occurs, however, we believe we must ensure 
that the reciprocity requirement will not be used to defeat tax-exempt 
financing authorized by the Congress. Therefore, we clarify that 
reciprocal service will not be required if providing such service would 
jeopardize the tax-exempt status of the transmission customer's (or its 
corporate affiliates') bonds used to finance such transmission 
facilities.<SUP>499 If a non-public utility has sought a declaratory 
order on a voluntarily-filed tariff, we request that it identify the 
services, if any, that it cannot provide without jeopardizing the tax-
exempt status of its financing.<SUP>500
---------------------------------------------------------------------------

    \498\ Definition of Private Activity Bonds, 59 FR 67658 
(December 30, 1994), Proposed Rules (to be codified at 26 CFR pt. 
1).
    \499\ The same would be true in the case of a G&T cooperative 
that is a tax-exempt entity under section 501(c)(12) of the Internal 
Revenue Code (26 U.S.C. 501(c)(12)) that would risk loss of tax-
exempt status if more than 15 percent of its revenues are derived 
from business with non-members. We clarify that reciprocal service 
will not be required if providing such service would jeopardize the 
G&T cooperative's tax-exempt status.
    \500\ A tariff offered by a non-public utility transmission 
provider to satisfy the reciprocity requirement may include a 
provision permitting the transmission provider to refuse service if 
providing such service would jeopardize its tax-exempt status or the 
tax-exempt status of its bonds. The non-public utility could file a 
declaration to this effect in an NJ docket.
---------------------------------------------------------------------------

    We believe, given the fact that the IRS is currently examining 
these issues, that our policy in this regard is appropriate for the 
time being. After the IRS acts, we will reexamine our policy to ensure 
that the reciprocity requirement is applied broadly to achieve open 
access without jeopardizing tax-exempt financing.
    With respect to local furnishing bonds, which are available to a 
handful of public utilities, we note that Congress, in section 1919 of 
the Energy Policy Act, amended section 142(f) of the Internal Revenue 
Code to provide that a facility shall not be treated as failing to meet 
the local furnishing requirement by reason of transmission services 
ordered by the Commission under section 211 of the FPA if ``the portion 
of the cost of the facility financed with tax-exempt bonds is not 
greater than the portion of the cost of the facility which is allocable 
to the local furnishing of electric energy.'' <SUP>501 San Diego G&E 
has included in its existing transmission tariff a provision

[[Page 21615]]

that provides that, if it appears that the provision of transmission 
service would jeopardize the tax-exempt status of any local furnishing 
bonds used to finance its facilities, San Diego G&E will not contest 
the issuance of an order under section 211 of the FPA requiring the 
provision of such service, and will, within 10 days of receiving a 
written request by the applicant, file with the Commission a written 
waiver of its rights to a request for service under section 213(a) of 
the FPA and to the issuance of a proposed order under section 
212(c).<SUP>502 We believe such a provision is necessary and 
appropriate so that any local furnishing bonds that may exist do not 
interfere with the effective operation of an open access transmission 
regime. Accordingly, we will require any public utility that is subject 
to the Open Access Rule that has financed transmission facilities with 
local furnishing bonds to include in its tariff a similar 
provision.<SUP>503
---------------------------------------------------------------------------

    \501\ 26 U.S.C. 142(f)(2)(A).
    \502\ See San Diego Gas & Electric Company, Docket No. ER96-43-
000, Pro-Forma Point-to-Point Transmission Service Tariff, section 
4.6(d); Network Transmission Service Tariff, section 4.7(d).
    \503\ See Appendix D, Pro Form Open Access Transmission Tariff, 
Section 5.
---------------------------------------------------------------------------

    In addition, in response to arguments raised by cooperatives and 
joint action agencies, we agree to limit the reciprocity requirement to 
corporate affiliates. If a G&T cooperative seeks open access 
transmission service from the transmission provider, then only the G&T 
cooperative, and not its member distribution cooperatives, would be 
required to offer transmission service. However, if a member 
distribution cooperative itself receives transmission service from the 
transmission provider, then it (but not its G&T cooperative) must offer 
reciprocal transmission service over its interstate transmission 
facilities.
    Finally, a non-public utility, for good cause shown, may file a 
request for waiver of all or part of the reciprocity requirement. We 
would apply the same criteria we will use to determine whether to grant 
a waiver of all or part of the Final Rule's requirements for public 
utilities that request waiver.
    The reciprocity requirement will also apply to any entity that 
owns, controls or operates transmission facilities that uses a marketer 
or other intermediary to obtain access. For example, if a municipal 
purchases power from a marketer that also arranges for the transmission 
of the power through a public utility open access tariff to the 
municipal, the municipal would need to meet our reciprocity 
requirements. We point out here that we have established a procedure, 
set out in Section IV.K.2., for small public utilities to request a 
waiver from some or all of the requirements of the Rule. We would apply 
the same criteria to waive the reciprocity condition for small non-
public utilities.
g. Miscellaneous Tariff Modifications
(1) Ancillary Services
    The pro forma tariff, attached as Appendix D, incorporates 
conforming revisions consistent with the determinations discussed in 
Section IV.D.
(2) Clarification of Accounting Issues
Comments
    A number of commenters generally assert that, as presently 
configured, the Commission's Uniform System of Accounts does not 
support the proposed stranded cost and open access policies set forth 
in the NOPR. They urge the Commission to open a separate docket to 
address these accounting issues and bring together all parties to 
properly resolve them. More specifically, commenters ask whether 
certain of the requirements outlined in the NOPR pro forma tariffs 
would require changes to the Uniform System of Accounts. In particular, 
commenters are concerned that the recording of costs and revenues 
related to ancillary services, facilities studies, and system impact 
studies would require the creation of new accounts under the Uniform 
System of Accounts. In addition, commenters raise questions about the 
procedures transmission providers would have to follow for recording 
the costs for their own use of the system. Commenters also indicate 
that the Commission's accounting requirements may not be adequate to 
provide fully for the recognition of stranded costs as contemplated in 
the NOPR.
Commission Conclusion
    The Final Rule will result in significant changes in the way public 
utilities conduct business. This will create needs for financial 
information that are different from those that the Commission and 
others found necessary in the past. The Commission believes that the 
accounting guidance discussed infra will be sufficient to provide the 
financial information needed for regulatory purposes in light of this 
Rule. Therefore, we will not institute a separate proceeding to propose 
changes to our Uniform System of Accounts at the present time. We 
recognize, however, that the industry is in an early stage of 
transition to an environment in which truly comparable transmission 
services will be provided to all wholesale users. If, after gaining 
additional experience, it becomes apparent that more guidance is 
needed, additional guidance can be provided at that time through 
issuance of accounting interpretations, guidance letters, or a notice 
of proposed rulemaking to change our accounting regulations.
    Many of the accounting concerns expressed by commenters were 
addressed in the Chief Accountant's January 26, 1996 guidance letter. 
We offer the following additional clarifications on the Final Rule pro 
forma tariff requirements and certain other accounting issues related 
to the Final Rule.
(a) Transmission Provider's Use of Its System (Charging Yourself)
    The purpose of functional unbundling is to separate the 
transmission component of all new transactions occurring under the 
Final Rule pro forma tariff, thereby assisting in the verification of a 
transmission provider's compliance with the comparability requirement. 
For example, if a transmission provider makes an off-system power sale, 
functional unbundling requires that the revenues received from that 
third-party customer be unbundled into specific transmission and 
production components. The transmission component of the revenues would 
be the product of the amount of transmission capacity used in making 
the sale and the applicable rate. With respect to off-system sales, the 
transmission provider would look to operating revenue accounts those 
revenues received from the customer to whom it made the off-system 
sale. We will require that the transmission service component and 
energy component of those revenues be recorded in separate subaccounts 
of Account 447, Sales for Resale.
(b) Facilities and System Impact Studies
    Comparability mandates that to the extent a transmission provider 
charges transmission customers for the costs of performing specific 
facilities or system impact studies related to a service request, the 
transmission provider also must separately record the costs associated 
with specific studies undertaken on behalf of its own native load 
customers, or, for example, for making an off-system sale. Utilities 
choosing this method of recovering the cost of specific studies must 
keep detailed expense records pertaining to each specific study. We 
will require utilities to record the cost of such studies that are 
properly includable in the determination of net income for the

[[Page 21616]]

period in a separate subaccount of Account 566, Miscellaneous 
Transmission Expenses. We note, however, that not all studies performed 
by a transmission provider will benefit only a single customer. To the 
extent a transmission provider performs a system impact study that is 
useful in providing service to all transmission customers, the costs 
should be allocated to all customers.
(c) Ancillary Services
    To ensure comparable transmission access a transmission provider is 
obligated to provide, or offer to provide, certain ancillary services 
to the transmission customer. Also, the transmission provider may offer 
to provide other ancillary services to the transmission customer, as 
discussed in Section IV.D. A transmission customer is obligated to 
purchase certain ancillary services from the transmission provider.
    Generation resources provide certain ancillary services, while 
transmission resources provide other ancillary services. Consequently, 
the costs of providing certain ancillary services are recorded in the 
transmission provider's power production expense accounts,<SUP>504 
while others are recorded in the transmission provider's transmission 
expense accounts.
---------------------------------------------------------------------------

    \504\ This discussion applies to vertically integrated 
transmission providers. It may not apply, for example, to a 
transmission-only company or an independent system operator.
---------------------------------------------------------------------------

    Some commenters suggest that there may be a need for revising the 
Uniform System of Accounts to better track the costs of providing 
discrete ancillary services. Other commenters believe that ancillary 
services are transmission-type services and suggested that the costs of 
generation-provided ancillary services be refunctionalized from power 
production expense to transmission expense.
    Currently, the Uniform System of Accounts requires that costs 
incurred in providing ancillary services are recorded as power 
production or transmission expense depending upon which resource the 
transmission provider uses to supply the service. At this time, we are 
not convinced that the amounts involved or the difficulty associated 
with measuring the cost of ancillary services warrants a departure from 
our present accounting requirements. However, in calculating separate 
rates for specific ancillary services utilities must maintain 
sufficient records and cost support for the derivation of the rates. 
Additionally, we will specify that the revenues a Transmission Provider 
receives from providing ancillary services must be recorded by type of 
service in Account 447, Sales for Resale, or Account 456, Other 
Electric Revenues, as appropriate.
(3) Liability and Indemnification
Comments
    A number of commenters addressed the liability and indemnification 
provisions of the proposed pro forma tariffs. Duke argues that the 
proposed language confuses and conflates the limitation on the 
Transmission Provider's and Customer's rights against each other if a 
force majeure event occurs, and the requirement of indemnification 
against claims by third parties.
    EEI argues that the proposed indemnification provision is 
inappropriate because it applies both ways, that is, the Transmission 
Provider and Customer indemnify each other against third party claims 
arising on their own systems. EEI suggests that the provision, as 
written, could result in the utility being required to indemnify the 
customer against damages incurred if, for example, an individual pried 
open a transformer to steal materials and in the process was 
electrocuted. This concern was also voiced by Consolidated Edison, 
NYSEG, and Virginia Electric and Power Company. Consumer Power suggests 
that the best answer to this issue may be to leave the issue of 
allocation of risk to the contracting parties, to be resolved by 
negotiation when a Service Agreement is drawn up.
    The Coalition for a Competitive Market, on the other hand, argues 
that the indemnification provision, as proposed, provides too much of a 
limitation of the Transmission Provider's liability, requiring gross 
negligence rather than simple negligence before the Transmission 
Provider can be held liable for damages to third parties arising from 
the Transmission Provider's actions.
Commission Conclusion
    We agree with the commenters that these risk allocation provisions 
must be carefully drafted so that transmission providers and customers 
can accurately assess and account for their respective risks. The 
indemnification provision has now been broken into two parts. The first 
part is a force majeure provision which provides that neither the 
transmission provider nor the customer will be in default if a force 
majeure event occurs, but also provides that both the transmission 
provider and customer will take all reasonable steps to comply with the 
tariff despite the occurrence of a force majeure event. This protection 
against unexpected and unpredictable events is appropriately made 
available to both the transmission provider and transmission customer.
    The second portion of the provision provides for indemnification 
against third party claims arising from the performance of obligations 
under the tariff. We have limited the indemnification portion of the 
provision so that it is now only the transmission customer who 
indemnifies the transmission provider from the claims of third parties. 
The customer is taking service from the transmission provider and may 
appropriately be asked to bear the risks of third-party suits arising 
from the provision of service to the customer under the tariff. We find 
that this new indemnification provision would be too strict if it 
required customers to indemnify transmission providers even in cases 
where the transmission provider is negligent. See Pacific Interstate 
Offshore Company, 62 FERC para. 61,260 at 62,733-34 (requiring 
amendment of indemnification provisions that required indemnification 
except in cases of ``gross negligence''). Accordingly, the revised 
provision provides that the customer will not be required to indemnify 
the transmission provider in the case of negligence or intentional 
wrongdoing by the transmission provider.
(4) Miscellaneous Clarifications
(a) Electronic Format
    In the NOPR, we proposed that public utilities making Stage Two 
filings be required, in addition to the requirements specified in Part 
35, to file copies of such filings on a diskette in ASCII format. We 
will now require that public utilities, in addition to complying with 
the requirements of Part 35, submit a complete electronic version of 
all transmission tariffs and service agreements in a word processor 
format, with the diskette labeled as to the format (including version) 
used, initially and each time changes are filed. After the initial 
compliance filing, utilities proposing changes to the Final Rule pro 
forma tariff terms and conditions must provide a detailed list of 
changes and, to the extent practicable, provide an electronic version 
that reflects changes in redline/strikeout format.
(b) Administrative Changes
    A number of commenters request tariff modifications of an 
administrative nature. We have adopted many of these recommendations. 
Due to the nature of these changes, we feel that no further

[[Page 21617]]

explanation is necessary. The tariff modifications include the 
following:
Part I--Common Service Provisions

Description

    <bullet> Added definition for Curtailment.
    <bullet> Modified definition for Good Utility Practice.
    <bullet> Added definition for Interruption.
    <bullet> Added definition for Load Shedding
    <bullet> Added definition for Long-Term Firm Point-to-Point 
Transmission Service.
    <bullet> Added definition for Third-Party Sale.
    <bullet> Modified provision for Interest on Unpaid Balances to 
include amounts placed in escrow.
    <bullet> Modified provision for Customer Default to not require 
termination of service.
    <bullet> Deleted contradictory language from the provision for 
Rights Under the Federal Power Act.
    <bullet> Deleted references to Valid Request throughout the tariff.
Part II--Point-To-Point Transmission Service

Description

    <bullet> Added language that multiple generating units at one site 
are considered one point of receipt.
    <bullet> Changed the time to file an unexecuted service agreement 
from 10 days to 30 days.
    <bullet> Changed the time to execute a service agreement from 30 
days to 15 days.
    <bullet> Deleted charge for scheduling changes.
    <bullet> Deleted redundant language on study agreements.
    <bullet> Changed standards for estimates from binding to good 
faith.
    <bullet> Clarified that schedules of energy submitted to the 
delivering party will equal the schedules of energy submitted by the 
receiving party unless reduced for losses.
    <bullet> Clarified that the term of non-firm point-to-point 
transmission service need not expire before the customer may submit 
another application for service.
    <bullet> Added language for rate treatment in the instance when a 
customer uses more non-firm point-to-point transmission service than it 
has reserved.
    <bullet> Clarified Deposit provision to permit return of deposit at 
expiration of service agreement rather than crediting the deposit 
against unspecified customer obligations under the tariff.
    <bullet> Clarified provision for Yearly Extensions for Commencement 
of Service.
    <bullet> Clarified provision for Reservation of Non-Firm Point-to-
Point Transmission Service.
    <bullet> Modified provision for customer Power Factor to permit 
mutually agreeable alternatives to maintaining a specified power 
factor.
Part III--Network Integration Transmission Service

Description

    <bullet> Deleted redundant Direct Assignment provision.
    <bullet> Added language to clarify that a transmission customer 
does not have to use the transmission provider's point-to-point 
transmission service if the sales to non-designated loads do not use 
the transmission provider's system.
    <bullet> Modified Transmission Customer Redispatch Obligation to 
limit the redispatch obligation to reliability reasons.
    <bullet> Deleted Member System requirement from network service.
    <bullet> Deleted redundant General Conditions.
    <bullet> Added provision to return application if customer does not 
remedy deficiency.
    <bullet> Deleted redundant language for designating new network 
resources.
    <bullet> Deleted redundant language for connecting new member 
systems.
    <bullet> Deleted redundant language for new interconnection points.
    <bullet> Added a 60 day period for initial applications consistent 
with the point-to-point service provision. (If applications during this 
period exceed available capacity, they are considered simultaneous 
requests and service will be decided based on a lottery.)
    <bullet> Modified System Impact Study provision.
    <bullet> Added 30 day turnaround for Facilities Study Agreement and 
changed estimates from binding to good faith.
    <bullet> Deleted redundant language for adding new network 
resources.
    <bullet> Added language for rate treatment in the instance when a 
customer fails to curtail or shed load.
    <bullet> Deleted redundant language from Network Operating 
Committee.
H. Implementation
    The Commission proposed in the NOPR a two-stage implementation 
process that would apply to all transmission-owning public utilities 
that do not have non-discriminatory open access transmission tariffs on 
file on the effective date of the final rule. As proposed in the NOPR, 
public utilities already in compliance with the rule would not be 
subject to the two-stage process.
    In Stage One, the Commission proposed to put into effect tariffs 
for network and point-to-point services, which include ancillary 
transmission services. These tariffs would specify the minimum terms 
and conditions of service needed to eliminate undue discrimination, and 
were proposed to be effective 60 days after the effective date of the 
final rule. Because the proposed pro forma tariffs did not contain 
specific rates, the Commission proposed to itself establish, for each 
affected public utility, just and reasonable rates for network service, 
point-to-point service, and six identified ancillary services. These 
rates were to be incorporated into each utility's tariffs.
    In Stage Two, which was to begin 61 days after the effective date 
of the final rule, parties would have been allowed to propose changes 
to the rates, terms, and conditions for service under utilities' 
transmission tariffs pursuant to sections 205 and 206 of the FPA.
Comments
    The commenters are split on the two-stage implementation procedure 
proposed in the NOPR. Commenters in favor of the proposed procedure 
believe that a two-stage process is necessary to put basic open access 
tariffs in place without delay.<SUP>505 Florida Power Corp and NIEP 
state that a longer implementation procedure would create a 
discriminatory situation for utilities that have filed open access 
tariffs versus those that have not. Other commenters, however, contend 
that the proposed Stage One rates would be just and reasonable only as 
an interim measure; therefore, the period during which such rates are 
effective should be limited.<SUP>506
---------------------------------------------------------------------------

    \505\ E.g., ABATE, CO Com, DOE, Florida Power Corp, IBM, IL Com, 
MN DPS, Industrial Energy Applications, Missouri-Kansas Industrials, 
NIEP, ND Com, PG&E, PSNM, SBA, SC Public Service Authority, TDU 
Systems.
    \506\ E.g., SC Public Service Authority.
---------------------------------------------------------------------------

    Those commenters that oppose the two-stage implementation process 
do so for a variety of reasons.<SUP>507 Many transmission customers 
believe that Stage One rates will be much higher than the rates they 
pay now. Several commenters warn that the implementation plan may not 
be practical if the Commission is inundated with filings at the 
beginning of Stage Two.<SUP>508 Some commenters expressing concerns 
about transmission pricing policy believe that in the NOPR the 
Commission intended to establish the Stage One rate method as its own

[[Page 21618]]

official pricing policy, while other commenters argue that the Stage 
One rates demonstrate that broad pricing policy reform is needed as 
part of an open access rule.
---------------------------------------------------------------------------

    \507\ E.g., Dayton, Carolina P&L, Citizens Utilities, Montana 
Power, Oglethorpe, OK Com, Seattle, Seminole EC, St. Joseph, 
Turlock, WA Com.
    \508\ E.g., Christensen, Seminole EC.
---------------------------------------------------------------------------

    Some commenters express concern about the timing of Stage One. 
Carolina P&L complains that the proposed implementation date is far too 
aggressive and proposes a one-year delay between the final rule and its 
implementation. Montana Power states that Stage One tariffs cannot be 
implemented in 60 days if any sort of functional unbundling is 
required. It insists that utilities should be given, at a minimum, 180 
days in which to hire and train new employees and to install new 
equipment. Dayton P&L believes that Stage One tariffs should not be 
imposed until experience is gained with voluntarily-filed open access 
tariffs, but recommends further development of the tariffs for guidance 
purposes. It also requests that the Commission delay implementation of 
mandatory open access transmission until meaningful appellate review 
has taken place. Seattle suggests that the rate determination methods 
be phased in, so that the forced filing of transmission tariffs does 
not cause immediate and major shifts in cost allocation between old and 
new customers.
    A few commenters express concern about the applicability of the 
implementation process. EEI and Consumers Power state that utilities 
that have already filed open access tariffs should have the option to 
use the two-stage implementation procedure so that they can obtain the 
terms and conditions of the NOPR tariffs without having to make a full-
blown rate case filing.
    Citizens Utilities asks that small distribution public utilities be 
exempt from Stage One if such entities can demonstrate that they do not 
use their own transmission systems to provide network service. 
Alternatively, it asks that application of Stage One to small public 
utilities be deferred until 60 days after they receive a section 211 
request. Oglethorpe states that the proposed method of Stage One 
pricing is not appropriate for electric cooperatives that receive 
financing from the Rural Utilities Service (formerly the Rural 
Electrification Administration).
Commission Conclusion
    In light of the many concerns raised regarding the proposed 
implementation process, the need to have adequate open access tariffs 
on file for all public utilities as soon as possible, the large number 
of utilities that have already filed some form of open access tariffs, 
and the desire to give public utilities flexibility to propose their 
own rates to be used in conjunction with the minimum non-rate terms and 
conditions necessary to ensure comparable service, we have decided to 
modify our proposed procedures. The details of the revised procedures 
are discussed below. In addition, special implementation requirements 
for coordination arrangements (power pools, public utility holding 
companies, and bilateral coordination arrangements) are discussed in 
Section IV.F.
The Revised Procedures
    Implementation of the Rule will vary slightly for those public 
utilities that tendered for filing open access tariffs before the date 
of issuance of this Rule (including newly-tendered applications that 
have not been accepted for filing before the issuance of this rule) and 
those public utilities that did not tender open access tariffs before 
the issuance of this Rule. The former group is hereinafter referred to 
as Group 1 public utilities, while the latter group is referred to as 
Group 2 public utilities.
1. Group 1 Public Utilities
    Group 1 public utilities will be required, within 60 days following 
publication of the Final Rule in the Federal Register, to make section 
206 compliance filings that contain the non-rate terms and conditions 
set forth in the Final Rule pro forma tariff and identify any terms and 
conditions that reflect regional practices, as discussed below. 
Attached as Appendix E to this Rule is a list of Group 1 public 
utilities.
    As to rates, we note that a transmission tariff rate is already in 
effect for all Group 1 public utilities, except for the few with 
recently-tendered applications that have not yet been accepted for 
filing. Most of these rates have been suspended, accepted for filing, 
set for hearing, and made subject to refund. Some have been accepted 
outright. Still others are the product of rate settlements.
    We anticipate that our mandated changes in non-rate terms and 
conditions are compatible with the rate proposals already filed by 
Group 1 public utilities. Consequently, we are not going to divert the 
industry's resources by mandating any rate changes to fine-tune these 
interim tariffs. Should, however, a Group 1 public utility determine 
that certain rate changes are necessitated by the revised non-rate 
terms and conditions, it may file a new rate proposal under FPA section 
205. Such filings must be ``conforming'' <SUP>509 under the 
Transmission Pricing Policy Statement and must be made no later than 60 
days after publication of the Final Rule in the Federal Register. 
Intervenors may raise any concerns with the filings within 15 days 
after such filings.<SUP>510 We hereby impose a blanket suspension for 
any filings by Group 1 public utilities proposing rate changes 
necessitated by the new non-rate terms and conditions. These rates will 
go into effect, subject to refund, 60 days after publication of this 
Rule in the Federal Register (the same day on which the non-rate terms 
and conditions of the Final Rule pro forma tariff go into 
effect).<SUP>511
---------------------------------------------------------------------------

    \509\ As described in the Transmission Pricing Policy Statement, 
a ``conforming'' proposal is one that meets the traditional revenue 
requirement and reflects comparability. FERC Stats. & Regs. para. 
31,005 at 31,141.
    \510\ Given the brief comment period on the compliance filings, 
we will require public utilities to serve copies of their compliance 
filings (via overnight delivery) on: all participants in their 
current open access rate proceedings (if applicable); all customers 
that have taken wholesale transmission service from the utility 
after the date of issuance of the Open Access NOPR; and the state 
agencies that regulate public utilities in the states of those 
participants and customers.
    \511\ The Commission retains the right to reject such rates or 
to set them for hearing.
---------------------------------------------------------------------------

    If the Final Rule tariff's non-rate terms and conditions do not in 
the opinion of the utility necessitate a change in current rates, then 
the current rates will continue in effect under whatever refund 
conditions, if any, now apply to those rates.
2. Group 2 Public Utilities
    Group 2 public utilities will be treated the same as Group 1 public 
utilities with regard to non-rate terms and conditions, but will be 
treated slightly differently from Group 1 as to rates, since Group 2 
utilities have not filed any proposed rates. We will require these 
utilities to either: (i) Within 60 days following publication of the 
Final Rule in the Federal Register, make section 206 compliance filings 
that contain the non-rate terms and conditions set forth in the Final 
Rule pro forma tariff and identify any terms and conditions that 
reflect regional practices, as discussed below; and (ii) within 60 days 
following publication of the Final Rule in the Federal Register, make 
section 205 filings to propose rates for the services provided for in 
the tariff, including ancillary services; or (iii) make a ``good 
faith'' request for waiver. The rates must meet the standards for 
conforming proposals in the Commission's Transmission Pricing Policy 
Statement and comply with the guidance concerning ancillary services 
set forth in this order. Attached to this

[[Page 21619]]

Rule as Appendix F is a list of Group 2 public utilities.
    Intervenors may raise any concerns with these filings within 15 
days after the filing.<SUP>512 We hereby impose a blanket suspension 
for all such rate filings; they will go into effect, subject to refund, 
60 days after the publication of this Rule in the Federal Register (the 
same day on which the terms and conditions of the compliance tariffs go 
into effect).<SUP>513
---------------------------------------------------------------------------

    \512\ Group 2 public utilities must serve a copy of their 
filings (via overnight delivery) on all customers that have taken 
wholesale transmission service from them since March 29, 1995 (the 
date of issuance of the Open Access NOPR) and on the state agencies 
that regulate public utilities in the states where those customers 
are located.
    \513\ But see note 510, supra.
---------------------------------------------------------------------------

3. Clarification Regarding Terms and Conditions Reflecting Regional 
Practices
    We have built a degree of flexibility into the tariffs to 
accommodate regional and other differences. Certain non-rate Final Rule 
pro forma tariff provisions specifically allow utilities either to 
follow the terms of the provision or to use alternatives that are 
reasonable, generally accepted in the region, and consistently adhered 
to by the transmission provider (e.g., time deadlines for scheduling 
changes, time deadlines for determining available capacity). In 
addition, other tariff provisions require utilities to follow Good 
Utility Practice. The definition of ``Good Utility Practice,'' 
contained in Section 1.14 of the Final Rule pro forma tariff, states 
that it ``is not intended to be limited to the optimum practice, 
method, or act to the exclusion of all others, but rather to be 
acceptable practices, methods or acts generally accepted in the 
region.'' Thus, where public utilities are permitted to follow regional 
practices, and elect to do so within 60 days of the date of publication 
of the Final Rule in the Federal Register, they should identify the 
regional practices in their compliance tariff filings.
4. Future Filings
    We recognize that there may be circumstances in which a public 
utility believes that the Final Rule pro forma tariff does not provide 
sufficient flexibility or that the utility can propose superior non-
rate terms and conditions. Thus, once the compliance tariff and 
conforming rates go into effect, which will be 60 days after 
publication of this Rule in the Federal Register, a public utility 
(either Group 1 or Group 2) may file pursuant to section 205 a tariff 
with terms and conditions that differ from those set forth in this 
Rule, provided that it: (1) Serves a copy of its filing on all 
wholesale customers for whom it has provided transmission service since 
March 29, 1995 (the date of the Open Access NOPR) and on the state 
agencies that regulate public utilities in the states where those 
customers are located; (2) identifies all deviations from its 
compliance tariff in its letter of transmittal; (3) provides, to the 
extent practical, a redlined version of the tariff; and (4) 
demonstrates that such terms and conditions are consistent with, or 
superior to, those in the compliance tariff. However, it may not seek 
to litigate fundamental terms and conditions set forth in the Final 
Rule.<SUP>514 In addition, the public utility may file whatever rates 
it believes are appropriate, consistent with the Transmission Pricing 
Policy Statement.
---------------------------------------------------------------------------

    \514\ As we stated in our ``Further Guidance Order,'' American 
Electric Power Service Corp., 71 FERC para. 61,393, 62,539-40, order 
on rehearing, 72 FERC para. 61,287, order on rehearing, 74 FERC 
para. 61,013 (1995), all tariffs need not be ``cookie-cutter'' 
copies of the Final Rule tariff. Thus, under our new procedure, 
ultimately a tariff may go beyond the minimum elements in the Final 
Rule pro forma tariff or may account for regional, local, or system-
specific factors. The tariffs that go into effect 60 days after 
publication of this Rule in the Federal Register will be identical 
to the Final Rule pro forma tariff; however, public utilities then 
will be free to file under section 205 to revise the tariffs, and 
customers will be free to pursue changes under section 206.
---------------------------------------------------------------------------

5. Waiver
    Finally, as noted above, several commenters propose that public 
utilities that own few transmission facilities be granted waiver, or 
that application of the Rule to such utilities be deferred until 60 
days after they receive a section 211 request. As discussed more fully 
in Section IV.K.2., we find that it is reasonable to permit certain 
public utilities for good cause shown to file, within 60 days after 
this Rule is published in the Federal Register, requests for waiver 
from some or all of the requirements of this Rule. The filing of a 
request in good faith for a waiver from the requirement to file an open 
access tariff will eliminate the requirement that such public utility 
make a compliance filing unless thereafter ordered by the Commission to 
do so. It will not, however, exempt such public utility from providing, 
upon request, transmission services consistent with the requirements of 
the Final Rule.
    I. Federal and State Jurisdiction: Transmission/Local Distribution. 
In the original Stranded Cost NOPR, the Commission clarified that it 
has exclusive jurisdiction over unbundled retail transmission in 
interstate commerce by public utilities: it found that the Commission 
has exclusive jurisdiction over the rates, terms, and conditions of 
unbundled retail transmission in interstate commerce by public 
utilities, up to the point of local distribution. In the Open Access 
NOPR, the Commission reaffirmed this jurisdictional determination 
<SUP>515 and also addressed the distinction between transmission and 
local distribution. The Commission stated three reasons for expressing 
its views on the distinction between Commission-jurisdictional 
transmission in interstate commerce and state-jurisdictional local 
distribution, in the context of unbundled retail wheeling by public 
utilities.<SUP>516 First, facilities that can be used for wholesale 
transmission in interstate commerce by a public utility would be 
subject to the Commission's open access requirements. Second, states 
have authority to address retail stranded costs and stranded benefits 
through their jurisdiction over facilities used in local distribution. 
Third, as the structure of the industry continues to change 
dramatically, utilities need to know which regulator has jurisdiction 
over which facilities and services in order to meet state and federal 
filing requirements. Accordingly, the NOPR set forth our jurisdictional 
analysis and several technical factors, for determining what 
constitutes ``facilities used in local distribution.''
---------------------------------------------------------------------------

    \515\ That determination included the situation in which a 
former bundled retail customer may need unbundled wheeling services 
from its previous public utility generation supplier, as well as 
unbundled wheeling from one or more intervening public utilities, in 
order to reach a distant generation supplier. In that scenario, the 
Commission would have jurisdiction over all of the transmission 
facilities used for the unbundled wheeling provided by the 
intervening public utilities. The NOPR also noted that the 
Commission would not have jurisdiction over the rates for the sale 
of generation by the distant supplier because the transaction would 
be a retail sale. FERC Stats. & Regs. para. 32,514 at 33,144.
    \516\ The term ``wheeling'' is intended to cover any delivery of 
electric energy from a supplier to a purchaser, i.e., transmission, 
distribution, and/or local distribution. The Commission also has 
jurisdiction to order wholesale transmission services in either 
interstate or intrastate commerce by transmitting utilities that are 
not also public utilities. See Tex-La Electric Cooperative of Texas, 
Inc., 67 FERC para. 61,019 (1994), reh'g pending.
---------------------------------------------------------------------------

    For unbundled wholesale wheeling, the NOPR proposed to apply a 
functional test, i.e., whether the entity to whom the power is 
delivered is a lawful reseller. For unbundled retail wheeling, the NOPR 
proposed to apply a combination functional-technical test that would 
take into account technical characteristics of the facilities used for 
the wheeling. The Commission proposed seven indicators of local 
distribution to be evaluated on a case-by-case basis:

[[Page 21620]]

    (1) Local distribution facilities are normally in close proximity 
to retail customers.
    (2) Local distribution facilities are primarily radial in 
character.
    (3) Power flows into local distribution systems; it rarely, if 
ever, flows out.
    (4) When power enters a local distribution system, it is not 
reconsigned or transported on to some other market.
    (5) Power entering a local distribution system is consumed in a 
comparatively restricted geographical area.
    (6) Meters are based at the transmission/local distribution 
interface to measure flows into the local distribution system.
    (7) Local distribution systems will be of reduced voltage.<SUP>517
---------------------------------------------------------------------------

    \517\ FERC Stats. & Regs. para.32,514 at 33,145.
---------------------------------------------------------------------------

    The NOPR concluded that the application of these tests will enable 
states to address stranded costs by imposing an exit fee on departing 
retail customers, or including an adder in the retail customers' local 
distribution rates.<SUP>518
---------------------------------------------------------------------------

    \518\ Id. at 33, 144-45.
---------------------------------------------------------------------------

    In the NOPR, the Commission also addressed buy-sell transactions in 
which an end user arranges for the purchase of generation from a third-
party supplier and a public utility transmits that energy in interstate 
commerce and re-sells it as part of a ``nominal'' bundled retail sale 
to the end user. We explained that the retail sale is actually the 
functional equivalent of two unbundled sales (one transmission and the 
other the sale of power) and that we have exclusive jurisdiction over 
the voluntary sale by public utilities of unbundled transmission at 
retail in interstate commerce.<SUP>519
---------------------------------------------------------------------------

    \519\ As discussed infra, there also would be a component of 
local distribution in such a transaction that would be subject to 
state jurisdiction.
---------------------------------------------------------------------------

Comments

    Several commenters support the Commission's proposed jurisdictional 
demarcation.<SUP>520 San Diego G&E states that the Commission correctly 
proposed to look at both functional factors (such as whether the 
service is retail or wholesale) and technical factors (such as 
voltage). PG&E states that the NOPR's functional/technical test is 
preferable to a bright line voltage test.
---------------------------------------------------------------------------

    \520\ E.g., PG&E, Wisconsin Coalition, Com Ed.
---------------------------------------------------------------------------

    Consumers Power states that the Commission has exclusive 
jurisdiction over all wheeling on an interconnected interstate 
transmission grid. It suggests that the Commission and the states act 
through a joint board or hearing to resolve jurisdictional differences 
and develop a bright line test.
    PSE&G and PG&E express concern that if retail wheeling is 
implemented, there may be loopholes that would enable customers to 
evade state jurisdiction and thus avoid paying stranded costs. For 
example, PSE&G is concerned that a retail customer may request 
transmission service only and a state commission will be unable to 
attach a retail stranded cost surcharge to that customer. PG&E proposes 
adding another indicator to the functional/technical test--a final tap 
to a retail customer--to ensure that ``high-voltage'' retail customers 
do not evade the state's reach. Moreover, to ensure that retail 
customers cannot escape state jurisdiction, PG&E recommends that the 
Commission state, as a matter of policy, that ``all retail customers 
taking retail transmission service from their host utility by 
definition take service over local distribution facilities.''
    CINergy agrees with the Commission that a distinction between 
transmission and local distribution is important, but emphasizes the 
practical need for clarity on a timely basis. To achieve certainty, 
CINergy proposes that the Commission allow public utilities to file, 
under section 205, classifications of their facilities as transmission 
or local distribution. CCEM endorses CINergy's proposal. Although NARUC 
disagrees that the Commission has jurisdiction over unbundled retail 
transmission, if the Commission reaffirms the NOPR regarding its 
jurisdiction, then NARUC supports CINergy's proposal.
    PSE&G strongly supports the Commission's proposed case-by-case 
methodology for determining whether facilities should be classified as 
transmission or local distribution. SoCal Edison argues that since a 
utility may have difficulty determining which of its facilities are 
transmission and which are local distribution, utilities and states 
should be able to ask the Commission to classify a particular facility. 
Portland and Orange & Rockland suggest that the Commission provide a 
forum to resolve disputes over the correct classification of particular 
facilities.
    Ohio Edison states that the Commission should assume jurisdiction 
over unbundled retail transmission, but only where a state has required 
this unbundling. It also believes that the Commission should assert 
jurisdiction over the ancillary services necessary to provide this 
jurisdictional service.
    NYSEG argues that the Commission lacks jurisdiction over the 
transmission component of bundled retail service. On the other hand, 
NYSEG argues that the statute, legislative history, and case law reveal 
that the Commission has jurisdiction over unbundled retail wheeling 
from source to load, since it is transmission in interstate commerce. 
NYSEG argues that the ``local distribution'' exception to the 
Commission's jurisdiction applies only to bundled sales of power at 
retail.
    Several state commissions assert that states have rate authority 
over all facilities used to provide retail service.<SUP>521 IL Com 
argues that states have rate authority over all facilities used to 
provide retail service, regardless of whether the NOPR would classify 
these facilities as transmission or local distribution.
---------------------------------------------------------------------------

    \521\ E.g., NM Com, NC Com, AZ Com.
---------------------------------------------------------------------------

    MI Com, citing Connecticut Light & Power Company v. Federal Power 
Commission, 324 U.S. 515 (1945) (CL&P), and Arkansas Electric 
Cooperative v. Arkansas Public Service Commission, 461 U.S. 375, 393-94 
(1983), contends that states have plenary jurisdiction over all aspects 
of retail service, including retail access and unbundled retail 
transmission service. It asserts that the Commission's effort to expand 
federal jurisdiction into transmission in connection with retail sales 
is without statutory justification.
    Legal Environmental Assistance argues that the NOPR creates 
confusion about, and may intrude onto, state jurisdiction. NYMEX argues 
that when a state orders retail wheeling, the state should have 
jurisdiction over that transmission-only service.
    Oklahoma G&E, citing CL&P and United States v. California Public 
Utilities Commission, 345 U.S. 295, 316 (1953), asserts that the 
Commission failed to explain that the term ``transmission in interstate 
commerce'' could have different meanings depending on the factual 
context in which the term is applied. It argues that ``transmission in 
interstate commerce'' means the movement, in bulk, of electric energy 
flowing in interstate commerce, as opposed to the movement of electric 
energy that has been subdivided for delivery to consumers.
    Oklahoma G&E further argues that ``[t]he distinction between 
interconnected operation and radial operation corresponds precisely to 
this distinction between activities that have potential interstate 
effects and those that might have interstate effects but are a matter 
of primarily local concern.'' <SUP>522 Oklahoma G&E also disagrees that 
the transportation of electric energy sold at wholesale necessarily 
constitutes transmission in interstate commerce. It argues that the 
Commission has

[[Page 21621]]

misapplied case precedent and, by focusing on the level of the 
associated power sale, the Commission has misunderstood what 
constitutes a functional distinction between transmission in interstate 
commerce and local distribution.
---------------------------------------------------------------------------

    \522\ Oklahoma G&E Initial Comments at 16.
---------------------------------------------------------------------------

    NY Com asserts that the grant of jurisdiction to the Commission 
over wholesale power transactions in interstate commerce under section 
201 of the FPA does not reduce the states' authority over local 
distribution (citing CL&P and Federal Power Commission v. Florida Power 
& Light Company, 404 U.S. 453, 467 (1972)). NY Com argues that the 
NOPR's assertion of exclusive jurisdiction over all facilities used to 
deliver electricity for resale, even those traditionally regarded as 
local distribution, violates Congress' assignment of local electric 
distribution to the states. It takes issue with the Commission's list 
of factors and says that states and the Commission should agree on a 
definition that preserves the traditional classification of local 
distribution facilities. According to NY Com, such definition should 
focus on the functional characteristics of local electric systems--
i.e., electricity flows into a comparatively restricted geographic area 
and does not flow back out of that area, and the power is consumed in 
that area.
    NY IOUs argue that the Commission has jurisdiction over unbundled, 
but not bundled retail wheeling. It says that other factors, including 
the indicators listed in the NOPR, are irrelevant, and that even long-
distance interstate transmission is under state jurisdiction as long as 
it is bundled with a retail sale. According to NY IOUs, this is the 
plain meaning of the FPA; resort to legislative history is unnecessary. 
NY IOUs bases this view on section 201(a), which says that federal 
regulation extends only to matters not subject to state regulation. NY 
IOUs says that the only matters subject to state regulation were 
bundled retail sales, and that since transmission was part of the 
bundle, Congress intended transmission to stay under state authority as 
long as it is part of that bundle. It also cites section 201(b), which 
sets forth exceptions from Commission jurisdiction, and section 201(c), 
which defines ``transmission in interstate commerce'' and thus also 
controls the definition of transmission in intrastate commerce. 
Finally, NY IOUs argues that the legislative history supports its view, 
as does the case law.
    Central Louisiana believes that the costs of requiring a 
transmission provider to take unbundled transmission service for both 
wholesale and retail purposes would far exceed any benefits. In this 
regard, Central Louisiana says that states clearly have jurisdiction 
over bundled retail transmission charges and that the proposed approach 
could not be implemented without states giving up jurisdiction or the 
passage of new federal legislation.
    MN DPS disagrees on legal and policy grounds with the Commission's 
assertion of jurisdiction over unbundled retail transmission 
services.<SUP>523 It maintains that the Commission's arguments do not 
negate the language of the FPA specifying that regulation of retail 
sales of electric energy is reserved to the states. MN DPS argues that 
the Commission's arguments in support of its position are not on point 
because the issue is state authority to set rates for retail sales, not 
interstate commerce. Further, it declares that jurisdiction over a 
service does not change simply because it is priced differently.
---------------------------------------------------------------------------

    \523\ See also OH Com.
---------------------------------------------------------------------------

    Several commenters argue that unbundled pricing should not expand 
the Commission's jurisdiction.<SUP>524 NARUC argues that the NOPR did 
not explain why the Commission's authority attaches only to unbundled 
retail transmission service, why unbundling is jurisdictionally 
significant, and how transmission of electricity to end users differs 
from unbundled interstate transmission of natural gas by local 
distribution companies, which is subject to state regulation. Thus, 
NARUC urges the Commission not to claim jurisdiction over unbundled 
retail transmission services.
---------------------------------------------------------------------------

    \524\ E.g., DOD, NM Com, KY Com, ABATE.
---------------------------------------------------------------------------

    NARUC also argues that the Commission's test for distinguishing 
between transmission and local distribution is not a bright line as 
discussed in Federal Power Commission v. Southern California Edison 
Company, 376 U.S. 205 (1964) (Colton). NARUC concludes that when a 
state determines to enable a retail customer to purchase power from a 
third-party provider, that state retains the authority to regulate the 
delivery service provided by the utility.
    IL Com asserts that the test should be whether the utility function 
over which the Commission seeks to exercise jurisdiction is one which 
falls within the Attleboro gap.<SUP>525 It argues that the Commission 
has no legal authority to prescribe conditions under which a public 
utility may provide transmission service within its own service 
territory to its own retail customers. IL Com concedes that the court 
cases cited by the Commission can be interpreted to support widely 
disparate legal and policy positions, but argues that those cases 
resolved questions of Commission jurisdiction in circumstances where 
wholesale sales of electric power were being examined and not 
circumstances where retail sales are being considered. It contends that 
the question of whether the Commission should exercise jurisdiction 
over all transmission in retail wheeling has never been addressed 
before and requires a careful examination of the underlying purposes of 
Congress in enacting the FPA. IL Com explains that transmission by an 
Illinois utility of power to a retail consumer within its own service 
territory is not subject to Commission jurisdiction because that 
transmission was never within the Attleboro gap and has always been 
regulated by states.
---------------------------------------------------------------------------

    \525\ See Public Utilities Commission v. Attleboro Steam & 
Electric Company, 273 U.S. 83 (1927).
---------------------------------------------------------------------------

    OK Com recommends that the Commission apply to the electric 
industry the same policy that it has adopted concerning its regulation 
of the gas industry and leave unbundled retail service regulation to 
state authorities.
    WI Com argues that if a utility offers unbundled retail access, 
jurisdiction over transmission services should continue to be based 
upon the historical demarcation between wholesale and retail 
transactions. KY Com argues that Congress did not intend, by 
authorizing wholesale wheeling in the Energy Policy Act, to change the 
longstanding division of jurisdiction between the Commission and the 
states. It claims that the NOPR ignores the limitation in the FPA that 
the Commission has no jurisdiction over retail sales service. NV Com 
cites several cases noting the states' historical authority to regulate 
retail rates.
    IA Com proposes a definition of local distribution and transmission 
that would preserve the jurisdictional status quo and does not put a 
state commission in the position of losing authority over certain 
elements of a retail transaction should it allow retail wheeling. IA 
Com's proposed definition is as follows:

    Distribution--Service provided by a utility directly connected 
to an ultimate consumer of electricity is a distribution service 
with respect to electric energy delivered to that consumer.
    Transmission--Service provided by a utility with respect to 
electric energy to be delivered to an ultimate consumer through 
another utility is a transmission service.<SUP>526
---------------------------------------------------------------------------

    \526\ IA Com Initial Comments at 4.


    Montana Power states that a reasonable way to give effect to the 
``local distribution'' exemption is to define ``local distribution'' as 
a bundled retail sale, even if interstate facilities are used.

[[Page 21622]]

    Several commenters criticized the NOPR's functional/physical 
indicators. PA Com disagrees with the Commission's discussion of the 
FPA's legislative history and asserts that the FPA does not address the 
issue of what constitutes local distribution. PA Com contends that the 
issue was resolved by the Supreme Court in CL&P in a manner contrary to 
the Commission's technical-functional test and that the NOPR minimized 
CL&P. NM Com asserts that the proposed engineering and functional 
elements for determining the status of local distribution facilities 
fail to account for the governmental or legalistic test requirement of 
the FPA as identified in CL&P.
    KY Com concludes that a physical definition of distribution 
facilities, based on objective criteria, is consistent with the FPA and 
is necessary to provide a clean line of demarcation.
    CO Com argues that Congress used a transactional test rather than a 
functional test and that Congress intended all retail transactions to 
be under state jurisdiction. According to CO Com, there is concurrent 
jurisdiction over unbundled transmission in interstate commerce to an 
end-user. Moreover, CO Com asserts that unbundled intrastate 
transmission to a wholesale purchaser is under state jurisdiction 
(citing section 201(b)(1)). Finally, CO Com argues that the state has 
authority over unbundled transmission in intrastate commerce to an end-
user when the transmission-providing utility, end-user, and generator 
are all within the same state.
    Other commenters prefer a functional test. Natural Resources 
Defense, DOE, and Sustainable Energy Policy generally agree that a line 
needs to be drawn between transmission and local distribution but 
believe that the Commission's test is unnecessarily cumbersome or may 
lead to legal uncertainty, at least within the context of stranded 
benefits. Instead, Natural Resources Defense proposes the following 
functional test, which is based on end-use service:

    The Federal Power Act does not affect state regulators' 
jurisdiction to apply distribution charges--either volume-based or 
fixed--to electricity that is used by any utility customer to 
provide end-use services (as distinguished from electricity that is 
purchased for resale to end-use customers).<SUP>527
---------------------------------------------------------------------------

    \527\ Natural Resources Defense Initial Comments at 3.

Sustainable Energy Policy endorses Natural Resources Defense's 
position. DOE suggests that a functional definition of local 
distribution (i.e., electricity provided for end-use service) may be 
the best way to avoid legal uncertainty.
    EPA argues that the Commission's proposed physical definition may 
encourage gaming to avoid stranded costs and costs associated with 
public policy goals such as energy efficiency, renewable energy 
development and R&D funding, and a physical definition assumes that 
power flows into, and not out of, distribution systems, which would not 
allow for distributed generation (e.g., fuel cells). Thus, EPA urges 
the Commission to adopt a functional definition that ``local 
distribution occurs whenever electricity is provided by a utility for 
end-use service.'' Alternatively, EPA suggests that the Commission add 
a provision to its approach that ``the provision of electricity for 
end-use service generally involves local distribution.'' Sustainable 
Energy Policy suggests a non-bypassable charge levied on all users of 
the distribution system. It endorses the policy formulation set forth 
by Natural Resources Defense in its initial comments. Reynolds wants to 
ensure that there is always at least concurrent state jurisdiction over 
lines used to serve end-use customers, since only states can order 
retail wheeling.
    Detroit Edison argues that state/federal jurisdictional issues 
should be resolved by focusing on the use of the facilities. It says 
that facilities that are used to distribute a utility's own power to 
its own local customers should be subject to state regulation, while 
the use of facilities for wholesale power transactions or wholesale or 
retail transmission in interstate commerce should be under federal 
regulation.
    Mountain States Petroleum Assoc argues that the Commission should 
use a functional test based on state boundaries: if a line is in more 
than one state, there is Commission jurisdiction; if a line is entirely 
within one state, there is state jurisdiction.
    MD Com states that it believes that the Commission's proposed 
indicators for determining where to draw the line are adequate, but 
adds that it does not concede the Commission's assertion of 
jurisdiction over unbundled retail transmission.
    Some commenters suggest that implementation of the NOPR's tests 
could have adverse consequences. NH Com objects to the NOPR's specific 
tests; for example, if the Commission asserts jurisdiction over 
facilities because they are not radial, New Hampshire's policy of 
encouraging looping rather than radial lines would have the ironic 
effect of destroying state jurisdiction. NJ BPU states that there may 
be situations when the NOPR factors would not produce the proper 
result. It requests that the final rule recognize the need for case-by-
case flexibility in determining where federal jurisdiction ends, so 
that the Commission and the states can work cooperatively.
    NRRI argues that the NOPR's test could make siting of new 
transmission lines more difficult because states have in the past 
required native load customers to pay that part of the transmission-
related revenue requirement that is not covered by unbundled 
transmission service. NRRI contends that, if the Commission asserts 
jurisdiction over all unbundled transmission service and if there is a 
firm point-to-point service capacity right that has value and is 
reassignable, then state commissions might eliminate portions of the 
transmission systems subject to capacity rights from rate base. NRRI is 
also concerned that the NOPR's transmission/local distribution test 
could create a price squeeze between bundled and unbundled retail 
transmission rates.
    IN Com argues that the NOPR's view of jurisdiction would discourage 
retail wheeling. It says that states will be reluctant to order 
wheeling if the result is that they lose jurisdiction over the 
previously rolled-in transmission aspect of the service. It suggests 
that the Commission use negotiated rulemaking to address jurisdictional 
issues.
    Several commenters suggest alternative approaches to jurisdictional 
line-drawing. NV Com suggests that the Commission consider federal and 
state jurisdiction over transmission by using ``network'' and ``non-
network'' concepts:

    The ``network'' concept for regulation recognizes that there is 
an interstate network of electric facilities used to link generation 
with loads. The operation of that network is indifferent to whether 
the electrical flows are retail or wholesale flows. Conceptually, 
events on the network could fall under federal jurisdiction. Where 
facilities provide essential service for the delivery of power, but 
do not substantially affect the electrical flows on the network, the 
facilities fall outside the network and would remain within the 
traditional domain of the state commission. As a consequence the 
delineation of federal and state jurisdiction evolves from the 
recognition of the events and where they occur as opposed to a rigid 
consideration of the physical properties of the facilities 
involved.<SUP>528
---------------------------------------------------------------------------

    \528\ NV Com Reply Comments at 3.

NV Com further explains that the determination of what is a network 
event would require a case-by-case examination.

[[Page 21623]]

    OH Com asserts that Congress intends there to be a bright line 
between state and federal jurisdiction and that the Commission has 
failed to provide such a bright line. OH Com proposes the use of retail 
marketing areas to provide the bright line--the jurisdictional line 
would be at the point at which power enters the retail marketing area 
of the entity delivering the power to the retail customer. OH Com cites 
section 212(g) of the FPA, as amended by the Energy Policy Act, which 
provides that the Commission cannot issue any order under the FPA 
inconsistent with state law governing retail marketing areas.
    Under OH Com's proposal, the Commission would have jurisdiction 
over the wheeling-out and wheeling-through components of retail 
wheeling and the state would have jurisdiction over the wheeling-in 
component due to its local nature. OH Com concludes that the 
Commission's approach ``fails to meet the legal standard FERC must 
consider, and is inconsistent with the `savings clause' and legitimacy 
of `retail marketing areas' as discussed in the amended FPA.'' <SUP>529 
OH Com also explains that the Commission's approach ``is wreaking havoc 
on the state's ability to develop an interruptible buy-through 
arrangement to provide an increased competitive option for its retail 
customers.'' <SUP>530 OH Com further encourages the use of mutual 
deference to promote Congress' intent in mandating a system of federal/
state cooperation. In support, OH Com cites federal and state 
enforcement of telecommunications laws. NRRI also suggests that the 
jurisdictional line be drawn at the retail marketing area.
---------------------------------------------------------------------------

    \529\ Sections 212(g) and 212(h) of the FPA.
    \530\ We note that since OH Com filed its comments, it approved 
an interruptible buy-through plan. See Interruptible Electric 
Service Guidelines, Case No. 95-866-EL-UNC, __ PUR 4th __ (Ohio PUC 
Feb. 15, 1996). See also Central Illinois Light Company, Docket No. 
ER96-1075-000, 75 FERC para. ______ (1996) (accepting amendment to 
open access transmission tariffs that expands service eligibility to 
accommodate participation in experimental retail wheeling pilot 
program approved by the Illinois Commerce Commission); Illinois 
Power Company, Docket No. ER96-1285-000, 75 FERC para. ______ 
(1996); cf. Illinois Power Company, __ PUR4th __, No. 95-0494 
(Illinois Commerce Commission Mar. 13, 1996) (offering retail direct 
access service providing transmission and ancillary services using 
the rates, terms, and conditions of Illinois Power's open access 
tariff on file with the Commission); recently introduced legislation 
in Rhode Island, H.B. 8124, the Utility Restructuring Act of 1996.
---------------------------------------------------------------------------

    DC Com argues that the NOPR test is too difficult to administer and 
will create problems in determining the rate base at the state level. 
It suggests that the Commission should have jurisdiction over 
transmission from the source to the boundary of the ``home'' utility 
that delivers the power to the customer, with state jurisdiction over 
all aspects of the transmission service within that utility's franchise 
territory. AZ Com also expresses doubts that the NOPR's test is 
workable.
    Several commenters propose that the Commission and state 
authorities address the jurisdictional issue jointly. SBA characterizes 
the Commission's proposed demarcation line as ``laudable but 
misguided.'' <SUP>531 SBA recommends that a federal/state board be 
established to resolve the transmission/local distribution dilemma, 
similar to what Congress did for allocating costs between interstate 
and intrastate communications. SBA explains that the problem in the 
communications industry was the impossibility of allocating a portion 
of a single copper wire to interstate or intrastate service.
---------------------------------------------------------------------------

    \531\ SBA Initial Comments at 36.
---------------------------------------------------------------------------

    AZ Com notes that even if the Commission is correct, the FPA 
clearly does not preempt a state from concluding that retail 
transmission or other direct access programs should be implemented in 
that state. AZ Com suggests that there may be concurrent jurisdiction 
and that mutually agreed-upon principles should be implemented to 
determine which jurisdiction should be given deference.
    MD Com states that in determining the status of particular 
facilities, the Commission should give substantial weight to 
determinations made by states. ABATE states that the Commission could 
initially defer to states with respect to the determination of rates, 
terms, and conditions, while maintaining the right to review and 
overturn the state determination.
    If the Commission maintains its position concerning jurisdiction, 
NARUC argues that the Commission should not implement its multi-factor 
test, but should enter into discussions with state commissions to 
develop workable alternatives. NH Com argues that pricing the retail 
part of a transaction, even if it involves use of the transmission 
system, should be subject only to state jurisdiction. NH Com wants to 
create a mechanism by which state and federal regulators combine their 
efforts in cooperative regulation; it suggests several alternatives 
such as state/federal agreements for shared jurisdiction.
    KY Com and NRRI object to the statement in the NOPR that retail 
buy-through service is really transmission service (subject to the 
Commission's jurisdiction) plus a sale of generation at retail (subject 
to state jurisdiction). From a policy standpoint, KY Com argues that 
the Commission's approach creates a powerful disincentive for a state 
to embark on changes that otherwise might foster a more competitive 
environment. NRRI argues that the Commission's approach may violate 
sections 212(g) and 212(h).
    IL Com is concerned that industrial customers who get direct access 
may attempt to evade state jurisdiction, and thus avoid retail stranded 
cost charges, by bypassing facilities such as radial lines. It contends 
that retail wheeling rate surcharges would be a more effective means of 
recovering retail stranded costs if states were allowed to apply them 
to unbundled transmission and local distribution rates, not just the 
local distribution component of such rates.
    NC Com asserts that ``[a] significant cottage industry may well 
arise solely to convert retail customers into wholesale customers, 
thereby subverting the intent of Congress as expressly set forth in 
EPACT.'' <SUP>532 If the Commission does not adopt NARUC's proposal, 
NARUC asserts that the Commission's functional test should not permit 
an end user to bypass the distribution service provided by the utility. 
It urges the Commission to assure that there will be some facility 
involved in the transaction that will be defined as providing a local 
distribution service.
---------------------------------------------------------------------------

    \532\ NC Com Initial Comments at 7.
---------------------------------------------------------------------------

    NARUC also requests that the following sentence be added to 
proposed 18 CFR 35.27:

    Nothing in this part limits the authority of a State commission 
in accordance with State law (1) to allow or disallow the inclusion 
of the costs of electric energy purchased at wholesale in retail 
rates subject to such State commission's jurisdiction, (2) to 
establish competitive procedures for the acquisition of such 
electric energy, or (3) to establish non-discriminatory fees for the 
delivery of such electric energy to retail consumers for purposes 
established in accordance with State law.(<SUP>533)

    \533\ NARUC Reply Comments at 15-16.
---------------------------------------------------------------------------

    Duke is concerned about the potential for regulatory gaps, which 
could lead to costs not being recovered from either federal or state 
jurisdiction. Duke is also concerned that where facilities are used for 
both wholesale and retail transactions, costs might not be recovered if 
federal and state regulators use different methods of cost allocation.
    In response to the NOPR's proposal for functional 
unbundling,<SUP>534 CA Com agrees that it is important to draw a 
distinction between transmission and local distribution and that a 
bright line is not possible, but suggests that corporate or functional 
unbundling

[[Page 21624]]

might provide a means to establish a workable bright line without 
relying on the more qualitative approach proposed in the NOPR. Arizona 
argues that rather than unbundling transmission for retail purposes, 
each utility should establish a distribution function that would obtain 
transmission on behalf of retail customers, taking service under the 
utility's tariff. Arizona states that this would simplify the 
allocation of transmission costs, since all transmission costs would be 
under the Commission's jurisdiction. Arizona argues that the Commission 
should permit the utility to recover the distribution rate approved by 
the state. According to Arizona, this would create a bright line 
between state and federal jurisdiction.
---------------------------------------------------------------------------

    \534\ FERC Stats. & Regs. para. 32,514 at 33,080-83.
---------------------------------------------------------------------------

    TX Com argues that the proposed test would not be applicable to 
intrastate utilities in Texas because they do not operate in interstate 
commerce. Thus, it asserts that it should continue to regulate Electric 
Reliability Council of Texas (ERCOT) transmission and distribution 
service and deal with stranded cost issues that arise in connection 
with any retail wheeling initiatives.
    Several commenters object to the Commission's proposal to assert 
jurisdiction over transactions that are buy-sell transactions in name 
only.<SUP>535 AEP argues that the Commission should avoid an 
unnecessary conflict over state/federal jurisdiction that may be caused 
by the NOPR's statement that buy-sell transactions are in fact 
transmission subject to Commission jurisdiction. It suggests that the 
Commission attempt to reach agreement with the states on this matter or 
ask Congress for any necessary statutory change. Citizens Utilities 
also argues that the Commission should not unbundle the interstate 
transmission aspect of buy-sell transactions. It says that, unlike the 
analogous gas contracts, buy-sell arrangements on the electric side are 
not an end run around clear federal jurisdiction. Further, it argues 
that it would be very difficult to define those buy-sell transactions 
that truly belong under federal jurisdiction.
---------------------------------------------------------------------------

    \535\ See id. at 33,082.
---------------------------------------------------------------------------

    IL Com also objects to the NOPR's characterization of buy-sell 
transactions. It argues that the fact that a transaction becomes 
unbundled does not suddenly make part of it under federal jurisdiction. 
Nucor argues that there is no need for the Commission to resolve this 
issue now; it suggests that the buy-sell arrangement is only 
tangentially related to open access. It argues that each buy-sell 
transaction will have to be addressed individually.
    UT Com seeks clarification as to what the Commission means by buy-
sell arrangements:

we currently authorize interruptible ``buy-through'' contracts, 
through which a retail customer, taking service subject to 
interruption for either economic or technical reasons, can opt to 
``buy-through'' an interruption. The public utility purchases energy 
on behalf of the customer and sells it at cost to the customer. In 
our opinion, such transactions are not an example of a buy-sell 
transaction within the meaning of the proposed rule.<SUP>536
---------------------------------------------------------------------------

    \536\ UT Com Initial Comments at 4-5.

    DOD objects to the statement in the NOPR that ``buy-sell'' 
transactions are not really bundled retail service. It says that this 
view will discourage the development of innovative state programs, such 
as direct access programs. NYSEG also argues that buy-sell transactions 
are not under the Commission's jurisdiction. It argues that these 
transactions are unlike buy-sell transactions on the gas side, where 
the Commission asserted jurisdiction to prevent LDCs from circumventing 
the nondiscrimination standard it imposed on the release of capacity. 
---------------------------------------------------------------------------
NYSEG says:

    In contrast to its regulation of gas buy-sells, if the 
Commission regulates electric buy-sell transactions it would forego 
regulation of a transaction in which the Commission has a 
significant interest (i.e., access to the upstream seller's 
transmission), to regulate a transaction in which the Commission has 
virtually no interest (i.e., access to the distributing utility's 
system). Electric utilities must serve each retail customer 
irrespective of whether the customer takes traditional bundled 
service or retail buy-sell service. Unlike excess upstream gas 
pipeline capacity, the capacity on the local utility's electric 
system would not be allocated to another customer in a FERC 
jurisdictional transaction absent the electric buy-sell transaction. 
Electric buy-sell transactions are not designed so as to manipulate 
the assignment of upstream transmission capacity. Consequently, the 
impetus for FERC to reclassify gas buy-sell transactions as capacity 
assignments is not present in the electric context.<SUP>537
---------------------------------------------------------------------------

    \537\ NYSEG Initial Comments at 48 (footnote omitted).

    NYSEG argues that there are only two possible grounds for the 
Commission's assertion of jurisdiction over electric buy-sell 
transactions: either (1) the sale for resale by the supplier is really 
a sale at retail to the end user, and the resale by the local utility 
is really unbundled retail wheeling; or (2) the Commission has 
jurisdiction over transmission service that is part of bundled retail 
service. It claims that the second ground is invalid because the 
transmission aspect of bundled retail service is distribution. It also 
claims that the first ground is invalid because it assumes that the 
sale by the supplier to the local utility is not a sale for resale even 
---------------------------------------------------------------------------
though the contract says that it is. NYSEG states:

    The logical outcome would be that FERC would not have 
jurisdiction over the sale by the supplier to the utility, including 
transmission by that supplier because it would be a bundled retail 
sale. This is because, if the commission holds the resale to be a 
retail wheel, then it would have to find that the sale by the 
supplier is a retail sale to the end user. The Commission cannot at 
once regulate the sale for resale and the ``retail transmission 
service.'' The Commission would regulate the transmission rates of 
the local franchise utility, although it would not regulate the 
access to such transmission service--a matter FERC leaves to state 
regulators. In the process, FERC would abandon the ability to 
regulate access to the supplier's bundled ``retail power sale and 
transmission service,'' a transaction that FERC arguably has an 
interest in regulating.<SUP>538
---------------------------------------------------------------------------

    \538\ NYSEG Initial Comments at 50.

Finally, NYSEG argues that if the Commission insists on asserting 
jurisdiction, it should at least grandfather existing contracts.
    UT Industrials state that where there is a state barrier to a buy-
sell transaction, the Commission should allow the utility to file a 
tariff with the Commission that would permit the utility to complete a 
voluntary buy-sell transaction as the NOPR proposes. However, it 
contends that when a state regulatory authority is authorized to, and 
has approved buy-sell transactions, it is not necessary for the 
Commission to become involved. It urges the Commission to allow such 
transactions to take place free of Commission regulation.
Commission Conclusion
    In the discussion below, the Commission addresses the following 
jurisdictional issues raised in the prior NOPRs:

    a. Does the Commission have jurisdiction over unbundled 
transmission in interstate commerce by a public utility when such 
transmission is used to transport electric energy that is sold to an 
end user?
    b. If so, what facilities are jurisdictional to the Commission 
in a situation involving the unbundled delivery in interstate 
commerce by a public utility of electric energy from a third-party 
supplier to an end user?
    c. What facilities are jurisdictional to the Commission in a 
situation involving the unbundled delivery in interstate commerce by 
a public utility of electric energy from a third-party supplier to a 
purchaser who will then re-sell the energy to an end user?

[[Page 21625]]

    d. What procedures are appropriate for making jurisdictional 
determinations?

    In addition, the Commission addresses concerns raised by state 
regulators which indicate that competition and open access are 
perceived as threatening the traditional regulatory functions of state 
commissions. The Federal Power Act differentiates between state and 
federal regulation of electric power. As we discuss below, the 
Commission believes that any change in state or federal jurisdiction 
over physical transmission assets and related costs will not affect the 
traditional tasks of state and federal regulators.
    The wide range of jurisdictional interpretations and proposals in 
the comments reflects the fact that the legislative history of the FPA 
and case law interpreting federal/state jurisdiction under that Act and 
the Natural Gas Act grew out of a market structure in which electricity 
and transmission generally were bought and sold on a bundled basis. As 
a result, most transactions included either a retail or wholesale sale 
of electric energy and jurisdictional lines were drawn on the basis of 
this sale. Thus, the cases simply do not resolve dispositively these 
jurisdictional issues when they arise in the context of the market 
structures and unbundled transactions being contemplated in today's 
electric industry. However, after reviewing the extensive analysis of 
the FPA, legislative history, and case law contained in both our 
initial Stranded Cost NOPR and in our Open Access NOPR, and the 
comments received on that analysis, we continue to believe that we were 
correct in asserting jurisdiction over the transmission component of an 
unbundled interstate retail wheeling transaction. We therefore reaffirm 
our conclusion. We also reaffirm and clarify our determinations 
regarding the tests to be used to determine what constitute Commission-
jurisdictional transmission facilities and what constitute state-
jurisdictional local distribution facilities in situations involving 
unbundled wholesale wheeling and unbundled retail wheeling.<SUP>539
---------------------------------------------------------------------------

    \539\ Not only do we conclude that our determinations are 
legally supportable under the case law, but we believe it is 
imperative to provide guidance to public utilities and state 
regulators as to our position on where the jurisdictional boundaries 
lie.
---------------------------------------------------------------------------

    At the same time, the Commission strongly supports the efforts of 
states to pursue pro-competitive policies. We recognize that 
jurisdictional issues raise overlapping Federal and state policy 
concerns that call for heightened cooperation among federal and state 
regulators. As discussed below, where states unbundle retail sales, we 
will give deference to their determinations as to which facilities are 
transmission and which are local distribution, provided that the 
states, in making such determinations, apply the seven criteria 
discussed in the NOPR and reaffirmed below. In addition, we clarify our 
view that there is an element of local distribution service in any 
unbundled retail transaction, and further clarify other aspects of our 
jurisdictional ruling to preserve state jurisdiction over matters that 
are of local concern and will remain subject to state jurisdiction if 
retail unbundling occurs.
    We first address our legal determination that if unbundled retail 
transmission in interstate commerce occurs voluntarily by a public 
utility or as a result of a state retail access program, this 
Commission has exclusive jurisdiction over the rates, terms, and 
conditions of such transmission. No commenter has raised cases or 
legislative history not previously considered in our prior NOPRs, and 
we will not repeat here our full legal analysis of this issue.<SUP>540 
However, we find compelling the fact that section 201 of the FPA, on 
its face, gives the Commission jurisdiction over transmission in 
interstate commerce (by public utilities) without 
qualification.<SUP>541 Unlike our jurisdiction over sales of electric 
energy, which section 201 of the FPA specifically limits to sales at 
wholesale, the statute does not limit our transmission jurisdiction 
over public utilities to wholesale transmission.
---------------------------------------------------------------------------

    \540\ The Commission's complete legal analysis on this issue, 
and on the related issue of what facilities are Commission-
jurisdictional transmission facilities, and what are state 
jurisdictional local distribution facilities, are contained in 
Appendix G to this Rule.
    \541\ Section 201(b)(1) specifically exempts from Commission 
jurisdiction facilities used for transmission in intrastate commerce 
and transmission of electric energy consumed wholly by the 
transmitter. As a result, we have no jurisdiction over retail 
wheeling that occurs in Alaska, Hawaii and the Electric Reliability 
Council (ERCOT) portion of Texas since transactions in those areas 
are intrastate.
---------------------------------------------------------------------------

    In response to those commenters (including NARUC) who argue that 
the Commission did not explain why its authority attaches only to 
unbundled, but not bundled, retail transmission in interstate commerce 
by public utilities, we believe 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. Under 
the FPA, the Commission's jurisdiction over sales of electric energy 
extends only to wholesale sales. However, when a retail transaction is 
broken into two products that are sold separately (perhaps by two 
different suppliers: an electric energy supplier and a transmission 
supplier), we believe the jurisdictional lines change. In this 
situation, the state clearly retains jurisdiction over the sale of the 
power. However, the unbundled transmission service involves only the 
provision of ``transmission in interstate commerce'' which, under the 
FPA, is exclusively within the jurisdiction of the Commission. 
Therefore, when a bundled retail sale is unbundled and becomes separate 
transmission and power sales transactions, the resulting transmission 
transaction falls within the Federal sphere of regulation.
    In asserting jurisdiction over unbundled retail transmission in 
interstate commerce by public utilities, the Commission in no way is 
asserting jurisdiction to order retail transmission directly to an 
ultimate consumer. Section 212(h) of the FPA clearly prohibits us from 
doing so. In addition, as stated in both the initial Stranded Cost NOPR 
and the Open Access NOPR, we do not address whether states have 
authority to order retail wheeling in interstate commerce. The 
Commission's assertion of jurisdiction is that if retail transmission 
in interstate commerce by a public utility occurs voluntarily or as a 
result of a state retail wheeling program, the Commission has exclusive 
jurisdiction over the rates, terms, and conditions of such transmission 
and public utilities offering such transmission must comply with the 
FPA by filing proposed rate schedules under section 205.
    The Commission clarifies that nothing in this jurisdictional 
determination changes historical state franchise areas or interferes 
with state laws governing retail marketing areas of electric utilities. 
Section 212(g) of the FPA prohibits Commission orders that would be 
inconsistent with such laws. However, we reject arguments made by some 
of the commenters that section 212(g) could somehow be construed to 
give states authority over the rates, terms, and conditions of 
unbundled interstate transmission within retail marketing 
areas.<SUP>542 While our

[[Page 21626]]

jurisdiction cannot affect whether and to whom a retail electric 
service territory (marketing area) is to be granted by the state, and 
whether such grant is exclusive or non-exclusive, neither can state 
jurisdiction affect this Commission's exclusivejurisdiction over 
transmission in interstate commerce by public utilities.
---------------------------------------------------------------------------

    \542\ The legislative history of FPA section 212(g) and its 
predecessor, former section 211(c)(3), indicates that the provision 
was focused on not interfering with state laws governing retail 
service territories and not permitting Commission wheeling orders 
``for purposes of sale by a utility to an ultimate consumer who is 
within the service territory of another utility (other than the 
applicant) where such territory is established by or under State 
law, rule, or decision.'' See H.R. Conf. Rep. No. 1750, 95th Cong., 
2d Sess. 92 (1978), reprinted in 1978 U.S. Code Cong. & Ad. News 
7797, 7826. Nothing on the face of section 212(g) or the legislative 
history of either the Energy Policy Act or PURPA indicates that the 
provision in any way affects the Commission's authority over rates, 
terms, and conditions of transmission in interstate commerce by 
public utilities.
---------------------------------------------------------------------------

    In response to several of the commenters, we further clarify that 
the Commission's jurisdiction over the rates, terms, and conditions of 
unbundled retail transmission is no broader than our authority over 
transmission used for wholesale transactions, and will not affect 
matters otherwise left to the states by Congress.<SUP>543 The Federal 
Power Act recognizes that retail marketing areas are governed by state 
law. Moreover, we believe that states have authority over the service 
of delivering electric energy to end users. In exercising this 
authority, state regulatory commissions and state legislatures have 
traditionally developed social and environmental programs suited to the 
circumstances of their states. State regulation of most power 
production and virtually all distribution and consumption of electric 
energy is clearly distinguishable from this Commission's responsibility 
to ensure open and non-discriminatory interstate transmission service. 
Nothing adopted by the Commission today, including its interpretation 
of its authority over retail transmission or how the separate 
distribution and transmission functions and assets are discerned when 
retail service is unbundled, is inconsistent with traditional state 
regulatory authority in this area.
---------------------------------------------------------------------------

    \543\ Among other things, Congress left to the States authority 
to regulate generation and transmission siting. See FPA sections 
201(b) and 211(d)(1); section 731 of the Energy Policy Act.
---------------------------------------------------------------------------

    The Commission reiterates its strong interest in preventing any 
balkanization of the interstate power market. Although the Commission 
believes its Final Rule will accommodate retail competition, if it is 
offered voluntarily by a utility or ordered by a state, our policies 
relate only to the bulk power market and not traditional state 
regulation of the retail market.<SUP>544
---------------------------------------------------------------------------

    \544\ This Final Rule will not affect or encroach upon state 
authority in such traditional areas as the authority over local 
service issues, including reliability of local service; 
administration of integrated resource planning and utility buy-side 
and demand-side decisions, including DSM; authority over utility 
generation and resource portfolios; and authority to impose non-
bypassable distribution or retail stranded cost charges.
---------------------------------------------------------------------------

    NARUC has requested that the Commission specifically clarify in 
Sec. 35.27 of its proposed rules <SUP>545 that nothing in our final 
rule limits the authority of a state commission ``to allow or disallow 
the inclusion of the costs of electric energy purchased at wholesale in 
retail rates subject to such State commission jurisdiction.'' We will 
adopt NARUC's proposal with modification, but add it as a separate 
subsection. The Final Rule adopts a new Sec. 35.27(b) as follows:


    \545\ Section 35.27 of the proposed rules provided that any 
public utility seeking authorization to engage in sales for resale 
at market-based rates shall not be required to demonstrate any lack 
of market power in generation with respect to sales from capacity 
first placed in service on or after 30 days from the date of 
publication of the Final Rule in the Federal Register. FERC Stats. & 
Regs. para. 32,514 at 33,154.
---------------------------------------------------------------------------

    Nothing in this part (i) shall be construed as preempting or 
affecting any jurisdiction a state commission or other state 
authority may have under applicable state and federal law, or (ii) 
limits the authority of a state commission in accordance with state 
and federal law to establish (a) competitive procedures for the 
acquisition of electric energy, including demand-side management, 
purchased at wholesale, or (b) non-discriminatory fees for the 
distribution of such electric energy to retail consumers for 
purposes established in accordance with state law.


    With respect to the Commission's adoption of the Open Access NOPR's 
functional/technical tests for determining what facilities are 
Commission-jurisdictional facilities used for transmission in 
interstate commerce and what facilities are state-jurisdictional local 
distribution facilities, the case law supports a bright line for 
unbundled wholesale transmission, i.e., transmission of electric energy 
that is being sold for resale. This is consistent with the bright line 
drawn by Congress to fill the Attleboro gap for regulating wholesale 
sales of electric energy. The case law also supports a bright line with 
respect to retail transmission by intervening utilities, i.e., 
transmission by those utilities between the new retail generation 
supplier and the public utility that previously provided bundled retail 
service to the end user. However, despite many commenters' arguments to 
the contrary, we cannot divine such a bright line for unbundled retail 
transmission by the public utility that previously provided bundled 
retail service to the end user. In fact, the limited case law, 
including CL&P and Colton, supports a case-by-case 
determination.<SUP>546 Accordingly, we believe our technical test, with 
its seven indicators, will permit reasoned factual determinations in 
individual cases.
---------------------------------------------------------------------------

    \546\ As noted, the Commission's detailed legal analysis is 
contained in Appendix G. We are particularly persuaded by the 
Supreme Court's statement that whether facilities are used in local 
distribution is a question of fact to be decided by the Commission 
as an original matter. See CL&P, 515 U.S. at 534-35.
---------------------------------------------------------------------------

    Although we are unable to draw the bright line for local 
distribution facilities that many commenters would like, we believe it 
is important to make two clarifications regarding local distribution in 
the context of retail wheeling. First, even when our technical test for 
local distribution facilities identifies no local distribution 
facilities for a specific transaction, we believe that states have 
authority over the service of delivering electric energy to end users. 
Second, through their jurisdiction over retail delivery services, 
states have authority not only to assess stranded costs but also to 
assess charges for stranded benefits, such as low-income assistance and 
demand-side management. Because their authority is over services, not 
just the facilities, states can assign stranded costs and benefits 
based on usage (kWh), demand (kW), or any combination or method they 
find appropriate. They do not have to assign them to specific 
facilities.<SUP>547
---------------------------------------------------------------------------

    \547\ As noted above, states retain authority over state 
integrated resource planning, utility resource portfolios, and 
utility buy-side and demand-side decisions.
---------------------------------------------------------------------------

    Thus, while we believe in most cases there will be identifiable 
local distribution facilities subject to state jurisdiction, we also 
believe that even where there are no identifiable local distribution 
facilities, states nevertheless have jurisdiction in all circumstances 
over the service of delivering energy to end users. Under this 
interpretation of state/federal jurisdiction, customers have no 
incentive to structure a purchase so as to avoid using identifiable 
local distribution facilities in order to bypass state jurisdiction and 
thus avoid being assessed charges for stranded costs and benefits.
    Based on concerns raised by state commissions as well as some 
utilities, we have further determined that it is appropriate to provide 
deference to state commission recommendations regarding certain 
transmission/local distribution matters that arise when retail wheeling 
occurs. We also believe it is important to develop mechanisms to avoid 
regulatory conflict and to help provide certainty to utilities as to 
which regulator has jurisdiction over which facilities. These are 
discussed below.

[[Page 21627]]

    Determining where to draw the jurisdictional line for facilities 
used in unbundled retail wheeling transactions will involve case-
specific determinations that evaluate the seven local distribution 
indicators that we are adopting. We believe that the Commission should 
take advantage of state regulatory authorities' knowledge and expertise 
concerning the facilities of the utilities that they regulate. 
Therefore, in instances of unbundled retail wheeling that occurs as a 
result of a state retail access program, we will defer to 
recommendations by state regulatory authorities concerning where to 
draw the jurisdictional line under the Commission's technical test for 
local distribution facilities, and how to allocate costs for such 
facilities to be included in rates, provided that such recommendations 
are consistent with the essential elements of the Final Rule.<SUP>548 
Moreover, we recognize that in some cases the Commission's seven 
technical factors may not be fully dispositive and that states may find 
other technical factors that may be relevant. We will consider 
jurisdictional recommendations by states that take into account other 
technical factors that the state believes are appropriate in light of 
historical uses of particular facilities.
---------------------------------------------------------------------------

    \548\ In order to give such deference, we expect state 
regulators to specifically evaluate the seven indicators and any 
other relevant facts and to make recommendations consistent with the 
essential elements of the Rule.
---------------------------------------------------------------------------

    Some commenters have asked the Commission to provide a forum to 
prevent or resolve disputes over the correct classification of 
facilities as transmission or local distribution. As a means of 
facilitating jurisdictional line-drawing, we will entertain proposals 
by public utilities, filed under section 205 of the FPA, containing 
classifications and/or cost allocations for transmission and local 
distribution facilities. However, as a prerequisite to filing 
transmission/local distribution facility classifications and/or cost 
allocations with the Commission, utilities must consult with their 
state regulatory authorities. If the utility's classifications and/or 
cost allocations are supported by the state regulatory authorities and 
are consistent with the principles established in the Final Rule, the 
Commission will defer to such classifications and/or cost 
allocations.<SUP>549 We encourage public utilities and their state 
regulatory authorities to attempt to agree to utility-specific 
classifications and allocations that the utility may file at the 
Commission.
---------------------------------------------------------------------------

    \549\ This should also alleviate some concerns about the 
potential for costs not being accounted for if the Commission and a 
state commission use different methods of allocating costs.
---------------------------------------------------------------------------

    A number of commenters have asked the Commission to defer to state 
commission recommendations or decisions regarding rates, terms and 
conditions of unbundled retail transmission in interstate commerce by 
public utilities. Some have suggested that we set broad guidelines for 
such rates, terms, and conditions, and then allow states to actually 
implement the guidelines. While the Commission cannot simply turn over 
its jurisdiction for the states to implement, we understand the 
concerns raised by many state regulators and believe that deference to 
state commissions with regard to rates, terms, and conditions may be 
appropriate in some circumstances, as discussed below.
    As we determined in the NOPR, when unbundled retail wheeling in 
interstate commerce occurs, the transaction has two components for 
jurisdictional purposes--a transmission component and a local 
distribution component. The Commission has jurisdiction over facilities 
used for the transmission component of the transaction, and the state 
has jurisdiction over facilities used for the local distribution 
component.<SUP>550 Thus, the rates, terms and conditions of unbundled 
retail transmission by a public utility must be filed at the 
Commission. When this occurs, we will generally expect unbundled retail 
wheeling customers to take service under the same FERC tariff that 
applies to wholesale customers. However, if the unbundled retail 
wheeling occurs as part of a state retail access program, it may be 
appropriate to have a separate retail transmission tariff <SUP>551 to 
accommodate the design and special needs of such programs. In such 
situations, the Commission will defer to state requests for variations 
from the FERC wholesale tariff to meet these local concerns, so long as 
the separate retail tariff is consistent with the Commission's open 
access policies and comparability principles reflected in the tariff 
prescribed by this Final Rule. In addition, rates must be consistent 
with our Transmission Pricing Policy Statement, and the guidance herein 
concerning ancillary services.<SUP>552
---------------------------------------------------------------------------

    \550\ As discussed above, even if there were instances where no 
local distribution facilities are used, we believe states have 
authority over the service of delivering electric energy to end 
users.
    \551\ I.e., the tariff would be different from the tariff that 
applies to wholesale customers. Such tariff would still be filed 
with the Commission under FPA section 205.
    \552\ In applying the principles of the Final Rule to retail 
transmission tariffs, the Commission clearly cannot order retail 
wheeling directly to an ultimate consumer. See FPA section 212(h).
---------------------------------------------------------------------------

    A final jurisdictional issue raised in the Open Access NOPR 
concerns buy-sell transactions. We remain concerned, just as we were 
with buy-sell arrangements in the gas industry, that buy-sell 
arrangements can be used by parties to obfuscate the true transactions 
taking place and thereby allow parties to circumvent Commission 
regulation of transmission in interstate commerce. Thus, we reaffirm 
our conclusion that we have jurisdiction over the interstate 
transmission component of transactions in which an end user arranges 
for the purchase of generation from a third-party. However, we 
recognize that there is a wide range of programs and transactions that 
might or might not fall within this category. We will address these on 
a case-by-case basis.
    In summary, the Commission reaffirms and clarifies its prior 
jurisdictional conclusions and tests for determining the demarcation 
between federal and state jurisdiction over transmission in interstate 
commerce and local distribution. We have attempted to address these 
issues in a way that provides for flexibility and recognition of 
legitimate state concerns. With regard to retail services, we recognize 
the states' concerns that the unbundling of retail transactions would 
result in changes from what historically has been regulated by the 
states (principally, the rates of transmission assets previously 
included in retail rate base). However, the decision to provide 
unbundled retail wheeling is not the Commission's to make because we 
have no authority to order transmission directly to an ultimate 
consumer. In addition, even if a retail access program occurs, we do 
not believe the unbundling of retail transactions will radically change 
fundamental state authorities, including authority to regulate the vast 
majority of generation asset costs, the siting and maintenance of 
generation facilities and transmission lines, and decisions regarding 
retail service territories. Further, the Commission intends to be 
respectful of state objectives so long as they do not balkanize 
interstate transmission of power or conflict with our interstate open 
access policies. As the electric industry and state regulatory 
authorities continue to develop new competitive market structures and 
consider retail wheeling programs, we believe that the tests and 
mechanisms we have provided in this Rule will accommodate both Federal 
and state interests and will help provide jurisdictional certainty to 
market participants.

[[Page 21628]]

J. Stranded Costs

1. Justification for Allowing Recovery of Stranded Costs
    In the Supplemental Stranded Cost NOPR, the Commission noted that 
the Open Access Rule would give a utility's historical wholesale 
customers greatly enhanced opportunities to reach new 
suppliers.<SUP>553 This would affect the way in which utilities have 
recovered costs under the traditional regulatory system that, on the 
one hand, imposed an obligation to serve,<SUP>554 and, on the other 
hand, permitted recovery of all prudently incurred costs. We noted that 
if customers leave their utilities' generation systems without paying a 
share of these costs, the costs will become stranded unless they can be 
recovered from other customers. The Commission stated in the NOPR that 
we must address the costs of the transition to a competitive industry 
by allowing utilities to recover their legitimate, prudent and 
verifiable stranded costs simultaneously with any final rule we adopt 
requiring open access transmission.<SUP>555
---------------------------------------------------------------------------

    \553\ FERC Stats. & Regs. para. 32,514 at 33,095.
    \554\ The Supplemental Stranded Cost NOPR described such an 
obligation as explicit at retail and arguably implicit at wholesale. 
FERC Stats. & Regs. para. 32,514 at 33,101.
    \555\ Id. at 33,095-96, 33,101.
---------------------------------------------------------------------------

Comments
    Virtually all of the investor-owned utility commenters as well as 
commenters representing state commissions and other constituencies 
support the NOPR's premise that stranded costs can be created when a 
customer switches suppliers. They endorse the proposal to allow the 
recovery of legitimate and verifiable stranded costs.<SUP>556 Numerous 
commenters also support the Commission's proposal to link stranded cost 
recovery with open access tariffs. These commenters agree that the 
recovery of stranded costs is critical to the successful transition of 
the industry to an open transmission access, competitive 
industry.<SUP>557 Commenters such as EEI and NU submit that open access 
and stranded cost recovery should be implemented simultaneously; that 
unbundled transmission service should not be required until a stranded 
cost recovery mechanism is in place. Some commenters propose that if 
the full recovery of stranded costs is disallowed as a result of 
rehearing or judicial review, utilities that have filed open access 
transmission tariffs should be permitted to withdraw them, or the 
Commission should otherwise reconsider its rule on open access 
transmission in light of such a reversal.<SUP>558
---------------------------------------------------------------------------

    \556\ See, e.g., EEI, Atlantic City, Arizona, Carolina P&L, 
Centerior, Central Hudson, Detroit Edison, Duke, Duquesne, Entergy, 
Florida Power Corp, El Paso, Houston, NIPSCO, NU, Oklahoma G&E, 
Otter Tail, PG&E, Puget, Southern, San Diego G&E, SCE&G, SoCal 
Edison, Montana, Montana-Dakota Utilities, NSP, Utilities For 
Improved Transition, NC Com, PA Com, Electric Consumers Alliance, 
American National Power, NE Public Power District, MEAG, OH Coops, 
Seattle, NY Energy Buyers, SBA, TVA, Utility Workers Union, Big 
Rivers EC, Central EC, Citizens Lehman, NGSA, AGA, Montaup, NIEP.
    \557\ See, e.g., EEI, Coalition for Economic Competition, EGA, 
CINergy, Electric Consumers Alliance, Atlantic City, Com Ed, 
Consumers Power, Dayton P&L, Dominion, Duke, El Paso, NEPCO, NIMO, 
NIPSCO, Ohio Edison, Florida Power Corp, PECO, Pennsylvania P&L, 
PSNM, Public Service Co of CO, Southern, SCE&G, VEPCO, Texas 
Utilities, DOE, CA Energy Com, CO Com, PA Com, NE Public Power 
District, SMUD, Brazos, Sunflower, PJM, Utility Workers Union, 
Utility Investors Analysts, Nuclear Energy Institute, SoCal Gas, 
AGA, Utility Shareholders, LPPC. Although DOD agrees that addressing 
stranded costs is a critical part of the transition to a more 
competitive industry, it submits that there is nothing in the Open 
Access NOPR that should affect the treatment of stranded costs 
because the Open Access NOPR would not change the contracts that 
govern existing wholesale transactions. It argues that the 
Commission will have ample opportunity to decide these matters 
before the present wholesale long-term contracts expire.
    \558\ E.g., Utilities For Improved Transition, PECO, Utility 
Workers Union, Dayton P&L.
---------------------------------------------------------------------------

    Commenters representing the financial community reiterate their 
strong support for the full recovery of stranded costs, noting that the 
prospect of not recovering stranded costs could erode a utility's 
ability to attract capital which, in turn, could impede the long-term 
goal of achieving competitive wholesale markets.<SUP>559 Several 
commenters also argue that stranded cost recovery is economically 
efficient and is necessary to ensure parity among competitors and to 
avoid uneconomic bypass.<SUP>560
---------------------------------------------------------------------------

    \559\ Utility Investors Analysts, Utility Shareholders.
    \560\ See, e.g., EEI, SCE&G, Montana, Com Ed.
---------------------------------------------------------------------------

    The commenters that oppose allowing utilities to recover legitimate 
and verifiable stranded costs repeat many of the arguments that were 
raised in response to the initial Stranded Cost NOPR. For example, a 
number of commenters argue that the risk that a utility could lose 
customers (and thereby incur stranded costs) is not a new phenomenon 
created by regulatory and statutory initiatives that utilities could 
not have anticipated.<SUP>561 Some commenters argue that there was 
never an implied obligation to serve at wholesale.<SUP>562 According to 
TDU Systems, monopoly power, not regulatory obligation, has kept 
wholesale customers captive over the years.
---------------------------------------------------------------------------

    \561\ E.g., TAPS, IN Industrials, Air Liquide, Texas 
Industrials, Detroit Edison Customers, AMP-Ohio.
    \562\ E.g., TDU Systems, Competitive Enterprise.
---------------------------------------------------------------------------

    Other commenters argue that allowing the recovery of stranded costs 
would make it uneconomic for customers to seek alternative sources of 
power and that the prospect of liability for and protracted litigation 
over stranded cost claims would create paralyzing uncertainty for 
customers, uncertainty that may dissuade them from taking advantage of 
new opportunities in the wholesale power market.<SUP>563 Some 
commenters also argue that stranded cost recovery would be a 
disincentive to efficient operation by affording the greatest 
protection to utilities that made the worst investment 
decisions.<SUP>564
---------------------------------------------------------------------------

    \563\ See, e.g., Missouri Joint Commission, Omaha PPD, American 
Forest & Paper, TAPS, AMP-Ohio, Kansas Commission, VA Com, Nucor, 
Torco, IPALCO, DE Muni, Municipal Energy Agency Nebraska, Air 
Liquide, Arkansas Cities, Detroit Edison Customers, Cleveland, 
Texas-New Mexico, Blue Ridge, Suffolk County, NM Industrials, PA 
Munis, Caparo, ABATE, NRRI, Building Owners, Alma, WEPCO, Total 
Petroleum. SC Public Service Authority asserts that the Commission 
has not adequately addressed the anticompetitive potential of exit 
fees and the potential shifting of losses from high-cost to low-cost 
producers. It says that the Commission should renotice any further 
proposal that it develops to permit a reasoned analysis of 
anticompetitive concerns.
    \564\ E.g., TAPS, AMP-Ohio, IPALCO, Suffolk County, Competitive 
Enterprise, NY Energy Buyers, Supervised Housing, Central Illinois 
Light, WP&L, SC Public Service Authority, KS Com.
---------------------------------------------------------------------------

    Commenters also argue that the scope of the proposed rule is 
overbroad; that stranded cost recovery should be allowed, if at all, on 
a case-by-case basis; that there should be no presumption that every 
utility will experience stranded costs; and that utilities should not 
be allowed to recover 100 percent of prudently incurred stranded 
costs.<SUP>565
---------------------------------------------------------------------------

    \565\ E.g., Alma, IPALCO, Suffolk County, CO Consumers Counsel, 
Arkansas Cities, Central Illinois Light, NY AG, NASUCA, VA Com, NY 
Energy Buyers, UT Industrials, NM Industrials, NJ Ratepayer 
Advocate, WEPCO, IN Industrials, ABATE, AZ Com.
---------------------------------------------------------------------------

    Several commenters suggest that there is no factual basis for the 
stranded cost rule, citing a lack of evidence of a wholesale stranded 
cost problem.<SUP>566 TDU Systems refers to a Resource Data 
International study that shows that, of $114 billion in potential 
investor-owned utility stranded investment, only $10.4 billion is 
associated with wholesale transactions.<SUP>567 Others submit that the

[[Page 21629]]

Commission should obtain more current data concerning the magnitude of 
potential stranded cost recovery before issuing the final rule.<SUP>568 
In reference to the statement in the Supplemental NOPR that the 
Commission will continue to gather information on the magnitude of 
potential stranded costs,<SUP>569 DE Muni states that the Commission 
must commit to making public all the data it obtains so that all can 
evaluate the impact of the recovery of stranded costs on an ongoing 
basis.
---------------------------------------------------------------------------

    \566\ E.g., ELCON, TDU Systems, Texas-New Mexico, Central 
Illinois Light.
    \567\ However, Utilities for Improved Transition refers to a 
report by Moody's Investor Service estimating that the stranded 
costs of the Nation's 114 largest electric utilities under open 
access transmission will be $135 billion in the next ten years (13 
to 14 times greater than the costs stranded by the introduction of 
open access transportation of natural gas). It notes that this 
estimate covers costs stranded by transmission in interstate 
commerce of both wholesale and retail power, and submits that both 
types of costs are relevant to this proceeding because of the 
Commission's jurisdiction over the transmission rates for wheeling 
to both wholesale and retail customers.
    \568\ E.g., Central Illinois Light, Utility Workers Union, 
Alcoa.
    \569\ See FERC Stats. & Regs. para. 32,514 at 33,105.
---------------------------------------------------------------------------

    NRRI submits that the Commission has drawn the wrong conclusion 
from its natural gas industry experience. According to NRRI, pipelines 
were ``caught in an unusual transition'' by changes caused by Congress 
and the Commission. In the case of the electric industry, NRRI submits 
that although there are uneconomic wholesale power contracts, the 
Commission is not responsible for this situation.<SUP>570
---------------------------------------------------------------------------

    \570\ According to NRRI, the Commission did not ``berate'' 
electric utility management to sign uneconomic contracts in the 
manner that NRRI contends the Commission and Congress ``berated'' 
pipeline management. NRRI Initial Comments at 6. NRRI also objects 
that the proposed rule is a departure from what occurred in other 
deregulated industries (where no stranded cost recovery was allowed) 
and that the Commission should provide a fuller explanation as to 
why it believes allowing utilities full recovery of legitimate and 
verifiable stranded costs is the correct course of action.
---------------------------------------------------------------------------

    Several commenters suggest that the Commission condition a 
utility's ability to recover stranded costs upon the utility agreeing 
to take certain actions (such as reducing environmental effects 
<SUP>571 or ensuring the payment of costs that are stranded if the 
utility commences direct service to an end-use customer that was 
previously a wholesale customer of a transmission dependent utility 
<SUP>572 ), or agreeing to refrain from certain actions (such as 
seeking unilaterally to terminate or modify IPP contracts).<SUP>573 
CCEM proposes that open access, conversion rights, and divestiture 
should each be a precondition to a utility's eligibility for any 
stranded cost recovery. VT DPS submits that, if the Commission adopts a 
stranded cost rule, it should limit utility stranded cost claims to 
those cases where the utility can demonstrate that its costs have been 
rendered unrecoverable as a direct result of the final rule.<SUP>574
---------------------------------------------------------------------------

    \571\ E.g., Legal Environmental Assistance, Conservation Law 
Foundation.
    \572\ E.g., TDU Systems.
    \573\ E.g., EGA, LG&E. EGA and LG&E further argue that if a 
utility is able to abrogate a QF contract, a QF should be entitled 
to recover its costs based upon the same equities of reliance upon 
governmental approvals, changed regulatory regimes, and reasonable 
expectation.
    \574\ VT DPS argues that under Order No. 636, the Commission 
allowed recovery of costs that would be rendered ``unrecoverable'' 
because the costs would not be incurred to provide transportation 
service and because there would be no wholesale load from which to 
recover the costs. It suggests that when a utility loses wholesale 
load or a municipality establishes a new distribution system, the 
utility's costs are not necessarily rendered unrecoverable.
---------------------------------------------------------------------------

    A number of commenters object that the proposed rule contains no 
provisions for non-transmission-owning utilities to collect stranded 
costs.<SUP>575 Illinois Municipal Electric Agency asks the Commission 
to consider providing a forum for municipals to recover stranded costs 
from their customers under the same guidelines as investor-owned 
utilities. Recognizing that the FPA gives the Commission no general 
jurisdiction over municipalities for purposes of rate 
regulation,<SUP>576 Illinois Municipal Electric Agency argues that the 
FPA nevertheless does not prevent the Commission from providing a forum 
for municipalities that may experience stranded costs as a result of 
new federal regulations. NE Public Power District, RUS, and rural 
electric cooperative commenters object that the NOPR gives public 
utilities a greater chance than other transmitting utilities to recover 
stranded costs from departing customers by offering public utilities 
two avenues of recovery (an exit fee under a power sales contract or a 
transmission surcharge) but offering other transmitting utilities only 
one avenue (a transmission surcharge).<SUP>577
---------------------------------------------------------------------------

    \575\ E.g., PA Munis, Missouri Joint Commission, TAPS, Municipal 
Energy Agency Nebraska.
    \576\ But see FPA section 212(a), 16 U.S.C. 824k(a).
    \577\ RUS objects that, at the same time, an RUS-financed 
cooperative that is a transmitting utility would be required to 
provide reciprocal open access to its public utility supplier, which 
is also its customer and its competitor.
---------------------------------------------------------------------------

    PA Munis objects that the Commission's proposal to impose stranded 
costs only on wholesale requirements customers (and not on other 
wholesale customers) is unduly discriminatory and counter to the goals 
of the Open Access NOPR. It submits that the Commission's proposal, by 
subjecting a wholesale requirements customer to increased transmission 
rates for stranded costs not levied on other wholesale customers, is 
indistinguishable in substance from the pre-Order 436 plan held to be 
discriminatory in Maryland People's Counsel v. FERC.<SUP>578
---------------------------------------------------------------------------

    \578\ 761 F.2d 768 (D.C. Cir. 1985).
---------------------------------------------------------------------------

    ELCON and others <SUP>579 urge the Commission to clarify that 
stranded costs do not arise when a customer leaves a system because its 
plant becomes uneconomic or the customer wishes to co-generate or self-
generate. They note that ``[t]hese alternatives have always existed and 
do not arise from new opportunities for wholesale and retail 
wheeling.'' <SUP>580
---------------------------------------------------------------------------

    \579\ E.g., VA Com, DE Muni, LG&E, Mountain States Petroleum 
Assoc.
    \580\ ELCON July 25, 1995 Comments at 6.
---------------------------------------------------------------------------

Commission Conclusion
    We reaffirm our preliminary determination that the recovery of 
legitimate, prudent and verifiable stranded costs should be allowed. 
Having considered the arguments raised by the commenters that oppose 
stranded cost recovery, we continue to believe that utilities that 
entered into contracts to make wholesale requirements sales under an 
entirely different regulatory regime should have an opportunity to 
recover stranded costs that occur as a result of customers leaving the 
utilities' generation systems through Commission-jurisdictional open 
access tariffs or FPA section 211 orders,<SUP>581 in order to reach 
other power suppliers. As we indicated in the Supplemental Stranded 
Cost NOPR, we do not believe that utilities that made large capital 
expenditures or long-term contractual commitments to buy power years 
ago should now be held responsible for failing to foresee the actions 
this Commission would take to alter the use of their transmission 
systems in response to the fundamental changes that are taking place in 
the industry.<SUP>582 We will not ignore the effects of recent 
significant statutory and regulatory changes on the past investment 
decisions of utilities.<SUP>583 While, as some commenters point out, 
there has always been some risk that a utility would lose a particular 
customer, in the past that risk was smaller. It was not unreasonable 
for the utility to plan to continue serving the needs of its wholesale 
requirements customers and retail customers, and for those customers to 
expect the utility to plan to meet future customer needs. With the new 
open access, the risk of losing a

[[Page 21630]]

customer is radically increased. If a former wholesale requirements 
customer or a former retail customer uses the new open access to reach 
a new supplier, we believe that the utility is entitled to recover 
legitimate, prudent and verifiable costs that it incurred under the 
prior regulatory regime to serve that customer.<SUP>584
---------------------------------------------------------------------------

    \581\ Hereafter referred to collectively as the ``new open 
access'' or ``open access transmission.''
    \582\ FERC Stats. & Regs. para. 32,514 at 33,101-02.
    \583\ Contrary to NRRI's claim, and as explained in the NOPR 
(see, e.g., FERC Stats. & Regs. para. 32,514 at 33,063-68), the 
electric industry's transition to a more competitive market is 
driven in large part by statutory and regulatory changes beyond the 
utilities' control.
    \584\ As a result, the opportunity for wholesale stranded cost 
recovery under this Rule is limited to utilities that provided sales 
of generation and transmission under wholesale requirements 
contracts, and to utilities that provided service to retail 
customers that convert to wholesale customer status, and that face 
the potential inability to recover costs when their customers are 
able to reach new suppliers through open access transmission.
---------------------------------------------------------------------------

    We learned from our experience with natural gas that, as both a 
legal and a policy matter, we cannot ignore these costs. During the 
1980s and early 1990s, the Commission undertook a series of actions 
that contributed to the impetus for restructuring of the gas pipeline 
industry. The introduction of competitive forces in the natural gas 
supply market as a result of the Natural Gas Policy Act of 1978 
<SUP>585 and the subsequent restructuring of the natural gas industry 
left many pipelines holding uneconomic take-or-pay contracts with gas 
producers. When the Commission initially declined to take direct action 
to alleviate that burden, the U.S. Court of Appeals for the District of 
Columbia Circuit faulted the Commission for failing to do so.<SUP>586 
The court noted that pipelines were ``caught in an unusual transition'' 
as a result of regulatory changes beyond their control.<SUP>587
---------------------------------------------------------------------------

    \585\ 15 U.S.C. 3301  et seq.
    \586\ AGD, 824 F.2d at 1021.
    \587\ Id. at 1027.
---------------------------------------------------------------------------

    As we stated in the Supplemental NOPR, the court's reasoning in the 
gas context applies to the current move to a competitive bulk power 
industry. Indeed, because the Commission failed to deal with the take-
or-pay situation in the gas context, the court invalidated the 
Commission's first open access rule for gas pipelines. Once again, we 
are faced with an industry transition in which there is the possibility 
that certain utilities will be left with large unrecoverable costs or 
that those costs will be unfairly shifted to other (remaining) 
customers. That is why we must directly and timely address the costs of 
the transition by allowing utilities to seek recovery of legitimate, 
prudent and verifiable stranded costs. At the same time, however, this 
Rule will not insulate a utility from the normal risks of competition, 
such as self-generation, cogeneration, or industrial plant closure, 
that do not arise from the new availability of non-discriminatory open 
access transmission. Any such costs would not constitute stranded costs 
for purposes of this Rule.
    We are issuing the Stranded Cost Final Rule simultaneously with the 
Open Access Final Rule because we believe that the recovery of 
legitimate, prudent and verifiable stranded costs is critical to the 
successful transition of the electric industry to a competitive, open 
access environment. We believe that our decision today will be upheld 
by the courts. While the D.C. Circuit is still considering the various 
appeals of Order No. 636,<SUP>588 it has already upheld, in at least 
two instances, our ultimate decision to allow the recovery of costs 
stranded in the transition to a competitive natural gas 
industry.<SUP>589 As a result, we reject the suggestions of some 
commenters that a utility's obligation to comply with the provisions of 
the Open Access Final Rule should be conditioned upon final court 
approval of the Stranded Cost Final Rule. We also decline otherwise to 
condition a utility's ability to recover its stranded costs. As 
described in greater detail in Section IV.J.8, if a utility can make 
the necessary evidentiary showings, it will be eligible for stranded 
cost recovery.
---------------------------------------------------------------------------

    \588\ Pipeline Service Obligations and Revisions to Regulations 
Governing Self-Implementing Transportation Under Part 284 of the 
Commission's Regulations; and Regulation of Natural Gas Pipelines 
After Partial Wellhead Decontrol, Order No. 636, 57 FR 13267 (April 
16, 1992), FERC Stats. & Regs. para. 30,939 (1992), order on reh'g, 
Order No. 636-A, 57 FR 36128 (August 12, 1992), FERC Stats. & Regs. 
para. 30,950 (1992); order on reh'g, Order No. 636-B, 57 FR 57911 
(December 8, 1992), 61 FERC para. 61,272 (1993), reh'g denied, 62 
FERC para. 61,007 (1993), appeal pending United Distribution 
Companies, et al., v. FERC, No. 92-1485, et al., (D.C. Cir. Oral 
Argument Held Feb. 21, 1996).
    \589\ See, e.g., Public Utilities Commission of the State of 
California v. FERC, 988 F.2d 154, 166 (D.C. Cir. 1993) (``FERC, with 
the backing of this court, has been at pains to permit pipelines to 
recover these (take-or-pay) costs, which have accumulated less 
through mismanagement or miscalculation by the pipelines than 
through an otherwise beneficial transition to competitive gas 
markets.''); Western Resources, Inc. v. FERC, 72 F.3d 147 (D.C. Cir. 
1995).
---------------------------------------------------------------------------

    With regard to the magnitude of potential wholesale stranded costs, 
as the Supplemental Stranded Cost NOPR recognizes, the level may be 
small relative to that of retail stranded costs. Nevertheless, 
wholesale costs may be stranded as a result of open access 
transmission. Because the significance of such costs to the utilities 
that would face them may be great (and the prospect of not recovering 
such costs could erode utilities' ability to attract capital and be 
very detrimental to a diverse array of utility shareholders), we 
believe that we have a responsibility to allow for the recovery of such 
costs.
    We disagree with the commenters who contend that this Rule would 
discriminate against certain segments of the industry, such as non-
transmission-owning utilities (who would not be allowed to collect 
stranded costs) or wholesale requirements customers (who would be 
subject to stranded cost charges while other wholesale customers would 
not). These commenters misconstrue the purpose of this Rule and the 
nature of the stranded costs for which this Rule would allow recovery. 
This rule is designed to address a new and specific problem: The fact 
that a utility that historically has supplied bundled generation and 
transmission services to a wholesale requirements customer and incurred 
costs to meet reasonably expected customer demand may experience 
stranded costs when its customer is able to reach a new generation 
supplier due to the availability of open access transmission. This rule 
proposes a solution to that problem by allowing the recovery of 
legitimate, prudent and verifiable costs incurred by a utility to 
provide service to a wholesale requirements customer that subsequently 
becomes, in whole or in part, an unbundled wholesale transmission 
services customer of the utility. The opportunity for extra-contractual 
wholesale stranded cost recovery is allowed for only a discrete set of 
requirements contracts for which the utility can demonstrate that it 
had a reasonable expectation of continuing service, as well as for 
retail-turned-wholesale situations in which the utility satisfies the 
necessary evidentiary criteria. Thus, the fundamental premise of this 
rule--namely, that a utility should have an opportunity to recover 
reasonably-incurred costs that arise because open access use of the 
utility's transmission system enables a generation customer to shop for 
power--would not apply to a non-transmission-owning utility that, by 
definition, has no transmission by which its generation customer can 
escape to another supplier.
    The same historical relationship discussed above, including the 
expectation of continued service, justifies imposing the stranded costs 
covered by this rule on wholesale requirements customers only (not on 
non-requirements customers that contract separately for transmission 
services to deliver their purchased power). Requirements customers 
historically were long-term customers who typically did not expect to 
take service from other suppliers. Utilities thus assumed they would 
continue

[[Page 21631]]

serving these customers and may have made significant investments based 
on that long-term expectation. In contrast, utilities did not (and do 
not today) generally make investments for short-term economy-type 
transactions. Rather, such transactions were entered into only when the 
utility temporarily had available capacity or energy that could be 
provided to the buyer at a price lower than the buyer's decremental 
cost. The utility was not obligated in any way--either explicitly or 
implicitly--to provide for the needs of non-requirements customers. 
Because coordination transactions were not the cause of stranded 
investment decisions, it would be inappropriate to allocate such costs 
to non-requirements customers.
    Further, although some commenters object that the Rule would give 
public utilities a greater opportunity than other transmitting 
utilities to recover stranded costs, our jurisdiction over transmitting 
utilities that are not also public utilities is limited. If the selling 
utility under an existing contract is a transmitting utility that is 
not also a public utility, its wholesale requirements contracts are not 
subject to this Commission's jurisdiction. Thus, we can allow such a 
transmitting utility to recover stranded costs only through Commission-
jurisdictional transmission rates under sections 211 and 212 of the 
FPA. Nevertheless, in the context of a specific section 211 case, we 
would expect to apply similar principles to the extent possible to 
assure full stranded cost recovery. We also encourage such transmitting 
utilities to negotiate mutually agreeable stranded cost provisions with 
their customers.
2. Cajun Electric Power Cooperative, Inc. v. FERC <SUP>590
---------------------------------------------------------------------------

    \590\ 28 F.3d 173 (D.C. Cir. 1994) (Cajun).
---------------------------------------------------------------------------

    In the Supplemental Stranded Cost NOPR, the Commission made a 
preliminary finding that the Cajun court decision does not bar the 
recovery of stranded costs as proposed in the NOPR and set forth our 
reasoning in support of that finding.<SUP>591
---------------------------------------------------------------------------

    \591\ FERC Stats. & Regs. para. 32,514 at 33,105-06.
---------------------------------------------------------------------------

Comments
    Various commenters contend that the proposal to permit recovery of 
stranded costs at all, or particularly through transmission rates of 
departing customers, fails to address the Cajun court's 
concerns.<SUP>592 These commenters repeat many of the same arguments 
previously raised in this proceeding, which we have already addressed. 
Some commenters argue that including generation-based stranded costs in 
transmission rates is an anticompetitive tying arrangement and that 
Cajun compels the Commission to abandon this aspect of its stranded 
cost proposal or, at a minimum, to explain how the chosen method of 
recovery differs from that remanded in Cajun.<SUP>593
---------------------------------------------------------------------------

    \592\ E.g., APPA, ABATE, ELCON, Central Illinois Light, IL Com, 
VT DPS.
    \593\ See, e.g., ELCON, American Forest & Paper, MMWEC, Cajun, 
IL Com, PA Com, VT DPS, Education, DE Muni, IN Industrials, Texas-
New Mexico, Las Cruces, Blue Ridge, Suffolk County, Total Petroleum, 
NM Industrials, PA Munis.
---------------------------------------------------------------------------

    Several commenters <SUP>594 question whether the NOPR's stranded 
cost provisions would undermine the ``meaningful'' access to 
alternative suppliers referenced by the Cajun court.<SUP>595 For 
example, Arkansas Cities asserts that the Commission has failed to 
address whether a transmitting utility retains market power over 
transmission even after imposition of an open access tariff. It 
contends that this question is vital to determining whether imposition 
of stranded costs would interfere with a wholesale transmission 
customer's meaningful access to other power suppliers.
---------------------------------------------------------------------------

    \594\ E.g., Arkansas Cities, PA Munis, NM Industrials.
    \595\ See Cajun, 28 F.3d at 179.
---------------------------------------------------------------------------

    Some commenters also submit that the proposed procedures for a 
customer to obtain an estimate of its stranded cost liability are 
inadequate because they do not ameliorate the uncertainty confronting 
the customer, which was a concern of the court in Cajun. They suggest 
that a customer would still face the prospect of litigation concerning 
whether a proposed stranded cost charge is appropriate.<SUP>596
---------------------------------------------------------------------------

    \596\ See, e.g., Suffolk County, Arkansas Cities, Education.
---------------------------------------------------------------------------

    Other commenters argue that Cajun requires a trial-type evidentiary 
hearing before stranded costs may be recovered. They question whether 
the Commission's generic proposals on open access and the Commission's 
statements about the need to recover stranded costs are 
adequate.<SUP>597 ELCON references the Cajun court's statement that 
``if the Commission is wrong at the outset concerning the possibility 
of legitimate stranded investment cost, it is not fair or reasonable to 
create such a mechanism for recovery.'' <SUP>598 ELCON submits that the 
factual record does not demonstrate any significant wholesale stranded 
cost problem and, as a result, a final rule allowing recovery of such 
costs would not be ``fair or reasonable.''
---------------------------------------------------------------------------

    \597\ E.g., PA Com, NY Com, RUS.
    \598\ Cajun, 28 F.3d at 179 (emphasis in original).
---------------------------------------------------------------------------

    Many other commenters, in contrast, believe that the NOPR is 
distinguishable from the case that was before the court in Cajun and 
that the Commission has fully addressed the Cajun court's concerns. 
According to the Coalition for Economic Competition, this proceeding is 
very different from the Cajun proceeding because the proposed rule 
would not automatically permit utilities to charge market-based rates. 
The Coalition for Economic Competition states that in the absence of 
generic market-based rate authorization, there is no basis in Cajun for 
barring the recovery of stranded investment in transmission 
tariffs.<SUP>599
---------------------------------------------------------------------------

    \599\ SC Public Service Authority notes this distinction as well 
(Initial Comments at 78): ``In Cajun, the court was not criticizing 
the recovery of stranded assets as an abstract matter, but 
specifically as an integral part of a set of tariffs designed to 
justify market-based rates on the basis that the open access tariff 
adequately mitigated market power despite the provision permitting 
recovery of stranded assets.'' It suggests that if the Commission 
decides to allow utilities to recover stranded costs from departing 
customers, any utility recovering such costs should not be allowed 
to charge market-based rates.
---------------------------------------------------------------------------

    A number of commenters agree with the Commission that the Cajun 
court was concerned with the need for a more complete explanation of 
the basis for stranded cost recovery and the mechanism selected for 
such recovery. These commenters believe that the NOPR provides both the 
evidentiary record for addressing these concerns on a generic basis and 
the opportunity for all participants to present evidence and 
arguments.<SUP>600
---------------------------------------------------------------------------

    \600\ See, e.g., EEI, NEPCO, Centerior, Electric Consumers 
Alliance, Southern.
---------------------------------------------------------------------------

    Noting the Cajun court's concern as to whether the wholesale 
customer in that case had ``meaningful'' access to alternative 
suppliers, a number of commenters agree that the Commission, through 
the open access provisions of the NOPR, is in fact providing wholesale 
customers meaningful, reasonable access to alternative 
suppliers.<SUP>601
---------------------------------------------------------------------------

    \601\ E.g., Omaha PPD, Com Ed, Florida Power Corp. Com Ed also 
submits that the argument by the petitioners in Cajun that ``there 
really is no such thing as stranded investment, only a failure to 
compete'' ignored the circumstances under which the investments were 
made. It states that electric utilities did not incur the costs of 
generation facilities (and long-term fuel and power supply 
contracts) because they were less efficient competitors, but to 
satisfy their obligation in a fully-regulated market to provide 
service to all who request it.
---------------------------------------------------------------------------

    As evidence that the Cajun court was concerned with inadequate 
explanation and procedures and did not find that stranded costs could 
never be justified, several commenters point out that the Cajun court 
did not mention the D.C. Circuit's landmark decision in AGD, which 
strongly supports stranded cost

[[Page 21632]]

recovery.<SUP>602 For example, Coalition for Economic Competition 
suggests that construing Cajun to hold that stranded cost recovery is 
always anticompetitive would be at odds with AGD and other decisions 
that have upheld the Commission's policy of allowing recovery of the 
costs of the transition to competitive markets.<SUP>603
---------------------------------------------------------------------------

    \602\ See, e.g., Com Ed, Coalition for Economic Competition, 
NYSEG, Entergy.
    \603\ See, e.g., K N Energy, Inc., 968 F.2d 1295 at 1301 (D.C. 
Cir. 1992), Elizabethtown Gas Co. v. FERC, 10 F.3d 866, 874 (D.C. 
Cir. 1993).
---------------------------------------------------------------------------

    Numerous commenters also support the Commission's conclusion that 
stranded cost recovery through transmission rates is not a tying 
arrangement.<SUP>604 Among other things, these commenters argue that a 
tying claim requires that the defendant force the sale of a separate 
product with the sale of a product over which it has market power, and 
that here there is no second product being tied to transmission. 
Several commenters also suggest that, in any event, stranded cost 
recovery as proposed in the NOPR would be considered a legitimate 
business justification under the antitrust laws.<SUP>605 Com Ed 
explains that the Commission, as part of its effort to enhance 
competition in generation by opening up the transmission network, is 
avoiding placing on utilities the entire burden of the stranded costs 
resulting from their past regulatory obligations; it is not permitting 
utilities to maintain a monopoly of power sales.
---------------------------------------------------------------------------

    \604\ E.g., EEI, Com Ed, Consumers Power, SoCal Edison, Salt 
River, Entergy.
    \605\ See State of Illinois ex rel. Burris v. Panhandle Eastern 
Pipe Line Co., 935 F.2d 1469, 1483 (7th Cir. 1991), cert. denied, 
502 U.S. 1094 (1992) (pipeline's refusal to transport gas that an 
LDC customer purchased from another supplier was ``genuinely and 
reasonably motivated by the need to limit its potential take-or-pay 
liability, not by a desire to maintain its monopoly position by 
excluding competition in the sale of natural gas''); City of Chanute 
v. Williams Natural Gas Company, 743 F. Supp. 1437 (D. Kan.), aff'd, 
955 F.2d 641 (7th Cir. 1990) (pipeline's refusal to transport third-
party gas was motivated by legitimate business concerns, including 
desire to prevent take-or-pay liability, not by an anticompetitive 
motive).
---------------------------------------------------------------------------

Commission Conclusion
    We reaffirm that we do not interpret the Cajun court decision as 
barring the recovery of stranded costs. The court in that case did not 
bar stranded cost recovery, as some commenters suggest; it instead 
found that the Commission had not provided adequate proceedings and had 
not fully explained its decision. The Commission had failed to hold an 
evidentiary hearing concerning whether the inclusion of a stranded cost 
recovery provision in a particular utility's transmission tariff, along 
with other provisions in the tariff, resulted in the adequate 
mitigation of Entergy's market power so as to justify market-based 
rates. The court also found that the Commission had failed to explain 
adequately its approval of the stranded cost provision, among other 
provisions. In contrast, as discussed below, we have addressed in this 
consolidated proceeding (the Stranded Cost NOPR, the Supplemental 
Stranded Cost NOPR, the Open Access NOPR, and the Open Access/Stranded 
Cost Final Rule) all of the Cajun court's concerns.
    Our interpretation of Cajun is bolstered by a recent opinion of the 
Court of Appeals for the D.C. Circuit (the same circuit that decided 
Cajun) that confirms the validity of Commission imposed stranded cost 
recovery mechanisms in the transition to competitive markets. In 
Western Resources, Inc. v. FERC,<SUP>606 the court affirmed the 
Commission's decision to allow the recovery of costs stranded in the 
transition of the natural gas industry to a competitive market.<SUP>607 
We believe that, by this decision, the court has again affirmed the 
Commission's ability to allow stranded cost recovery, as long as we 
follow adequate procedures and explain our decision.<SUP>608
---------------------------------------------------------------------------

    \606\ 72 F.3d 147 (D.C. Cir. 1995).
    \607\ Id. at 152.
    \608\ As we noted in the Supplemental NOPR, the same court had 
earlier instructed the Commission in the AGD case that the 
Commission must consider the transition costs borne by regulated 
utilities when the Commission changes the regulatory rules of the 
game. FERC Stats. & Regs. para. 32,514 at 33,106.
---------------------------------------------------------------------------

    We are providing in this proceeding the evidentiary record to 
support our decision to allow the recovery of legitimate, prudent and 
verifiable stranded costs on a generic basis. We also are ensuring the 
``meaningful'' access to alternative suppliers that was identified as a 
concern of the Cajun court. The Open Access Final Rule is designed to 
attack one essential element of market power--namely, control over 
transmission access. The standard we are adopting for transmission 
service is far stricter than the standard we used at the time Cajun was 
decided; we now require non-discriminatory open access transmission, as 
well as a code of conduct and non-discriminatory sharing of 
transmission information (OASIS). The collective effect of these 
actions is that public utilities that own, control or operate 
interstate transmission facilities will not be able to favor their own 
generation and will have to compete on an equal basis with other 
suppliers.<SUP>609 All public utilities that own, control or operate 
facilities used for transmitting electric energy in interstate commerce 
will have tariffs on file that offer to any eligible customer any 
transmission services that the public utility could provide to itself, 
and under comparable terms and conditions.
---------------------------------------------------------------------------

    \609\ Id. at 33,065-67.
---------------------------------------------------------------------------

    We note that the Cajun court identified several provisions in 
Entergy's proposed tariff as potentially restraining competition: 
Entergy's retention of sole discretion to determine the amount of 
transmission capability available for its competitors' use; <SUP>610 
the point-to-point service limitation; <SUP>611 the failure to impose 
reasonable time limits on Entergy's response to requests for 
transmission service; <SUP>612 and Entergy's reservation of the right 
to cancel service in certain instances,<SUP>613 even where a customer 
had paid for transmission system modifications.<SUP>614 These types of 
provisions, which have the potential to restrain competition, will not 
be allowed under the Open Access Rule. On the contrary, the Final Rule 
pro forma tariff contains terms and conditions to ensure the provision 
of non-discriminatory transmission service. In addition, the 
requirements that a public utility take service under its own tariff, 
adopt a non-discriminatory transmission information network, and 
separate power marketing and transmission functions further ensure non-
discrimination and remove constraints to fair competition. Thus, the 
nondiscriminatory open access

[[Page 21633]]

transmission that is the hallmark of this Rule is designed to ensure 
meaningful access to alternative suppliers and goes far beyond that 
which was offered in the transmission tariff that was under review in 
Cajun.
---------------------------------------------------------------------------

    \610\ In contrast to the tariff under review in Cajun, the Final 
Rule pro forma tariff provides that available transmission 
capability (ATC) must be calculated and posted on the transmission 
provider's Open Access Same-time Information System (OASIS) pursuant 
to new Part 37--OPEN ACCESS SAME-TIME INFORMATION SYSTEM AND 
STANDARDS OF CONDUCT FOR PUBLIC UTILITIES of the Commission's 
regulations. Section 37.6 provides in pertinent part that along with 
posting its ATC on its OASIS node, a public utility must make all 
data used in the calculation publicly available, on request. Section 
37.4 provides that employees of the public utility and any affiliate 
that are engaged in merchant functions are prohibited from having 
preferential access to any transmission-related information. 
Additionally, the regulations provide auditing and monitoring 
procedures to safeguard against discriminatory practices.
    \611\ In contrast to the tariff under review in Cajun, the Final 
Rule pro forma tariff requires the provision of point-to-point and 
network service.
    \612\ In contrast to the tariff under review in Cajun, the Final 
Rule pro forma tariff requires reasonable time limits for responses 
to transmission requests. Specifically, Section 17.5 provides that a 
transmission provider must respond to a request for firm service as 
soon as practicable, but not later than thirty days after the date 
of receipt of a completed application.
    \613\ In contrast to the tariff under review in Cajun, the Final 
Rule pro forma tariff does not allow firm transmission service to be 
cancelled after the service has been commenced. However, Section 7.3 
of the Final Rule pro forma tariff does provide that in the event of 
a customer default, the transmission provider may, in accordance 
with Commission policy, file and initiate a proceeding with the 
Commission to terminate service.
    \614\ Cajun, 28 F.3d at 179-80.
---------------------------------------------------------------------------

    We also have addressed the Cajun court's concern over the method of 
recovery. In that case, Entergy proposed to include a charge in the 
departing customer's transmission rate to recover its stranded 
investment costs. The court said that this might constitute an 
anticompetitive tying arrangement.<SUP>615 As we explained in the 
Supplemental NOPR, the stranded cost recovery procedure we prescribe in 
this Rule is a transitional mechanism only that is intended to enable 
utilities to recover costs prudently incurred under a different 
regulatory regime. The purpose and effect of the stranded cost recovery 
mechanism that we approve in this Rule is to facilitate the transition 
to competitive wholesale power markets. Although we recognized in the 
Supplemental NOPR that stranded cost recovery may delay some of the 
benefits of competitive bulk power markets for some customers, such 
transition costs must nevertheless be addressed at an early stage if we 
are to fulfill our regulatory responsibilities in moving to competitive 
markets. The stranded cost recovery mechanism that we direct here is a 
necessary step to achieve pro-competitive results. In the long term, 
the Commission's rule will result in more competitive prices and lower 
rates for consumers.
---------------------------------------------------------------------------

    \615\ Notably, the court stated: ``This is, in essence, a tying 
arrangement, (citation omitted), and it might be fine if the purpose 
of the arrangement were not to cabin Entergy's market power.'' Id. 
at 177-78 (emphasis added).
---------------------------------------------------------------------------

    The Commission's approach also is consistent with the traditional 
regulatory concept of cost causation. We do not believe it is an 
illegal tying arrangement to hold a customer accountable for the 
consequences of leaving an incumbent supplier if, under our rules, the 
incumbent supplier must show a reasonable expectation of continuing 
service before it can recover stranded costs from the customer.
    Further, in response to the Cajun court's concern that the 
Commission had failed in that case to explain adequately its approval 
of the stranded cost provision and other provisions, we have provided 
in this proceeding a detailed explanation of the fundamental industry 
and regulatory changes that have given rise to the potential for 
stranded costs; the transitional nature of stranded costs; the critical 
need to deal with these costs in order to reach more competitive 
wholesale markets; and the consumer benefits that will result from 
competitive generation markets. We also have provided a detailed 
explanation of the terms and conditions in the Final Rule pro forma 
tariff that will meet the non-discriminatory open access service 
requirement.
    Several commenters (and the Cajun court) express concern for the 
need to provide as much certainty as possible for departing customers 
concerning their potential stranded cost obligation. Without some 
certainty, customers may be unable to shop for alternative suppliers. 
In response to these concerns, we have modified the stranded cost 
recovery mechanism to include a formula for calculating a departing 
customer's potential stranded cost obligation. As discussed in greater 
detail in Section IV.J.9, the revenues lost formula is designed to 
provide certainty for departing customers and to create incentives for 
the parties to address stranded cost claims between themselves without 
resort to litigation.
    We conclude that we have fully explained our decision to allow the 
recovery of legitimate, prudent and verifiable costs that are stranded 
in the transition to competitive wholesale bulk power markets. We also 
have provided ample opportunity for all concerned to present arguments 
and evidence on the issue. Further, we have significantly strengthened 
our open access requirements to ensure mitigation of transmission 
market power. Thus, we have fully addressed the concerns of the Cajun 
court.
3. Responsibility for Wholesale Stranded Costs (Whether To Adopt Direct 
Assignment to Departing Customers)
    In the Supplemental Stranded Cost NOPR, the Commission made a 
preliminary finding that direct assignment of stranded costs to the 
departing wholesale generation customer is the appropriate method for 
recovery of such costs.<SUP>616
---------------------------------------------------------------------------

    \616\ FERC Stats. & Regs. para.32,514 at 33,108.
---------------------------------------------------------------------------

Comments
    Numerous parties representing all constituencies support direct 
assignment of stranded costs to the departing generation 
customer.<SUP>617 These commenters argue, among other things, that 
direct assignment is consistent with the cost causation principle and 
preferable to increasing the delivered price of electricity to a whole 
region through the imposition of a wires charge, and that recovery of 
stranded costs from remaining customers would not be in the public 
interest. Several state commenters seek assurance from the Commission 
that native load customers will be held harmless from stranded costs 
resulting from other customers leaving the system.<SUP>618 KY Com 
submits that the possible results of a broader assessment of stranded 
costs, with the related uncertainty of its impact on the utilities' 
cost of capital, is more problematic in the long run than the 
possibility that the direct assignment of stranded costs would deter 
customers from shopping for power.
---------------------------------------------------------------------------

    \617\ See, e.g., EEI, Atlantic City, Arizona, Carolina P&L, 
Centerior, Com Ed, Duke, HP&L, Duquesne, Florida Power Corp, Omaha 
PPD, Alcoa, AEC & SMEPA, BG&E, Central Electric, Detroit Edison, El 
Paso, Montana-Dakota Utilities, Ohio Edison, PECO, PSNM, Southern, 
Sierra, SoCal Edison, Tucson Power, Utilities For Improved 
Transition, Cajun, NRECA, EGA, Electric Consumers Alliance, FL Com, 
PA Com, Knoxville, Salt River, KY Com, ND Com, California DWR, LA 
DWP, TVA, Utility Investors Analysts, Texas Utilities, LG&E, Utility 
Shareholders.
    \618\ E.g., NC Com, UT Com, NJ Ratepayer Advocate.
---------------------------------------------------------------------------

    Although TAPS opposes stranded cost recovery in general, it submits 
that, if the Commission decides to allow recovery, the Commission 
should directly assign stranded costs and not spread them across the 
board to all transmission users.
    Several commenters also oppose any allocation of stranded cost 
liability to shareholders.<SUP>619
---------------------------------------------------------------------------

    \619\ E.g., SCE&G, Com Ed, Ky Com, NC Com. SCE&G states that the 
Commission misinterpreted its previous comments by suggesting in the 
Supplemental NOPR that SCE&G believed shareholders should bear part 
of the costs.
---------------------------------------------------------------------------

    Some commenters state that direct assignment of stranded costs 
sends the correct pricing signals during the transition to a 
competitive regime. For example, Electric Consumers Alliance states 
that a wholesale customer should be able to obtain power elsewhere, but 
that the motive to do so should not be to escape responsibility for 
sunk investments made on its behalf. El Paso submits that failure to 
make the departing generation customer liable for stranded cost 
recovery would create a ``first-off'' incentive; the customers that 
leave the system first would not suffer from higher future rates 
designed to recover prudently incurred costs from the reduced base of 
remaining customers.
    Some commenters support direct assignment but oppose recovery of 
stranded costs through transmission rates. These commenters prefer an 
exit fee or lump-sum approach that would reflect cost causation in an 
unbundled fashion.<SUP>620 DOJ maintains that a

[[Page 21634]]

transmission adder is analogous to an excise tax and that the excise 
tax approach would distort pricing signals and customers' decisions on 
the use of electric power. It submits that the lump-sum approach, on 
the other hand, would establish a fixed, sunk liability that would not 
depend upon how much transmission service the departing customer takes 
in the future.<SUP>621
---------------------------------------------------------------------------

    \620\ E.g., Texas Utilities, DOJ.
    \621\ In its reply comments, Utility Working Group disputes 
DOJ's arguments that a transmission adder is analogous to an excise 
tax and would distort competition. It argues that DOJ's claim of 
price distortion ignores the fact that the costs that would be 
associated with a transmission adder consist of a portion of the 
previous wholesale power price--the markup above the utility's 
marginal cost that had regulatory approval. Utility Working Group 
says that because the utility's price and its competitor's price 
will contain this same charge for the utility's sunk and regulatory 
costs (the difference between the utility's regulated rate and its 
incremental cost), they will compete on the basis of their 
respective incremental costs. It also suggests that transmission 
adders can be designed on a lump-sum basis so that they are not tied 
to the amount of electricity purchased.
---------------------------------------------------------------------------

    Other commenters oppose direct assignment as being inconsistent 
with wholesale competition.<SUP>622 They argue that placing all of the 
responsibility for stranded costs on departing generation customers 
would discourage customers from switching to other generation providers 
and would thereby inhibit competition.<SUP>623 Some commenters also 
assert that departing generation customers are not the sole ``cause'' 
of stranded costs.<SUP>624 VT DPS contends that direct assignment 
cannot be reconciled with the Commission's refusal to allow the 
imposition of exit fees by gas pipelines when their wholesale customers 
depart.<SUP>625
---------------------------------------------------------------------------

    \622\ E.g., ELCON, NYMEX, IL Industrials, Missouri-Kansas 
Industrials, Philip Morris, Fertilizer Institute, Coalition on 
Federal-State Issues.
    \623\ Some commenters also oppose the Commission's proposal to 
allow the recovery of generation-related costs through transmission 
rates as being in contravention of cost-causation principles (e.g., 
VT DPS) or in violation of section 212(a) of the FPA, which they 
contend limits cost recovery to transmission-related costs (e.g., IL 
Industrials, Las Cruces).
    \624\ E.g., ELCON, IL Industrials, NY Energy Buyers, TX 
Industrials, Missouri-Kansas Industrials, Caparo, IBM, PA Munis, 
Education. For example, Caparo submits that business decisions by 
incumbent utilities are the cause of stranded costs.
    \625\ In support of this proposition, the VT DPS cites 
Transwestern Pipeline Co., 44 FERC para.61,164 at 61,536 (1988); El 
Paso Natural Gas Co., 47 FERC para.61,108 at 61,314 (1989); El Paso 
Natural Gas Co., 72 FERC para.61,083 (1995). It also contends that 
the Commission recently treated a notice provision in an El Paso 
contract as a conclusive, rather than a rebuttable, presumption. VT 
DPS cites other differences between the Commission's treatment of 
the natural gas and the electric utility industries. It notes that 
the Commission has not proposed to allow existing wholesale electric 
customers to get out of their contracts early, as it did in the gas 
area.
---------------------------------------------------------------------------

    Some commenters support spreading the burden of stranded costs 
broadly among departing customers, shareholders, and remaining 
wholesale customers on the basis that it would be equitable for all 
industry stakeholders to share both the benefits and the costs of the 
transition to competition.<SUP>626
---------------------------------------------------------------------------

    \626\ E.g., ELCON, IN Industrials, Reynolds, Philip Morris, 
ABATE, Missouri-Kansas Industrials, Aluminum.
---------------------------------------------------------------------------

    Others support spreading the costs to all customers through, for 
example, a meter charge to all utilities (to be passed on to 
customers), a one-time charge across the total market base, an access 
fee on the transmission system, or a component of transmission 
rates.<SUP>627 Nordhaus proposes a uniform national tax on all 
customers, at a rate that declines over time in a predetermined manner. 
He submits that this approach would remove ``gaming'' between utilities 
and potential exiters, would ensure that the stranded costs are not 
disproportionately loaded on price-sensitive demanders (that is, 
exiting customers), and would gradually disappear over time in a 
predictable fashion, thereby increasing the predictability of the new 
market.
---------------------------------------------------------------------------

    \627\ See, e.g., American National Power, NIEP, NSP, SBA, 
Coalition on Federal-State Issues, Pennsylvania P&L, Consolidated 
Natural Gas, Nordhaus, PA Munis. Consumers Power states that it does 
not oppose direct assignment, but asks that the final rule not 
preclude utilities from proposing alternative recovery mechanisms, 
including those that assess stranded costs on all transmission 
customers as part of the transmission rate. It suggests that 
utilities should not be precluded from showing that there may be 
countervailing reasons to assess stranded costs broadly among all 
transmission customers (e.g., where the costs assignable to a 
particular customer or group of customers may be so high as to 
create a dispute as to the propriety of direct assignment).
---------------------------------------------------------------------------

    PA Munis disputes the Commission's assertion in the Supplemental 
Stranded Cost NOPR that there is no compelling reason to assess costs 
broadly. It argues that a broad-based recovery mechanism that 
distributes uneconomic stranded costs to all power users would minimize 
the competition-inhibiting aspects of the Commission's proposed 
surcharge on departing generation customers. In a similar fashion, NSP 
states that across-the-board recovery from all users of the grid would 
recognize the societal benefits to be achieved from the transition to a 
competitive bulk power market and would reflect precedent set during 
the move to competition in the natural gas and telephone industries. It 
submits that the cost per service unit would be lower than exit fees 
assigned to particular customers and would eliminate the need for 
detailing stranded cost exposure for each customer contemplating 
leaving the system.
    FTC submits that some investments that now appear as stranded costs 
may have been intended to benefit customers over a wider area than a 
single utility. It suggests that national regional assessment methods 
could recover stranded costs undertaken to benefit these wider groups 
of customers.
    We also received comments suggesting that less than full recovery 
of stranded costs should be allowed. A number of commenters urge the 
Commission to require some shareholder liability for stranded cost 
recovery to give utilities an incentive to mitigate.<SUP>628 Several of 
these commenters assert that utility shareholders should be required to 
pay a portion of any stranded costs (such as 25-50 percent) because at 
least some of the responsibility for stranded costs lies with poor 
business decisions by utility management.<SUP>629 Occidental Chemical 
proposes that the Commission grant utilities a ``presumption of 
prudence'' in return for requiring them to absorb a minimum of 25 
percent (up to 50 percent) of stranded costs, citing as support the 
Commission's precedent in the natural gas industry.
---------------------------------------------------------------------------

    \628\ See, e.g., American Forest & Paper, Torco, Philip Morris, 
DE Muni, MT Com, IL Com, KS Com, Fertilizer Institute, Caparo, Las 
Cruces, IN Com, PA Munis, San Francisco, NRRI, Competitive 
Enterprise, ELCON, IN Industrials, UT Industrials, NY Energy Buyers, 
ABATE, CA Energy Co, Caparo, Education, Reynolds.
    \629\ See, e.g., Fertilizer Institute, Caparo, DE Muni, PA 
Munis, MT Com, San Francisco, ELCON, IN Industrials, NY Energy 
Buyers.
---------------------------------------------------------------------------

Commission Conclusion
    We reaffirm our decision that direct assignment of stranded costs 
to the departing wholesale generation customer through either an exit 
fee <SUP>630 or a surcharge on transmission is the appropriate method 
for recovery of such costs. We believe it is appropriate that the 
departing generation customer, and not the remaining generation or 
transmission customers (or shareholders), bear its fair share of the 
legitimate and prudent obligations that the utility undertook on that 
customer's behalf.
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    \630\ As used in this Rule, ``exit fee'' refers to the charge 
that will be payable by a departing generation customer upon the 
termination of its requirements contract with a utility (if the 
utility is able to demonstrate that it reasonably expected to 
continue serving the customer beyond the term of the contract), 
whether payable in a lump-sum payment or an amortization of a lump-
sum payment. (The same charge also can be paid as a surcharge on the 
customer's transmission rate.)
---------------------------------------------------------------------------

    In reaching this decision, we have carefully weighed the arguments 
supporting direct assignment of stranded costs against those supporting 
a more broad-based approach, such as spreading stranded costs to all 
transmission users of a utility's system.

[[Page 21635]]

Recognizing that each approach has advantages and disadvantages, we 
conclude that, on balance, direct assignment is the preferable approach 
for both legal and policy reasons.
    One of the main reasons to adopt direct assignment of stranded 
costs is that direct assignment is consistent with the well-established 
principle of cost causation, namely, that the party who has caused a 
cost to be incurred should pay it. Direct assignment of stranded costs 
to departing generation customers is particularly appropriate given the 
nature of the stranded cost recovery mechanism contained in this Rule, 
which links the incurrence of stranded costs to the decision of a 
particular generation customer to use open access transmission to leave 
the utility's generation system and shop for power, and which bases the 
prospect of stranded cost recovery on the utility's ability to 
demonstrate that it incurred costs with the reasonable expectation that 
the customer would remain on its generation system.
    A broad-based approach, in contrast, would violate the cost 
causation principle by shifting costs to customers (such as 
transmission users of the utility's system) that had no responsibility 
for stranding the costs in the first place. In addition, if the 
Commission were to adopt a broad-based approach, it would have to 
determine whether to base the transmission surcharge on all users of a 
utility's transmission system on a one-time, up-front estimate of 
stranded costs (that is, each utility claiming stranded costs would 
make a one-time, comprehensive determination of stranded costs for the 
utility as a whole) or on an as-realized basis (the surcharge would be 
based on actual customer departures and would be adjusted each time a 
customer departs). Each option would have disadvantages that are not 
present in the direct cost causation approach we are adopting.
    For example, a major disadvantage of an up-front, broad-based 
transmission surcharge is that it in effect would charge customers for 
costs before the costs are incurred (i.e., before customers have even 
decided to leave the utility's generation system) and could charge for 
costs that may never be incurred (e.g., some customers may decide to 
stay on the utility's system as requirements customers). The other 
option, a broad-based transmission surcharge that would be adjusted as 
customers leave the utility's system, also has disadvantages. While 
this option might recover stranded costs that are closer to the actual 
amount incurred by the utility, it could produce variability in 
transmission rates every time stranded costs from a newly-departed 
customer are included in the transmission surcharge and, in turn, could 
possibly hamper efficient power supply choices and efficient generator 
location decisions. These disadvantages are not present in the direct 
assignment approach.
    Direct assignment will result in a more accurate determination of a 
utility's stranded costs than would an up-front, broad-based 
transmission surcharge. This is because the stranded cost for any 
customer is finally determined only if that customer actually leaves a 
utility. Moreover, there is no stranded cost unless the then-current 
market price of power for the period that the utility reasonably 
expected to continue serving the customer is below the utility's cost. 
Thus, because the circumstances of each departing customer will be 
known, the amount of any stranded cost liability can be determined with 
reasonable accuracy. Further, if a customer does not leave the utility 
or leaves at some future time when the utility's costs are competitive, 
the issue need not be addressed.
    On this basis, the direct assignment approach is more suited to the 
recovery of stranded costs as defined in this Rule (including the 
reasonable expectation standard and open access transmission causation 
requirement) than is a broad-based approach. We expect that a utility 
would have difficulty estimating in advance all of its stranded costs 
for purposes of an up-front, broad-based transmission surcharge. In the 
face of this uncertainty, the utility's best strategy likely would be 
to try to recover through the broad-based surcharge as much of its 
uneconomic assets as possible by claiming that all of its wholesale 
customers are likely to depart and to leave large stranded costs. In 
this regard, the broad-based approach would provide an incentive for a 
utility to try to recover the costs of all of its uneconomic assets 
whether or not they were prudently incurred. This is in contrast to 
what this Rule provides, which is for recovery of only those 
legitimate, prudent and verifiable costs that were incurred on behalf 
of a specific customer based on a reasonable expectation that the 
utility would continue to serve the customer and that are stranded when 
the customer departs the utility's generation system by using the 
utility's open access transmission.
    The direct assignment approach also can be readily applied to both 
wholesale and retail-turned-wholesale departing customers. It also can 
be adapted for retail customers. Further, it works for costs stranded 
by a section 211 order requiring either a public utility, or a 
transmitting utility that is not also a public utility, to provide 
transmission service. However, this is not the case for a broad-based 
approach, particularly an up-front, broad-based approach. Assuming that 
a principal motivation for an up-front, broad-based approach would be 
to recover all of a utility's stranded costs as quickly as possible, 
retail-turned-wholesale stranded costs nevertheless are not susceptible 
of being collected on an up-front basis. It is not possible to make a 
realistic up-front estimate of costs stranded by municipalizations that 
may occur in the future. Thus, even if we were to adopt an up-front, 
broad-based approach for recovering costs that are stranded when 
wholesale requirements customers use their former supplier's 
transmission system to reach a new supplier, retail-turned-wholesale 
stranded costs would have to be identified as they occur and the 
stranded cost surcharge on transmission users adjusted accordingly. 
Similarly, the broad-based approach is not easily adaptable to 
transmitting utilities that are not also public utilities. It is 
doubtful that, in establishing the rate for a section 211 applicant, 
the Commission could also set transmission surcharges for customers 
that were not section 211 applicants; this is what a broad-based 
approach, in effect, would require us to do.
    Direct assignment by means of an exit fee or a transmission 
surcharge that is not dependent on any subsequent power or transmission 
purchases by the customer is also an economically efficient way to 
collected stranded costs. The customer may make a lump-sum stranded 
cost payment, amortize the lump-sum payment, or spread the payment as a 
surcharge in addition to its transmission rate. The total amount of 
stranded costs that the directly-assigned customer ultimately pays 
would not depend on how much transmission service it takes and thus 
would not influence the customer's subsequent transmission purchase 
decisions.
    With a broad-based surcharge (which could be demand- or usage-
based), on the other hand, the surcharge for transmission users would 
depend on how much transmission service the users take. A broad-based 
approach also would be inefficient as it would raise the price of 
transmission service for all customers, thereby potentially cutting off 
some beneficial power trading that would otherwise occur for all 
unbundled transmission customers. The surcharge also could convert some 
profitable existing power purchase contracts into unprofitable 
contracts. In

[[Page 21636]]

addition, it could reduce economy trading because the surcharge would 
be added to the price of economy transmission. In this manner, a broad-
based surcharge would constitute a cross-subsidy that could distort the 
market.
    We recognize that direct assignment is not without its potential 
drawbacks. For example, when compared to an up-front, broad-based 
transmission surcharge approach, direct assignment may entail a longer 
stranded cost recovery period. The transition period for stranded cost 
recovery under a direct assignment approach would depend on the length 
of the remaining terms of the wholesale requirements contracts for 
which this Rule provides an opportunity for recovery (contracts 
executed on or before July 11, 1994 that do not contain an exit fee or 
explicit stranded cost provision).
    On the other hand, a broad-based approach could identify and 
recover stranded costs earlier than the direct assignment approach; 
recovery of stranded costs for all of a utility's wholesale 
requirements customers could begin as soon as the utility's up-front 
stranded cost amount for departing wholesale customers is determined 
(through litigation or settlement). However, this potential advantage 
of a broad-based approach (the shorter transition period) is outweighed 
by what we believe to be a serious infirmity, namely, the possibility 
that the broad-based transmission surcharge could end up including 
costs that have not yet been incurred and may never be incurred.
    In addition, another potential drawback to the direct assignment 
approach is that the departing generation customer may see little or no 
savings in the short-term by switching power suppliers once its 
stranded cost exit fee is added to its lower power price from a new 
supplier. Direct assignment may leave the customer uncertain about the 
benefits of shopping for power because of the customer's potential 
stranded cost liability and, in turn, may bias the customer toward 
staying with its existing power supplier.<SUP>631
---------------------------------------------------------------------------

    \631\ To counteract this potential disadvantage, we have 
provided procedures in this Rule, including a formula that the 
utility is to use to calculate a departing generation customer's 
stranded cost obligation, that allow a customer considering 
switching power suppliers to request a stranded cost determination 
from the utility at any time before the expiration of the customer's 
wholesale requirements contract. See Section IV.J.9.
---------------------------------------------------------------------------

    In the case of a broad-based approach, in contrast, much of the 
customer's direct assignment stranded costs are spread to others 
through a transmission surcharge. As a result, the departing generation 
customer's power cost savings may more than offset the customer's 
stranded cost transmission surcharge. The customer may therefore see 
earlier power cost savings if a broad-based approach were 
adopted.<SUP>632 Once again, however, we believe that this potential 
benefit to a broad-based approach is outweighed by a significant 
countervailing disadvantage. In particular, the potential power cost 
savings to the departing generation customer would be realized only by 
shifting costs (that are directly attributable to the departing 
generation customer) to the other users of the utility's transmission 
system. We believe that this negative aspect of a broad-based 
approach--its violation of the cost causation principle--is too great a 
price to pay for allowing a departing generation customer to realize 
power cost savings as early as possible.
---------------------------------------------------------------------------

    \632\ In addition, because the customer would already know its 
stranded cost transmission surcharge, it presumably would have some 
certainty as to the costs of shopping for power. However, the 
stranded cost surcharge in its transmission rates subsequently may 
be adjusted upward if the utility providing transmission becomes 
eligible to recover retail-turned-wholesale stranded costs. Also, if 
the broad-based stranded cost surcharge is adjusted on an as-
realized basis, the potential departing generation customer's 
surcharge may increase as a result of other customers leaving the 
utility's system.
---------------------------------------------------------------------------

    Thus, we recognize that under direct assignment, it is possible 
that some customers may not be able to afford to leave as soon as they 
would like. This in turn could mean that lower cost suppliers would not 
be able to make sales to those customers as soon as they would like. 
However, this would occur only during a transition period, and it would 
ensure that, consistent with strict cost causation principles, the 
burden of these transition costs is not unfairly spread to other 
customers. Once the existing uneconomic assets and contracts are behind 
us, all wholesale customers will be better able to shop for power and 
reap the long-term benefits of competitive supply markets.
    Although this direct assignment approach is different from the 
approach taken in the natural gas industry, we believe that the 
difference is justified. The transition of the electric industry to an 
open transmission access, competitive industry (including our proposal 
to allow an opportunity for extra-contractual recovery of stranded 
costs associated with a discrete set of wholesale requirements 
contracts) is different in a number of respects from the natural gas 
industry's transition to open access transportation service by 
interstate natural gas pipelines. The gas industry underwent a long 
period of open access transition, starting with Order No. 436 in 1985 
and culminating with Order No. 636 in 1992. In the gas context, prior 
to addressing potential stranded costs, the Commission in Order No. 436 
allowed customers receiving bundled gas sales and transportation 
service from a pipeline the option to convert to transportation-only 
service, or to reduce their contract demand for gas service, before the 
termination of their contracts with the pipeline.<SUP>633 As a result, 
most of the former bundled customers of the pipeline had already 
departed the pipeline's sales service before the Commission addressed 
the recovery of take-or-pay costs in Order Nos. 500 and 528. In 
addition, by the time that the Commission addressed the remaining 
transition costs in Order No. 636, the commodity or wellhead natural 
gas market was already competitive and the majority of gas was already 
being sold on an unbundled basis.
---------------------------------------------------------------------------

    \633\ As discussed in Section IV.A.5, we are not providing for a 
similar conversion right in this Rule.
---------------------------------------------------------------------------

    Thus, changes in the natural gas industry had progressed to such a 
point (i.e., the departure of customers from bundled sales) that it was 
not possible for the Commission to use a strict cost causation 
approach. We noted in the Supplemental Stranded Cost NOPR that

    Many natural gas customers had already left their historical 
pipeline suppliers' systems. Others had converted from sales and 
transportation customers to transportation-only customers. Others 
were in a transition stage having had opportunities to lower their 
contract demands or otherwise become partial service customers. 
Significant take-or-pay and other costs had accumulated.<SUP>634
---------------------------------------------------------------------------

    \634\ FERC Stats. & Regs. para.32,514 at 33,108.
---------------------------------------------------------------------------

    Under those circumstances, the Commission determined that it was 
appropriate to spread the majority of the remaining transition costs 
associated with take-or-pay and other supply contracts to all customers 
(both existing and new) using the interstate natural gas transportation 
system. Moreover, because of the changes in contractual relationships 
that had already occurred among pipelines and their customers, it was 
no longer possible for the Commission to follow a strict cost causation 
approach to recovering take-or-pay costs. The Commission-prescribed 
remedy for the recovery of transition costs in the natural gas industry 
thus was tailored to fit the needs of that industry given the stage of 
development at the time.
    However, such a broad-based approach to recovery of natural gas 
transition costs was an exception to the

[[Page 21637]]

time-honored principle that rates should reflect cost causation, and 
because of this it was necessary for the Commission to justify its 
departure from that principle. As the court said in K N Energy v. FERC, 
<SUP>635 ``[i]t has been this Commission's long standing policy that 
rates must be cost supported. Properly designed rates should produce 
revenues from each class of customers which match, as closely as 
practicable, the costs to serve each class or individual customer.'' In 
that case, the court found the Commission's departure from cost-
causation justified ``given the unusual circumstances surrounding the 
take-or-pay problem, and the limited nature--both in time and scope--of 
the Commission's departure from the cost-causation principle.'' 
<SUP>636 It continues to be Commission policy to follow the cost-
causation principle to the extent possible.
---------------------------------------------------------------------------

    \635\ 968 F.2d 1295, 1300-01 (D.C. Cir. 1992) (quoting Alabama 
Electric Cooperative, Inc. v. FERC, 684 F.2d 20, 27 (D.C. Cir. 1982) 
(emphasis in original).
    \636\ Id. at 1301. See also Public Utilities Commission of State 
of California v. FERC, 988 F.2d 154, 169 (D.C. Cir. 1993).
---------------------------------------------------------------------------

    The factors described above are not present in the electric 
industry. At this time, the vast majority of customers remain on their 
bundled suppliers' systems and generation is not yet fully competitive. 
Because the situation facing the electric industry today is different 
from that which the natural gas industry faced, the Commission must 
tailor its approach differently. In the case of the electric industry 
today, we have the opportunity to address the stranded cost recovery 
issue up front, before customers leave their suppliers' systems. We 
thus are able to use the cost causation approach that has been 
fundamental to our regulation since 1935.<SUP>637
---------------------------------------------------------------------------

    \637\ Moreover, as we explained in the Supplemental Stranded 
Cost NOPR, the shifting of generation costs to transmission rates 
does not violate Commission policy where, as here, the customer that 
caused the costs to be incurred and stranded will continue to pay 
those costs. As we indicated, the only difference is that in some 
instances the customer will pay the costs through an adder to its 
transmission rate instead of through a generation rate. See FERC 
Stats. & Regs. para.32,514 at 33,108 n.269.
---------------------------------------------------------------------------

    The Commission disagrees with commenters' arguments that we cannot 
impose an exit fee to recover stranded costs because we did not do so 
in the gas context. As discussed in Section IV.J.9, this Rule 
establishes procedures for providing a potential departing generation 
customer advance notice (before it leaves its existing supplier) of the 
stranded cost charge (whether it is to be paid as an exit fee or a 
transmission surcharge) that will be applied if the customer decides to 
buy power elsewhere. In the natural gas context, in contrast, the 
Commission has prohibited pipelines from developing and charging an 
``exit fee'' after a customer had implemented its gas purchase 
decision, noting that otherwise, the customer would not know in advance 
the full cost consequences of its nomination decision.<SUP>638 The 
``exit fee'' that the Commission rejected in El Paso Natural Gas 
Company <SUP>639 is also factually distinguishable from the ``exit 
fee'' discussed in this rule. In that case, the Commission rejected a 
pipeline's attempt post-restructuring to impose an ``exit fee'' on firm 
transportation-only customers (that were converted sales customers) who 
in the future elect either to terminate their firm transportation 
service upon expiration of the service agreement, or to reduce their 
firm transportation services level by more than 10 percent pursuant to 
an existing contractual reduction right. Such a scenario is quite 
different from the limited opportunity for stranded cost recovery 
provided in this Rule, which is based on a utility's reasonable 
expectation of continuing generation service to a bundled (sales and 
transmission) requirements customer.
---------------------------------------------------------------------------

    \638\ See, e.g., Transwestern Pipeline Company, 43 FERC 
para.61,240 at 61,654, order on rehearing, 44 FERC para.61,164 at 
61,536 (1988), relevant petitions for review dismissed as moot, 
Transwestern Pipeline Company v. FERC, 897 F.2d 570, 575-76 (D.C. 
Cir. 1990); El Paso Natural Gas Company, 47 FERC para.61,108 at 
61,314 (1989).
    \639\ 72 FERC para.61,083 (1995). Further, VT DPS misinterprets 
the Commission's reference to the NOPR in that case. The Commission 
did not treat a notice of termination provision in El Paso's 
contract as a conclusive presumption that El Paso had no reasonable 
expectation of continuing to serve certain customers, as VT DPS 
contends. The Commission merely stated that ``[e]ven if the rules 
proposed in [the Supplemental Stranded Cost] NOPR were applied here, 
El Paso would have difficulty justifying the exit fee proposed in 
light of the existence of the notice of termination provision in the 
contract.'' 72 FERC at 61,441.
---------------------------------------------------------------------------

    We also will decline to require a utility seeking stranded cost 
recovery to shoulder a portion of its stranded costs. Such a 
requirement would be a major deviation from the traditional principle 
that a utility should have a reasonable opportunity to recover its 
prudently incurred costs.<SUP>640 Although the Commission allowed such 
an approach with regard to a natural gas pipeline's take-or-pay 
costs,<SUP>641 we did so only as an extraordinary measure given the 
nature of the take-or-pay problem and the prevailing environment at 
that time. We returned to traditional principles when, in issuing Order 
No. 636, we authorized pipelines to recover all of their prudently 
incurred gas supply realignment costs (the costs pipelines incur in 
realigning, renegotiating, or terminating their portfolio of gas supply 
contracts to adjust to their sales customers' decisions to exercise 
their unilateral right under the rule to reduce or end their commodity 
purchase obligations to the pipelines). <SUP>642 In the case of the 
open access transmission required by this Rule, we believe that a 
utility is entitled to an opportunity to recover all legitimate, 
prudent and verifiable costs incurred by the utility when the 
availability of open access transmission enables a requirements 
customer to reach a new generation supplier.
---------------------------------------------------------------------------

    \640\ See, e.g., Maryland v. Louisiana, 451 U.S. 725, 748 
(1981); Office of Consumers' Counsel v. FERC, 914 F.2d 292 (D.C. 
1990); National Fuel Gas Supply Corporation v. FERC, 900 F.2d 340, 
342, 347-51 (D.C. Cir. 1990).
    \641\ In Order No. 500, the Commission provided that if 
pipelines absorbed from 25 to 50 percent of their take-or-pay 
settlement costs, they could recover an equal amount from their firm 
sales customers in the form of fixed charges. Any balance could be 
recovered in the form of a commodity rate surcharge or a volumetric 
surcharge on total pipeline throughput. Order No. 500, FERC Stats. & 
Regs. para.30,761 at 30,787 (1987). See also Order No. 528, 53 FERC 
para.61,163 at 61,597 (1990). Moreover, we offered pipelines an 
important quid pro quo for absorbing take-or-pay costs under Order 
Nos. 500 and 528--a special presumption that they had been prudent 
in incurring their take-or-pay liabilities.
    \642\ Order No. 636, FERC Stats. & Regs. para.30,939 at 30,461.
---------------------------------------------------------------------------

    Although the alternatives of either spreading the stranded costs to 
all transmission users or requiring the utility shareholders to share 
the costs with departing customers might enable a wholesale customer to 
leave sooner than would the direct assignment approach, the departing 
customer would be able to do so only at the expense of others who had 
no responsibility for causing the legitimate, prudent and verifiable 
costs to be incurred. Although we departed from strict cost causation 
principles in the gas context and required a broad spreading of the 
costs given the particular circumstances presented by the gas 
industry's transition to open access, we ultimately returned to the 
more traditional approach of allowing utilities to recover all of their 
prudently incurred transition costs in Order No. 636. At this juncture 
in the evolution of competition in the electric industry we need not 
make such a departure from cost causation principles; utilities can 
identify and seek to charge the customers who caused the costs to be 
incurred in the first place, before those customers leave the utility's 
generation system. Accordingly, we believe that a broader spreading of 
the costs to entities who are not responsible for the incurrence of

[[Page 21638]]

the stranded costs would not be equitable.
4. Recovery of Stranded Costs Associated With New Wholesale 
Requirements Contracts
    In the Supplemental Stranded Cost NOPR, the Commission 
preliminarily concluded that future wholesale contracts must explicitly 
address the obligations of the seller and buyer, including the seller's 
obligation to continue to serve the buyer, if any, and the buyer's 
obligation, if any, if it changes suppliers. We stated that utilities 
will be allowed stranded cost recovery associated with ``new'' 
wholesale requirements contracts (executed after July 11, 1994) only if 
explicit stranded cost provisions are contained in the contract. We 
indicated that recovery of wholesale stranded costs associated with any 
such new contract will not be allowed unless such recovery is provided 
for in the contract.<SUP>643 We also stated that a contract that is 
extended or renegotiated for an effective date after July 11, 1994 
becomes a ``new'' contract for which stranded cost recovery will be 
allowed only if explicitly provided for in the contract.<SUP>644
---------------------------------------------------------------------------

    \643\ FERC Stats. & Regs. para. 32,514 at 33,110.
    \644\ Id. at 33,118.
---------------------------------------------------------------------------

    We also stated that it is not appropriate to impose on a wholesale 
requirements supplier a regulatory obligation to continue to serve its 
existing requirements customer beyond the end of the contract term. We 
proposed to retain the Sec. 35.15 prior notice of termination filing 
requirement only for: (i) All contracts required to be filed under 
sections 205 and 206 of the FPA that were executed before the effective 
date of the Final Rule pro forma tariffs; and (ii) any unexecuted 
contracts that were filed before the effective date of the Final Rule 
pro forma tariffs. With regard to any power sales contract executed on 
or after that date, we proposed to no longer require prior notice of 
termination under Sec. 35.15, but to require (for administrative 
reasons) written notification of the termination of such contract 
within 30 days after termination takes place. We requested comments on 
whether this proposal should also be applied to transmission 
contracts.<SUP>645
---------------------------------------------------------------------------

    \645\ Id. and nn. 273, 274.
---------------------------------------------------------------------------

Comments
    Numerous commenters support our preliminary conclusion that new 
wholesale requirements contracts should explicitly address the 
obligations of the seller and buyer and that it is not appropriate to 
impose on wholesale requirements suppliers a regulatory obligation to 
continue to serve their existing requirements customers beyond the end 
of the contract term.<SUP>646 However, Arkansas Cities expresses 
concern that this could undermine obligations to serve that have been 
included in certain contracts with utilities. It asks the Commission to 
state that, unless a utility has undertaken an obligation to serve via 
contract, there is no obligation to serve beyond the contract term. 
Arkansas Cities asks the Commission to clarify that contracts 
establishing an obligation to serve will be enforced.
---------------------------------------------------------------------------

    \646\ E.g., PA Com, FL Com, PSNM, Southern, NC Com, Duke, Public 
Service Co of CO, SoCal Edison, PacifiCorp, Carolina P&L, NYSEG.
---------------------------------------------------------------------------

    Several other commenters argue that if a wholesale customer elects 
to switch suppliers, the previous supplier should be under no 
obligation to take the customer back onto its system at embedded cost 
rates.<SUP>647 Sierra asks the Commission to endorse a host utility's 
ability to insist on protective contract provisions before 
reestablishing service, including a predetermined period (such as five 
years--a commonly-used planning period) before the customer could seek 
to leave the system again.
---------------------------------------------------------------------------

    \647\ E.g., Sunflower, Sierra, Public Service Co of CO, Duke.
---------------------------------------------------------------------------

    A number of commenters support the Commission's proposal to 
eliminate the prior notice of termination requirement for power sales 
contracts executed after the date on which the final rule pro forma 
tariffs become effective.<SUP>648 Southern states that, because of the 
opportunities for power purchasers that will exist after the proposed 
rules take effect, the Commission also should eliminate Sec. 35.15 as 
it applies to old contracts.
---------------------------------------------------------------------------

    \648\ E.g., EEI, NYSEG, Southern, PA Com, SoCal Edison, 
Pacificorp, El Paso.
---------------------------------------------------------------------------

    Several commenters support eliminating the Sec. 35.15 filing 
requirement for transmission contracts as well.<SUP>649 This change is 
needed, some assert, to provide certainty in commercial arrangements in 
the more competitive environment and as a matter of fairness. CSW 
suggests that all Sec. 35.15 filing requirements for existing contracts 
(wholesale and transmission contracts) be phased out over three years 
and that only contracts that expire within three years after the final 
rule should be subject to the requirement to file a notice of 
termination.
---------------------------------------------------------------------------

    \649\ E.g., EEI, Public Service Co of CO, PA Com, Entergy, 
Florida Power Corp.
---------------------------------------------------------------------------

    Nevertheless, several other commenters oppose the Commission's 
proposal to no longer require prior notice of termination for power 
sales contracts executed on or after the effective date of the generic 
tariffs.<SUP>650 TDU Systems opposes elimination of Sec. 35.15 as 
tantamount to a finding that termination of all contracts is just and 
reasonable. TDU Systems and NRECA submit that the market power 
exercised by supplying utilities will not disappear the instant the 
rule becomes final and that it may be possible for a utility to 
exercise monopoly power even with regard to ``new'' contracts. They 
propose that if the Commission nevertheless decides to allow contract 
termination under Sec. 35.15, the Commission should require a public 
utility to pay ``stranded benefit'' costs to former wholesale power 
customers if the customers show that they had a reasonable expectation 
that the power sales would continue past the end of the agreement at 
the prior rate.
---------------------------------------------------------------------------

    \650\ E.g., TDU Systems, NRECA, TAPS, Redding, Southwest TDU 
Group. VT DPS sees no urgent need for elimination of the Sec. 35.15 
requirement or for automatic termination of sales service under a 
wholesale contract of more than three years duration. However, it 
supports pregranted authorization of service termination upon 
expiration of sales contracts with terms of less than three years. 
Among other things, it submits that the pregranted authority to 
terminate short-term service would relieve the utility of a planning 
uncertainty and allow it to maximize use of uncommitted transmission 
capacity.
---------------------------------------------------------------------------

    Several commenters also oppose eliminating the Sec. 35.15 filing 
requirement for transmission contracts.<SUP>651 FL Com asserts that 
because the Commission has imposed an obligation to serve for 
transmission service, Sec. 35.15 should be retained for new and 
existing transmission contracts.
---------------------------------------------------------------------------

    \651\ TAPS, TDU Systems, FL Com, MMWEC.
---------------------------------------------------------------------------

Commission Conclusion
    We reaffirm our preliminary determination that future wholesale 
requirements contracts should explicitly address the mutual obligations 
of the seller and buyer, including the seller's obligation to continue 
to serve the buyer, if any, and the buyer's obligation, if any, if it 
changes suppliers. As we indicated in the Supplemental Stranded Cost 
NOPR, now that utilities have been placed on explicit notice that the 
risk of losing customers through increased wholesale competition must 
be addressed through contractual means only, they must address stranded 
cost issues when negotiating new contracts or be held strictly 
accountable for the failure to do so.
    We accordingly will allow recovery of wholesale stranded costs 
associated with any new requirements contract

[[Page 21639]]

(executed after July 11, 1994) only if explicit stranded cost 
provisions are contained in the contract. By ``explicit stranded cost 
provision'' (for contracts executed after July 11, 1994) we mean a 
provision that identifies the specific amount of stranded cost 
liability of the customer(s) and a specific method for calculating the 
stranded cost charge or rate. For purposes of requirements contracts 
executed after July 11, 1994 but before the date on which this Final 
Rule is published in the Federal Register, however, we clarify that a 
provision that specifically reserved the right to seek stranded cost 
recovery consistent with what the Commission permits in this Rule 
(without identifying the specific amount of stranded cost liability of 
the customer(s) and calculation method) nevertheless will be deemed an 
``explicit stranded cost provision.'' However, a provision in a 
requirements contract executed after July 11, 1994 but before the date 
on which this Final Rule is published in the Federal Register that 
merely postpones the issue of stranded cost recovery without 
specifically providing for such recovery will not be considered an 
``explicit stranded cost provision.'' After the date on which this 
Final Rule is published in the Federal Register, a provision must 
identify the specific amount of stranded cost liability of the 
customer(s) and a specific method for calculating the stranded cost 
charge or rate in order to constitute an ``explicit stranded cost 
provision.''
    We reaffirm that a requirements contract that is extended or 
renegotiated for an effective date after July 11, 1994 becomes a 
``new'' requirements contract for which stranded cost recovery will be 
allowed only if explicitly provided for in the contract.
    We also reaffirm our preliminary determination not to impose a 
regulatory obligation on wholesale requirements suppliers to continue 
to serve their existing requirements customers beyond the end of the 
contract term. The only exception to this would be if the customer 
decides to remain a requirements customer for the period for which the 
Commission finds that the supplying utility reasonably expected to 
continue serving the customer. In such a case, the supplying utility 
will be obligated to offer continuing service to the requirements 
customer for the period the utility reasonably expected to continue 
serving the customer.
    A requirements customer will be responsible for planning to meet 
its power needs beyond the end of the contract term by either building 
its own generation, signing a new power sales contract with its 
existing supplier, or contracting with new suppliers in conjunction 
with obtaining transmission service under its existing supplier's open 
access transmission tariff or another utility's transmission system. In 
so holding, it is not our intent to undermine any obligations 
specifically contained in a contract. Thus, if a contract explicitly 
establishes an obligation to serve beyond the end of the contract term, 
such a contractually-imposed obligation to serve (as distinguished from 
a regulatory obligation to serve) would be enforceable as a term of the 
contract. If a wholesale customer that switches suppliers later seeks 
to reestablish service with its former supplier, it will be up to the 
parties to negotiate their respective obligations.
    We also reaffirm our preliminary determination to no longer require 
prior notice of termination under Sec. 35.15 for any power sales 
contract executed on or after the effective date of the Final Rule pro 
forma tariff (but to require written notification of the termination of 
such contract within 30 days after termination takes places). This 
determination goes hand-in-hand with our determination (discussed 
above) not to impose a regulatory obligation on wholesale requirements 
suppliers to continue to serve their existing requirements customers 
beyond the end of the contract term.<SUP>652 We clarify, however, that 
this decision applies only to a power sales contract that is to 
terminate by its own terms (such as on the contract's expiration date). 
We have revised Sec. 35.15 accordingly. We will, however, continue to 
require prior notice of cancellation or termination for any power sales 
contract that is proposed to be cancelled or terminated for a reason 
other than by the contract's own terms (such as a self-help provision 
related to, for example, a billing dispute), regardless of when the 
contract was executed. We also will continue to require prior notice of 
the proposed termination of any power sales contract executed before 
the effective date of the Final Rule pro forma tariff (even if the 
contract is to terminate by its own terms) as well as any unexecuted 
power sales contract that was filed before that date.
---------------------------------------------------------------------------

    \652\ Although several commenters have asked the Commission to 
retain the prior notice of termination filing requirement due to 
concern that a utility nevertheless may be able to exercise 
generation market power with regard to a ``new'' wholesale 
requirements contract, we do not believe that retention of that 
provision is necessary to address these commenters' concerns. 
Instead, any party claiming to be aggrieved by a utility's alleged 
abuse of generation market power under a wholesale requirements 
contract can file a complaint with the Commission under section 206 
of the FPA.
---------------------------------------------------------------------------

    Further, we will retain the Sec. 35.15 filing requirement for all 
transmission contracts. The reason for retaining the Sec. 35.15 
requirement for transmission contracts is that transmission will 
continue to be provided under conditions of potential market power, and 
the Commission must be assured that transmission owners are not 
exerting market power in termination of transmission contracts. In 
addition, this filing requirement will provide the customer an 
opportunity to notify the Commission if the termination terms are 
disputed or if the customer was not given adequate opportunity to 
exercise its limited right of first refusal under the Final Rule (see 
Section IV.A.5).
5. Recovery of Stranded Costs Associated With Existing Wholesale 
Requirements Contracts
    In the Supplemental Stranded Cost NOPR, the Commission reaffirmed 
its proposal to permit the recovery of legitimate, prudent and 
verifiable stranded costs for a discrete set of ``existing'' wholesale 
requirements contracts (executed on or before July 11, 1994)--those 
that do not already contain exit fees or other explicit stranded cost 
provisions. We encouraged the parties to such contracts to renegotiate 
them to address stranded costs. In the case of existing contracts that 
already contain an exit fee or explicit stranded cost provision, 
however, we proposed to reject a unilateral stranded cost amendment; 
that is, we stated we would reject an amendment unless the contract 
permits renegotiation of the existing stranded cost provision or the 
parties to the contract mutually agree to renegotiate the 
contract.<SUP>653 In so doing, we proposed to drop the three year 
mandatory negotiation period suggested in the initial Stranded Cost 
NOPR.<SUP>654
---------------------------------------------------------------------------

    \653\ FERC Stats. & Regs. para. 32,514 at 33,113.
    \654\ We invited comments on this proposal. Id. at 33,115.
---------------------------------------------------------------------------

    If an existing requirements contract does not contain an exit fee 
or other explicit stranded cost provision (and is not renegotiated to 
add such a provision), we proposed that before the expiration of the 
contract: (1) A public utility or its customer may file a proposed 
stranded cost amendment to the contract under section 205 or 206; or 
(2) a public utility or transmitting utility may file a proposal to 
recover stranded costs associated with any such existing contract 
through its transmission rates for a customer that uses the utility's 
transmission system to reach another generation supplier.

[[Page 21640]]

    In the Supplemental Stranded Cost NOPR, we reaffirmed our proposal 
in the initial Stranded Cost NOPR that, even if the contract contains 
an explicit Mobile-Sierra <SUP>655 provision, it is in the public 
interest to permit public utilities to seek unilateral amendments to 
add stranded cost provisions if the contracts do not in essence forbid 
such recovery by containing exit fees or other explicit stranded cost 
provisions.<SUP>656 Under these circumstances, if neither of the 
parties seeks and obtains acceptance or approval of a stranded cost 
amendment, we propose to permit the public utility to seek recovery of 
stranded costs through its wholesale transmission rates.
---------------------------------------------------------------------------

    \655\ See United Gas Pipeline Company v. Mobile Gas Service 
Corporation, 350 U.S. 332 (1956); FPC v. Sierra Pacific Power 
Company, 350 U.S. 348 (1956).
    \656\ FERC Stats. & Regs. para. 32,514 at 33,113-14. We noted 
that under the Mobile-Sierra doctrine, a customer may waive its 
right to challenge the contract and/or the utility may waive its 
right to make unilateral rate changes. However, the parties may not 
waive the indefeasible right of the Commission to alter rates that 
are contrary to the public interest. Id. at 33,111.
---------------------------------------------------------------------------

    We also proposed procedures for providing an existing wholesale 
requirements customer advance notice of how the utility would propose 
to calculate costs that the utility claims would be stranded by the 
customer's departure.<SUP>657
---------------------------------------------------------------------------

    \657\ Id. at 33,114-15.
---------------------------------------------------------------------------

Comments
a. July 11, 1994 Cut-Off Date
    A number of commenters ask the Commission to reconsider the July 
11, 1994 cut-off date for distinguishing between ``existing'' and 
``new'' requirements contracts. Some commenters <SUP>658 support 
October 24, 1992 (the date of passage of the Energy Policy Act) as the 
cut-off date on the basis that anyone entering into a wholesale 
requirements contract after that date should have recognized the 
greatly increased possibility of the customer terminating or not 
renewing the contract.
---------------------------------------------------------------------------

    \658\ E.g., ELCON, TAPS, Alcoa, Utilicorp.
---------------------------------------------------------------------------

    Other commenters <SUP>659 support a later date for defining ``new'' 
requirements contracts, such as the date on which the final rule open 
access tariffs become effective. Utilities For Improved Transition 
argues that the Commission cannot retroactively adopt the July 11, 1994 
cut-off date, but must wait until the final rule is issued before 
setting the date after which requirements contracts must contain 
stranded cost provisions in order for stranded cost recovery to be 
allowed.
---------------------------------------------------------------------------

    \659\ E.g., Utilities For Improved Transition, Atlantic City.
---------------------------------------------------------------------------

    Commenters representing electric cooperatives also oppose the July 
11, 1994 cut-off date.<SUP>660 They contend that RUS borrowers were not 
free to negotiate stranded cost amendments to wholesale power contracts 
as soon as the Commission warned them to do so because their wholesale 
power contracts are mandated both as to form and substance by the 
RUS.<SUP>661
---------------------------------------------------------------------------

    \660\ E.g., Basin, Tri-County EC, NW Iowa Cooperative, Baker EC, 
Big Horn EC, Black Hills EC, Bon Homme Yankton EC, Carbon Power, 
Central EC, Douglas EC, East River EC, Ida County REC, James Valley 
EC, Lincoln-Union EC, McKenzie EC, North Dakota RECs, Oahe EC, 
Oliver-Mercer EC, Panhandle Coop, Rushmore EC, San Luis Valley EC, 
Slope EC, Spink EC, Turner-Hutchinson EC, Traverse EC, Union County 
EC, West River EC, Whetstone Valley EC, Woodbury County REC, 
Yellowstone Valley EC.
    \661\ Basin indicates that all such contracts for the sale of 
more than 1,000 kW and any amendments thereto must be specifically 
approved by the RUS.
---------------------------------------------------------------------------

    PA Munis asks the Commission to treat certain contracts that were 
executed before July 11, 1994 (but not approved by the Commission until 
after that date) as ``new'' contracts. PA Munis argues that the 
utility, after issuance of the initial NOPR, could have withdrawn its 
filing of the contract and sought to negotiate an exit fee at that 
time. It submits that the utility's failure to do so would justify a 
finding by the Commission that contracts approved after July 11, 1994 
be treated similarly to contracts executed after that date.
b. Stranded Cost Recovery for Existing Requirements Contracts
    A number of commenters express support for the Commission's 
proposal to permit modification of existing requirements contracts that 
do not already contain exit fees or other explicit stranded cost 
provisions.<SUP>662 NEPCO states its interpretation that the NOPR does 
not consider notice provisions to be ``explicit stranded cost 
provisions;'' it argues that the presence of a notice provision in a 
contract, while bearing on the supplier's ability to demonstrate the 
duration of its reasonable expectation of continued service, should not 
foreclose the amendment of a wholesale contract to add an exit fee or 
similar payment provision. Several other commenters ask the Commission 
to clarify that contracts that contain notice provisions and that 
preclude recovery for termination or reduction of service (but that do 
not necessarily use the terms ``exit fee'' or ``stranded cost''), or 
that expressly provide that stranded costs shall not be charged, cannot 
be reopened for a stranded cost claim.<SUP>663
---------------------------------------------------------------------------

    \662\ E.g., EEI, PSNM, AEP, Consumers Power. Consumers Power 
suggests that the language of proposed Sec. 35.26(c)(1)(iv) be 
modified to recite the Commission's public interest finding.
    \663\ E.g., Concord, Chugach, ME Consumer-Owned Utilities.
---------------------------------------------------------------------------

    A number of other commenters oppose the Commission's proposal to 
permit amendment of wholesale requirements contracts that do not 
address stranded cost recovery, for reasons previously raised in this 
proceeding.<SUP>664 They argue, among other things, that contracts 
should stand on their own. RUS asserts that the integrity of its 
Federal loan program is to a large extent predicated on honoring the 
long-term requirements wholesale power contracts between G&Ts and their 
distribution members.
---------------------------------------------------------------------------

    \664\ E.g., Utilicorp, AMP-Ohio, Environmental Action, DE Muni, 
Arkansas Cities, Direct Service Industries, PA Munis, ABATE, APPA.
---------------------------------------------------------------------------

    Several commenters also challenge the Commission's proposed 
determination that it is in the public interest to permit utilities to 
seek unilateral amendments to add stranded cost provisions to 
requirements contracts. These commenters argue that the NOPR's 
assumptions concerning the financial stability of public utilities are 
unsupported and thus do not meet the burden of proof required for the 
public interest finding under the Mobile-Sierra doctrine. They urge the 
Commission to require a utility-specific finding of imminent financial 
jeopardy before overriding a Mobile-Sierra contract.<SUP>665
---------------------------------------------------------------------------

    \665\ See, e.g., American Forest & Paper, VT DPS, PA Munis, 
ABATE, ELCON, APPA, Environmental Action.
---------------------------------------------------------------------------

    ELCON argues that the recent Northeast Utilities Service Company v. 
FERC <SUP>666 case reaffirms the traditional high threshold for 
overriding Mobile-Sierra clauses in the ``classic Mobile-Sierra 
situation'' in which one of the parties seeks modification of a 
contract that has already been reviewed and approved by the Commission. 
It submits that a utility seeking to add a stranded cost provision to 
an existing contract would fall within the ``classic situation.'' ELCON 
also argues that the First Circuit strongly implied that to satisfy 
Mobile-Sierra, the Commission must identify specifically those aspects 
of a contract that are contrary to the public interest and why. On this 
basis, ELCON argues that the case supports its position that a utility-
specific finding of imminent financial jeopardy is necessary to 
override an existing Mobile-Sierra contract.<SUP>667
---------------------------------------------------------------------------

    \666\ 55 F.3d 686 (1st Cir. 1995) (Northeast Utilities).
    \667\ PA Munis argues that Northeast Utilities provides no 
support for the Commission's proposed Mobile-Sierra finding because 
Northeast Utilities involved the effect of disputed contractual 
terms on third parties, not the alleged financial effect on the 
utility. It argues that the court found that the Commission had 
adequately explained how the disputed contractual terms may harm 
third parties to the contract (which PA Munis says the Commission 
has failed to do here). PA Munis also submits that the court went 
out of its way to emphasize the narrow scope of its order affirming 
the Commission.

---------------------------------------------------------------------------

[[Page 21641]]

    Some commenters argue that if utilities are to be granted industry-
wide Mobile-Sierra relief, then the Commission should give wholesale 
customers the reciprocal right to convert their wholesale power 
contracts to transmission-only service.<SUP>668 However, EEI contends 
that the Commission is barred by section 211(c)(2) of the FPA from 
ordering wheeling where a customer is taking service under a contract 
or under a rate tariff on file with the Commission.
---------------------------------------------------------------------------

    \668\ E.g., ELCON, CCEM, VT DPS, OK Com, TDU Systems, LG&E, 
ABATE, Portland, Utilicorp, TAPS.
---------------------------------------------------------------------------

    Several commenters ask the Commission to require renegotiation of 
the notice and/or term of all existing contracts with long lead-time 
cancellation provisions in order to allow all wholesale customers 
access to the market at the same time.<SUP>669 They submit that 
customers with short notice provisions will be the first to enjoy the 
benefits of open access and will have an effective ``first right of 
refusal'' of the most economical transmission paths and low cost 
suppliers, putting customers with long lead-time cancellations at a 
competitive disadvantage.
---------------------------------------------------------------------------

    \669\ E.g., Knoxville, Memphis.
---------------------------------------------------------------------------

c. Transition Period
    A number of commenters support the Commission's proposal not to 
mandate a three-year time limit for renegotiation of existing wholesale 
requirements contracts. They note that existing contracts have unique 
characteristics and complexities that affect the time required to 
renegotiate the contract bilaterally, to file a unilateral amendment 
with the Commission, or to file for stranded cost recovery through 
transmission rates.<SUP>670
---------------------------------------------------------------------------

    \670\ E.g., EEI, Florida Power Corp, PA Com, WP&L, Consumers 
Power, FL Com, TVA, SoCal Edison, Texas Utilities.
---------------------------------------------------------------------------

    On the other hand, some commenters object that the proposal to 
replace the previously proposed three-year window with an opportunity 
to raise stranded cost claims throughout the existing contract term 
creates a virtually unlimited transition period.<SUP>671 For example, 
ELCON asserts that because the NOPR would allow utilities to seek 
amendment of an existing contract any time prior to its expiration, 
stranded cost issues could extend through the life of existing 
facilities (30 years or more). Portland suggests that the Commission 
set a schedule now for proceedings to determine transmission costs and 
stranded costs for each utility with wholesale requirements customers.
---------------------------------------------------------------------------

    \671\ E.g., TAPS, TDU Systems, DOD, ELCON, APPA.
---------------------------------------------------------------------------

    Commenters propose various limits to the period within which 
stranded cost recovery could be raised, such as: (i) Three to five 
years; <SUP>672 (ii) the lesser of three years from the effective date 
of the final rule or the remaining term of the contract; <SUP>673 (iii) 
one year from the effective date of the final rule; <SUP>674 and (iv) 
December 31, 1998 (20 years after PURPA).<SUP>675
---------------------------------------------------------------------------

    \672\ E.g., Sierra, Central Illinois Light, NY Energy Buyers, 
American Forest & Paper, WEPCO, EGA. Education proposes either a 
transition period that ends five years after the effective date of 
the final rule or a phase-out of the utility's authority to recover 
stranded costs from departing customers by gradually reducing (for 
instance, over a ten year period from the date of the final rule) 
the percentage of stranded costs that the utility could recover.
    \673\ E.g., TAPS, Missouri Joint Commission.
    \674\ E.g., TDU Systems.
    \675\ E.g., DOD, ABATE.
---------------------------------------------------------------------------

Commission Conclusion
a. July 11, 1994 Contract Cut-Off Date
    We reaffirm our proposal to permit the recovery of legitimate, 
prudent and verifiable stranded costs for ``existing'' wholesale 
requirements contracts (executed on or before July 11, 1994) that do 
not already contain exit fees or other explicit stranded cost 
provisions. We believe that July 11, 1994--the date on which the 
initial Stranded Cost NOPR was published and, thus, on which the 
industry was put on notice of the proposal to disallow prospectively 
extra-contractual recovery of stranded costs--is the appropriate date 
for distinguishing ``existing'' requirements contracts from ``new'' 
requirements contracts. Because all parties were put on notice in the 
initial Stranded Cost NOPR that July 11, 1994 would be the operable 
date for the ``existing''/``new'' contract distinction, utilities that 
executed requirements contracts after that date could have had no 
reasonable expectation that they would be permitted to recover any 
costs extra-contractually.
    Moreover, because the costs at issue are extra-contractual costs, 
the Commission's notice to all parties that contracts executed after 
July 11, 1994 will be enforced by their terms as far as stranded cost 
recovery is concerned does not constitute ``retroactive rulemaking.'' 
Contrary to UFIT's contention, the Commission is not ``requir[ing]'' 
utilities to include stranded cost recovery provisions in all contracts 
executed after July 11, 1994.<SUP>676 The Commission has merely put all 
parties on notice that the opportunity for extra-contractual stranded 
cost recovery (which will be allowed on a prospective basis upon the 
effective date of the Rule) will not be available for any requirements 
contracts executed after July 11, 1994. The parties to requirements 
contracts executed after July 11, 1994 have been free to provide for 
stranded cost recovery in the contract, or not.<SUP>677 The point is 
that, for requirements contracts executed after the cut-off date, 
stranded cost recovery will be governed solely by the terms of the 
contract.
---------------------------------------------------------------------------

    \676\ See UFIT Initial Comments at 34. Moreover, the cases that 
UFIT cites, in which the Commission rejected parties' efforts to 
devise rates based on methods or formulas contained in proposed 
rules, are inapposite. By establishing the July 11, 1994 cutoff 
date, the Commission is not ``fix(ing) rates under section 206'' or 
otherwise making ``a Section 206 `determination,' '' as UFIT 
suggests. Id. at 35, 36. The Commission has not proposed a change in 
the way that utilities compute their rates; it has simply put all 
parties on notice of the limited nature and opportunity for extra-
contractual stranded cost recovery.
    \677\ In response to the commenters representing electric 
cooperatives that object to the July 11, 1994 cut-off date, we do 
not believe that the requirement that RUS borrowers obtain RUS 
approval of their contracts necessarily prevents such borrowers from 
addressing stranded cost recovery in contracts executed after July 
11, 1994.
---------------------------------------------------------------------------

b. Stranded Cost Recovery for Existing Requirements Contracts
    We reaffirm that we will permit utilities to seek recovery of 
stranded costs for a limited set of existing wholesale requirements 
contracts, namely, those that do not already contain exit fees or other 
explicit stranded cost provisions.<SUP>678 If an existing requirements 
contract includes an explicit provision for payment of stranded costs 
or an exit fee, we will assume that the parties intended the contract 
to cover the contingency of the buyer leaving the system. We will 
reject a stranded cost amendment to such a contract, unless the 
contract permits renegotiation of the existing stranded cost provision 
or the parties to the contract mutually agree to a new stranded cost 
provision. Similarly, we will reject a stranded cost amendment to an 
existing requirements contract if the contract prohibits stranded cost 
recovery (or precludes recovery for termination or reduction of 
service) or

[[Page 21642]]

prohibits renegotiation of an existing stranded cost or exit fee 
provision, unless the parties to the contract mutually agree to a new 
stranded cost provision.<SUP>679
---------------------------------------------------------------------------

    \678\ We confirm that a notice of termination provision by 
itself (that is, one that does not also provide for or preclude 
recovery of stranded costs by the seller upon termination of the 
contract) is not an ``explicit'' stranded cost provision; however, 
as discussed in Section IV.J.8, the presence of a notice provision 
creates a rebuttable presumption that the utility had no reasonable 
expectation of continuing to serve the customer.
    \679\ In the case of an existing wholesale requirements contract 
that does not contain an exit fee or other explicit stranded cost 
provision but does contain a notice provision, once a customer gives 
notice according to the terms of the contract that it will no longer 
purchase all or a part of its requirements from the selling utility, 
we would not allow the utility to amend the contract to add a 
stranded cost provision. However, in such a case, the utility could 
seek to recover stranded costs through its rates for transmission 
services to the customer. As discussed in Section IV.J.8, the 
utility would have to rebut the presumption that, based on the 
presence of the notice provision, it had no reasonable expectation 
of continuing to serve the customer.
---------------------------------------------------------------------------

    We reaffirm our desire that utilities attempt to renegotiate with 
their customers existing requirements contracts that do not contain 
exit fees or other explicit stranded cost provisions. If the parties 
negotiate a stranded cost provision and the seller is A public utility, 
the utility must file the provision with the Commission as an amendment 
to the existing requirements contract.
    If an existing requirements contract does not contain an exit fee 
or other explicit stranded cost provision (and is not renegotiated to 
add such a provision), before the expiration of the contract: (1) a 
public utility or its customer may file a proposed stranded cost 
amendment to the contract under section 205 or 206; or (2) a public 
utility in a section 205 proceeding, or a transmitting utility in a 
section 211 proceeding, may file a proposal to recover stranded costs 
associated with any such existing contract through its transmission 
rates for a customer that uses the utility's transmission system to 
reach another generation supplier.
    We thus reaffirm that if an existing requirements contract is not 
renegotiated, and the contract permits the seller and/or buyer to seek 
an amendment to the contract, the authorized party may seek an 
amendment to add a stranded cost provision. We also adopt our 
preliminary finding that, even if an existing requirements contract 
contains an explicit Mobile-Sierra provision, it is in the public 
interest to permit the public utility to seek a unilateral amendment to 
add stranded cost provisions if the contract does not already contain 
exit fees or other explicit stranded cost provisions. In the initial 
Stranded Cost NOPR, we identified two ways in which a failure to permit 
public utilities to address stranded costs could harm third parties, 
and thereby harm the public interest:

    First, the inability to seek recovery of stranded costs could 
impair the financial ability of a utility to continue to provide 
reliable service. This will depend on the magnitude of stranded 
costs and the prospect or lack thereof for recovering such costs 
from ratepayers. The prospect of not recovering from ratepayers 
significant amounts of stranded costs could seriously erode a 
utility's access to capital markets, or could drive the utility's 
cost of capital to unprecedented levels. This high cost of capital 
could precipitate other customers leaving the system which, in turn, 
could cause others to leave. Such a spiral could be difficult to 
stop once begun. Second, if some customers are permitted to leave 
their suppliers without paying for stranded costs, this may cause an 
excessive burden on the remaining customers who, for whatever 
reason, cannot leave and therefore may have to bear those 
costs.<SUP>680

    \680\ FERC Stats. & Regs. para. 32,507 at 32,870.
---------------------------------------------------------------------------

    The financial community commenters confirm our views in this 
regard. As they note, a utility's access to financial markets is 
essential to the continued provision of safe and reliable electric 
service to customers. However, the prospect of a utility not recovering 
stranded costs could erode a utility's ability to attract capital and 
thus imperil its continued financial stability.<SUP>681 As these and 
other commenters agree, the recovery of stranded costs is critical to 
the successful transition to more competitive markets.
---------------------------------------------------------------------------

    \681\ See Utility Investors Analysts, Initial Comments at 2-3; 
Utility Shareholders, Initial Comments at 2-4.
---------------------------------------------------------------------------

    Moreover, our determination that it is in the public interest to 
give public utilities a limited opportunity to propose contract changes 
unilaterally to address stranded costs if their contracts do not 
already explicitly do so satisfies the public interest standard of the 
Mobile-Sierra doctrine as recently interpreted by the Northeast 
Utilities court. In that case, the court affirmed an order of the 
Commission on remand modifying a contract under the Mobile-Sierra 
public interest standard.<SUP>682 As the court explained, the Mobile-
Sierra doctrine ``represents the Supreme Court's attempt to strike a 
balance between private contractual rights and the regulatory power to 
modify contracts when necessary to protect the public interest.'' 
<SUP>683 The court noted that when the Commission is considering 
whether a contract rate is too low, protective action by the Commission 
in the public interest is justified ``where the rate might impair the 
financial ability of the utility to continue to supply electricity, 
force electricity consumers to bear an excessive burden, or be unduly 
discriminatory.'' <SUP>684
---------------------------------------------------------------------------

    \682\ The court concluded that the Commission ``gave thoughtful 
consideration to the public interest.'' 55 F.3d at 693.
    \683\ Id. at 689.
    \684\ Id. at 690.
---------------------------------------------------------------------------

    The court also explained that ``the most attractive case for 
affording additional protection [under the public interest standard], 
despite the presence of a contract, is where the protection is intended 
to safeguard the interests of third parties * * *.' '' <SUP>685 It 
stated that the Mobile-Sierra doctrine allows the Commission to modify 
the terms of a private contract ``when third parties are threatened by 
possible `undu[e] discrimination' or the imposition of an `excessive 
burden.' '' <SUP>686 The court found that the Commission had met the 
public interest standard by showing how the contract could harm third 
parties.<SUP>687
---------------------------------------------------------------------------

    \685\ Id. at 691, citing Northeast Utilities Service Company v. 
FERC, 993 F.2d 937, 961 (1st Cir. 1993).
    \686\ Northeast Utilities, 55 F.3d at 691. The court 
distinguished the facts of that case from other Mobile-Sierra cases. 
It noted that ``[t]he issue here is not whether one party to a rate 
contract filed with FERC can effect a rate change unilaterally, but 
the standard to be used by FERC in examining electric power 
contracts filed with it.'' Id. at 690-91. It also noted that the 
contract provisions under review were not low-rate issues in the 
context of Mobile and Sierra. We recognize that whether a contract 
should be modified to add a stranded cost provision could be viewed 
as one party to a contract seeking to effect a unilateral rate 
change, or as a low-rate issue (i.e., whether the utility's rates 
would be insufficient without stranded cost recovery). However, 
parties are being permitted to make such unilateral filings only 
after a generic finding by the Commission that the public interest 
likely would be jeopardized if utilities are not permitted to make a 
case-specific showing that recovery should be allowed. We believe 
that Northeast Utilities provides valuable guidance concerning 
application of the public interest standard where, as here, a 
failure to allow limited contract modification may harm the public 
interest by harming third parties.
    \687\ The court found that the Commission had met the public 
interest standard ``by explaining how the disputed contractual terms 
may harm third parties to the contract. * * * For example, the 
Commission found the automatic rate-of-return-on-equity adjustment 
provision unacceptable because third parties may ultimately bear the 
burden of a rate component that does not reflect actual capital 
market conditions. Likewise, the `blank check' given owners of the 
power plant to determine the decommissioning costs for themselves 
under New Hampshire law is impermissible because it may be cashed at 
the expense of non-parties to the contract.'' Id. at 692 (emphasis 
in original). The court rejected the argument that the public 
interest standard is ``practically insurmountable'' in all 
circumstances. It noted, among other things, ``that neither Mobile 
nor Sierra stated or intimated that the `public interest' doctrine 
was `practically insurmountable.' '' Id. at 691.
---------------------------------------------------------------------------

    Consistent with the holding in Northeast Utilities, and contrary to 
the positions of some commenters, we have demonstrated how ``third 
parties may ultimately bear the burden'' <SUP>688 if public utilities 
with Mobile-Sierra contracts are not given any opportunity to propose 
contract changes to address stranded costs. If the Commission fails to 
give a

[[Page 21643]]

public utility this opportunity, and the utility's financial ability to 
continue the provision of safe and reliable service is impaired, third 
parties (customers relying on the public utility for their electric 
service) will be placed at risk. Similarly, if the Commission fails to 
give a public utility the opportunity to directly assign costs to the 
customers on whose behalf they were incurred, and some of the utility's 
customers leave the utility's generation system for that of another 
supplier without paying such costs, third parties (the utility's 
remaining customers) will be harmed by having to bear the costs that 
were not incurred to serve them and that are stranded by the other 
customers' departures via open access transmission. Moreover, we 
believe that protective action in the public interest is particularly 
necessary where, as here, a utility's rates could become insufficient 
because of fundamental changes in the industry that largely result from 
legislative or regulatory changes that could not be anticipated.
---------------------------------------------------------------------------

    \688\ Id. at 692 (emphasis in original).
---------------------------------------------------------------------------

    Further, notwithstanding the arguments of some commenters 
supporting a case-by-case (as opposed to a generic) public interest 
finding, we believe it appropriate that our public interest finding be 
made on a generic basis given the fact that, by this Rule, we are 
requiring full open access that could significantly affect historical 
relationships among traditional utilities and their customers and the 
ability of utilities to recover prudently incurred costs. We also 
emphasize that we are not eliminating the need for case-by-case 
demonstrations that stranded cost recovery should be allowed. Our 
public interest finding is that utilities be permitted to seek extra-
contractual recovery of stranded costs in certain defined 
circumstances. Utilities seeking recovery of stranded costs will have 
the burden, on a case-by-case basis, of showing they had a reasonable 
expectation of continuing to serve the departing generation customer.
    In summary, we emphasize the limited nature of our Mobile-Sierra 
public interest finding. First, our holding applies only to wholesale 
requirements contracts executed on or before July 11, 1994 that do not 
contain an exit fee or other explicit stranded cost provision. Thus, we 
will not permit modification of any contract that addresses the 
stranded cost issue explicitly, unless the contract specifically 
permits such modifications. Instead, we are simply examining 
requirements contracts that do not clearly address the issue in the 
context of the traditional regulatory regime under which they were 
signed--a regulatory environment in which it was assumed as a matter of 
course that the great majority of requirements customers would stay 
with their original suppliers and that these suppliers had a 
concomitant obligation to plan to supply these customers' continuing 
needs.
    Second, although we have decided on a generic basis that it is in 
the public interest to permit public utilities with Mobile-Sierra 
contracts to make unilateral filings, we are not automatically 
approving any amendment that a particular utility might file. As we 
stated in the initial Stranded Cost NOPR, if a public utility 
unilaterally files a proposed stranded cost amendment under either 
section 205 or 206 of the FPA, this does not necessarily mean that the 
Commission ultimately will find it appropriate to allow such 
amendment.<SUP>689 In addition, customers with Mobile-Sierra contracts 
that do not explicitly address stranded costs may also file complaints 
under section 206 of the FPA to propose to address stranded costs in 
existing requirements contracts. The Commission will analyze any 
proposed stranded cost amendment to a Mobile-Sierra contract, whether 
proposed by the utility or by its customer, based on the particular 
circumstances surrounding that contract. Thus, the case-by-case 
findings that some commenters seek will, in effect, be made when the 
Commission determines whether to approve a proposed stranded cost 
amendment to a particular contract.
---------------------------------------------------------------------------

    \689\ FERC Stats. & Regs. para. 32,507 at 32,871.
---------------------------------------------------------------------------

    As discussed in Section IV.A (Scope), the Commission has concluded 
that although current conditions in the wholesale power market do not 
warrant the generic modification of requirements contracts, nonetheless 
the modification of certain requirements contracts on a case-by-case 
basis may be appropriate. We have concluded further that, even if 
customers under such contracts are bound by so-called Mobile-Sierra 
clauses, they nonetheless ought to have the opportunity to demonstrate 
that their contracts no longer are just and reasonable.
    We have found that it would be against the public interest to 
permit a Mobile-Sierra clause in an existing wholesale requirements 
contract to preclude the parties to such a contract from the 
opportunity to realize the benefits of the competitive wholesale power 
markets. For purposes of this finding, the Commission defines existing 
requirements contracts as contracts executed on or before July 11, 
1994.<SUP>690 By operation of this finding, a party to a requirements 
contract containing a Mobile-Sierra clause no longer will have the 
burden of establishing independently that it is in the public interest 
to permit the modification of such contract. The party, however, still 
will have the burden of establishing that such contract no longer is 
just and reasonable and therefore ought to be modified.
---------------------------------------------------------------------------

    \690\ This is consistent with the definition of existing 
requirements contracts we have used for purposes of stranded cost 
recovery.
---------------------------------------------------------------------------

    This finding complements the Commission's finding that, 
notwithstanding a Mobile-Sierra clause in an existing requirements 
contract, it is in the public interest to permit amendments to add 
stranded cost provisions to such contracts if the public utility 
proposing the amendment can meet the evidentiary requirements of this 
Rule. The Commission's complementary Mobile-Sierra findings are not 
mutually exclusive. Any contract modification approved under this 
section shall provide for the utility's recovery of any costs stranded 
consistent with the contract modification. The stranded costs must be 
prudently incurred, legitimate and verifiable. Further, the Commission 
has concluded that if a customer is permitted to argue for modification 
of existing contracts that are less favorable to it than other 
generation alternatives, then the utility should be able to seek 
modification of contracts that may be beneficial to the customer.
    The Commission believes that the most productive way to analyze 
contract modification issues is to consider simultaneously both the 
selling public utility's claims, if any, that it had a reasonable 
expectation of continuing to serve the customer beyond the term of the 
contract and the customer's claim, if any, that the contract no longer 
is just and reasonable and therefore ought to be modified. Thus, if the 
selling public utility intends to claim stranded costs, it must present 
that claim in any section 206 proceeding brought by the customer to 
shorten or terminate the contract. Similarly, if the customer intends 
to claim that the notice or termination provision of its existing 
requirements contract is unjust and unreasonable, it must present that 
claim in any proceeding brought by the selling public utility to seek 
recovery of stranded costs. This will promote administrative efficiency 
and will permit the Commission to consider how the contracting parties' 
claims bear on one another.

[[Page 21644]]

    The Commission does not take contract modification lightly. Whether 
a utility is seeking a contract amendment to permit stranded cost 
recovery based on expectations beyond the stated term of the contract, 
or a customer is seeking to shorten or eliminate the term of an 
existing contract, we believe that each have a heavy burden in 
demonstrating that the contract ought to be modified. Still, we believe 
that given the industry circumstances now facing us, both selling 
utilities and their customers ought to have an opportunity to make the 
case that their existing requirements contracts ought to be modified. 
By providing both buyers and sellers this opportunity, the Commission 
attempts to strike a reasonable balance of the interests of all market 
participants. The Commission expects that many of the arguments 
presented by buyers and sellers in such proceedings will be fact 
specific.
c. Transition Period
    We reaffirm our proposal to allow a public utility or its customer 
to file a proposed stranded cost amendment, or to allow a public 
utility or transmitting utility to file a proposal to recover stranded 
costs through a departing generation customer's transmission rates, at 
any time prior to the expiration of the contract. There is no uniform 
time remaining on requirements contracts executed on or before July 11, 
1994. Any limitation on the period in which parties could propose 
amendments covering stranded costs (e.g., 3 years) would thus unequally 
affect market participants. Those with long terms remaining on their 
contracts could object that immediately addressing the issue would not 
be cost effective. For example, a utility with a long remaining term 
(e.g., 20 years) might not even seek stranded cost recovery depending 
on the competitive value of its assets near the end of the contract 
term.<SUP>691 However, such a utility would invariably seek to preserve 
its option to seek stranded cost recovery if its failure to do so 
within a short period resulted in a waiver of its right to do so.
---------------------------------------------------------------------------

    \691\ The value of its assets could vary over time as new 
technologies emerge, fuel costs fluctuate, or environmental 
requirements change.
---------------------------------------------------------------------------

6. Recovery of Stranded Costs Caused by Retail-Turned-Wholesale 
Customers
    In the Supplemental Stranded Cost NOPR, we stated that both this 
Commission and state commissions have the legal authority to address 
stranded costs that result from retail customers becoming wholesale 
customers who then obtain transmission under the open access 
tariffs.<SUP>692 We proposed that this Commission should be the primary 
forum for addressing the recovery of stranded costs caused by retail-
turned-wholesale customers. We explained that if a retail customer 
becomes a legitimate wholesale customer (such as through 
municipalization), it becomes eligible to use the non-discriminatory 
open access tariffs:

    \692\ FERC Stats. & Regs. para. 32,514 at 33,127.
---------------------------------------------------------------------------

    If costs are stranded as a result of this wholesale transmission 
access, we believe that these costs should be viewed as `wholesale 
stranded costs.' But for the ability of the new wholesale entity to 
reach another generation supplier through the FERC-filed open access 
transmission tariff, such costs would not be stranded.<SUP>693

    \693\ Id. at 33,128.
---------------------------------------------------------------------------

    We accordingly proposed to define ``wholesale stranded costs'' to 
include stranded costs resulting from unbundled transmission for newly-
created wholesale customers and sought comments on this definition.
    We proposed to require the same evidentiary demonstration for 
recovery as that required if recovery were sought from a wholesale 
requirements customer. We reaffirmed our proposal in the initial 
Stranded Cost NOPR that a utility will have to show that the stranded 
costs are not more than the net revenues that the retail-turned-
wholesale customer would have contributed to the utility had it 
remained a retail customer of the utility, and that the utility has 
taken and will take reasonable steps to mitigate stranded costs. We 
further proposed to deduct any recovery that a state has permitted from 
departing retail-turned-wholesale customers from the legitimate 
stranded costs of which we will allow recovery. In addition, we 
proposed to apply the same procedures for obtaining an estimate of 
maximum stranded cost exposure without mitigation to retail customers 
contemplating becoming wholesale transmission customers as those 
proposed for wholesale customers.<SUP>694
---------------------------------------------------------------------------

    \694\ Id.
---------------------------------------------------------------------------

Comments
    Some commenters contend that stranded costs that result when a 
retail customer becomes a wholesale customer should be left to the 
states as a matter of law and comity.<SUP>695 These commenters argue, 
among other things, that because the facilities used to provide retail 
service to these retail customers were subject to state jurisdiction 
and were included in retail rate base when the service was rendered, 
the state is the appropriate entity to determine the extent to which 
those customers should compensate the utility for the stranding of 
these costs. According to ELCON, ``(a) retail customer's new found 
access to the wholesale market does not provide FERC with authority 
over costs that originated with the local distribution function.'' 
<SUP>696
---------------------------------------------------------------------------

    \695\ E.g., NARUC, ELCON, TAPS, NASUCA, N.Y. Mayors, NY 
Industrials, American Iron & Steel, Missouri Joint Commission, Omaha 
PPD, MI Com, NY Com, NJ BPU, VT DPS, OK Com, IN Com, UT Com, WA Com, 
Environmental Action, IN Industrials, LA DWP, Seattle, CAMU, Las 
Cruces, UT Industrials, Suffolk County, NM Industrials, CO Consumers 
Counsel.
    \696\ ELCON Comments, dated July 25, 1995, at 41.
---------------------------------------------------------------------------

    Commenters assert that stranded costs resulting from the creation 
of new wholesale entities will occur as a result of state or local 
decisionmaking.<SUP>697 A number of commenters contend that in states 
where the state commission has control over municipalization, the 
Commission has no authority to provide for the recovery of stranded 
costs due to municipalization.<SUP>698 IL Com asserts that the 
Commission lacks authority over retail-turned-wholesale stranded costs, 
even in the absence of any explicit statutory authority for state 
commissions to address such costs. FL Com argues that the Commission 
should address the recovery of these stranded costs only upon petition 
from a state public utility commission.
---------------------------------------------------------------------------

    \697\ E.g., MD Com, MI Com, LA DWP, Las Cruces. For example, MD 
Com states that while open access transmission may make 
municipalization more attractive, it ultimately is MD Com's approval 
that makes municipalization possible in Maryland.
    \698\ E.g., MD Com, Las Cruces, Caparo, Coalition on Federal-
State Issues, IN Com, MI Com, Iowa Board.
---------------------------------------------------------------------------

    According to some commenters, the availability of open access 
transmission tariffs does not convert the character of the costs of 
stranded generation that was built to serve retail customers from 
retail to wholesale.<SUP>699 CA Com argues that this reasoning could 
require the Commission to act as the primary forum for stranded costs 
resulting from retail wheeling if the Commission's jurisdiction over 
retail transmission is upheld. It argues that in such a case, there 
also would be a relationship between the Commission-jurisdictional 
transmission and stranded costs.
---------------------------------------------------------------------------

    \699\ E.g., IL Com, CA Com, Midwest Commissions, CO Consumers 
Counsel.
---------------------------------------------------------------------------

    Some commenters also submit that the potential for retail customers 
to become wholesale customers has existed since the beginning of the 
industry and that utilities have had ample opportunity to adjust to 
this risk.<SUP>700 A number of commenters submit

[[Page 21645]]

that state commissions are in a better position than the Commission to 
address the recovery of costs that were incurred to serve retail 
customers and to take into consideration local concerns.<SUP>701
---------------------------------------------------------------------------

    \700\ E.g., LA DWP, Ohio Manufacturers, MMWEC, American Iron & 
Steel, UT Industrials, MI Com, NY Industrials, WA Com, Caparo.
    \701\ E.g., American Iron & Steel, MD Com, LA DWP, Suffolk 
County, MI Com, NJ BPU, N.Y. Mayors. NASUCA cites practical problems 
posed by the Commission's proposal to assume jurisdiction over 
stranded costs resulting from municipalization, such as how the 
Commission would transfer the revenues extracted from the retail-
turned-wholesale customer to a non-wholesale, locally-franchised 
entity.
---------------------------------------------------------------------------

    NARUC recognizes that a ``practical regulatory gap may exist that 
prevents [state commission] consideration of recovery of * * * 
potentially stranded costs'' in certain instances ``such as 
municipalization and cooperatives, where retail customers become 
wholesale customers under a FERC-approved open access tariff, [and] 
costs of the utility which served the customer at retail may become 
stranded.'' <SUP>702 NARUC proposes that the affected states and the 
Commission collaboratively develop mechanisms (which may involve 
amendments to the FPA, state statutes, or both) to eliminate these 
regulatory gaps.
---------------------------------------------------------------------------

    \702\ NARUC Initial Comments at 18-19.
---------------------------------------------------------------------------

    Some commenters object that the Commission's proposal to be the 
primary forum for recovery of stranded costs caused by retail-turned-
wholesale customers would make municipalization more expensive and 
therefore would discourage municipalities from seeking alternative 
sources of electricity.<SUP>703 Some argue that different treatment of 
stranded costs between federal and state authorities may lead to forum-
shopping as a primary determinant in the decision to 
municipalize.<SUP>704
---------------------------------------------------------------------------

    \703\ E.g., N.Y. Mayors, NIEP, Wing Group, VT DPS, NY 
Industrials, American Iron & Steel, Environmental Action, IN 
Industrials, Las Cruces, Caparo, UT Industrials.
    \704\ E.g., IN Com.
---------------------------------------------------------------------------

    A number of commenters also suggest that the NOPR is inconsistent 
with prior Commission treatment of municipalization because the 
Commission has historically promoted franchise competition between 
municipalities and utilities and has never before suggested that 
utilities could ``penalize'' municipalization decisions through 
generation cost add-ons to transmission rates.<SUP>705 VT DPS states: 
``By the Commission's logic, there would never have been an Otter Tail 
case. If Otter Tail could have made a stranded cost claim against the 
municipal utility Elbow Lake planned to create, Otter Tail would never 
have needed to refuse to wheel.'' <SUP>706
---------------------------------------------------------------------------

    \705\ E.g., VT DPS, American Iron & Steel. American Forest & 
Paper states that allowing stranded cost recovery in the event of 
municipalization would be inconsistent with the Commission's actions 
in the natural gas industry, where the Commission has encouraged 
competition at the retail level (through competitive bypass rather 
than franchise competition) and has not imposed transition charges 
or exit fees on converting customers.
    \706\ VT DPS Initial Comments at 49; see also American Iron & 
Steel, NY Industrials, Caparo.
---------------------------------------------------------------------------

    Suffolk County states that the Commission already considered 
stranded costs in the context of retail-turned-wholesale customers in 
United Illuminating Company,<SUP>707 where the Commission required 
United Illuminating to remove a provision in its proposed transmission 
tariff that would have allowed it to recover stranded costs associated 
with former retail loads served by new municipal systems. Suffolk 
County states that the Commission made clear that stranded cost 
matters, including those caused by municipalization, properly would be 
raised before state regulatory authorities. It objects that the Open 
Access NOPR ignores this case. Suffolk County also submits that the 
Commission's adoption of the settlement approved by the Massachusetts 
DPU in the Massachusetts Bay Transportation Authority case should serve 
as an example of proper jurisdictional deference with respect to local 
issues.<SUP>708
---------------------------------------------------------------------------

    \707\ 63 FERC para. 61,212 (1993), reh'g denied, 64 FERC para. 
61,087 (1993).
    \708\ See Massachusetts Electric Company, 68 FERC para. 61,101 
(1994); Letter Order dated March 3, 1995, Docket No. ER94-129-000 
(approving settlement).
---------------------------------------------------------------------------

    However, many other commenters support the Commission's proposal to 
be the primary forum for retail-turned-wholesale stranded 
costs.<SUP>709 These commenters submit, among other things, that the 
Commission's jurisdiction over such costs is clear.<SUP>710 Coalition 
for Economic Competition states that when a utility's costs are 
stranded through the availability of Commission-jurisdictional 
transmission service, the Commission must address those costs. It 
argues that commenters opposing the Commission's jurisdiction fail to 
analyze the Commission's duty to establish just and reasonable rates 
for Commission-jurisdictional transmission service.
---------------------------------------------------------------------------

    \709\ E.g., EEI, PSE&G, Centerior, Com Ed, Consumers Power, 
Detroit Edison, Duke, El Paso, Entergy, LILCO, Minnesota Power, 
Montana-Dakota Utilities, NYSEG, PECO, PG&E, PSNM, Southern, 
Utilities For Improved Transition, Allegheny, OH Com, Utilicorp, PA 
Com, WI Com, Coalition for Economic Competition, Central Louisiana, 
United Illuminating, Utility Investors Analysts, Nuclear Energy 
Institute, Utility Shareholders.
    \710\ E.g., Consumers Power, Coalition for Economic Competition, 
Utilities For Improved Transition.
---------------------------------------------------------------------------

    A number of commenters support the Commission's proposal to address 
retail-turned-wholesale stranded costs on the basis that many state 
commissions either lack authority to address costs that are stranded 
because of expanding or newly-created municipal systems, or have failed 
to address such costs.<SUP>711 El Paso adds that any protection offered 
by state judicial condemnation proceedings does not obviate the need 
for the Commission's involvement in this issue, noting that 
condemnation awards may not provide full stranded investment recovery 
under the Commission's standards. In addition, El Paso suggests that 
municipalization may occur through means other than condemnation of the 
distribution systems of electric utilities, such as when a municipality 
constructs its own, duplicative distribution facilities.
---------------------------------------------------------------------------

    \711\ E.g., Detroit Edison, Minnesota Power, El Paso, LILCO, 
Centerior, PG&E. PG&E urges a clarification in the rule so that the 
Commission would address retail-turned-wholesale stranded costs only 
if the state commission either lacks jurisdiction over municipal 
utilities, or, if it has jurisdiction, declines to address stranded 
costs. Where a state commission possesses jurisdiction over 
municipal entities and provides a utility with stranded cost 
recovery from former retail customers that have municipalized, PG&E 
proposes that such action should be final and not subject to 
Commission review. Other commenters, such as El Paso, ask the 
Commission to establish itself as the forum of last resort when 
states do not provide for full recovery of stranded costs.
---------------------------------------------------------------------------

    Several commenters also indicate that by forthrightly addressing 
this issue, the Commission has removed a cloud of uncertainty that 
would have taken years to resolve through litigation.<SUP>712 El Paso 
states that the proposed rule is needed because utilities may be 
subject to stranded costs resulting from municipalization in two 
separate state jurisdictions.
---------------------------------------------------------------------------

    \712\ E.g., Coalition for Economic Competition, El Paso.
---------------------------------------------------------------------------

    In response to the argument that stranded costs are exclusively 
subject to state jurisdiction, SoCal Edison asserts that whether the 
costs are retail or wholesale is irrelevant because the issue is how 
and where these costs should be recovered. According to SoCal Edison, 
if the Commission finds that these costs are just and reasonable costs 
associated with providing open access transmission service, the 
Commission may allow utilities to recover them in Commission-regulated 
rates.
    Coalition for Economic Competition notes that while utilities are 
aware of state laws allowing municipalities to condemn electric 
facilities and to form utilities, in recent decades, it has not 
happened on most systems. Moreover, it argues that merely being on 
notice that municipalization is a possibility does not relieve 
utilities of their state-imposed obligation to serve all

[[Page 21646]]

customers in their franchise areas. It asserts that utilities had to 
continue to invest in plant to satisfy their duty to serve. In 
addition, it submits that utilities had a reasonable expectation that 
they would continue to serve retail load because, among other things, 
state regulators set long amortization periods of 30-40 years for 
depreciation rates.
    Some commenters state that the Commission also should ensure that 
stranded costs are recovered when a municipal utility annexes territory 
served by another utility or otherwise expands its service 
territory.<SUP>713 A number of commenters also urge the Commission to 
ensure recovery of costs that are stranded if a municipal utility or a 
newly-formed wholesale or municipal utility physically interconnects to 
another utility or builds new transmission or distribution facilities 
to the municipal system.<SUP>714
---------------------------------------------------------------------------

    \713\ E.g., EEI, Minnesota Power, Centerior, Public Service Co 
of CO, SoCal Edison, Coalition for Economic Competition. PG&E asks 
that we allow utilities to seek recovery at the Commission for 
stranded costs attributable to former retail customers that have 
become customers of existing public agencies or municipal utilities 
where such costs cannot be collected at the state level.
    \714\ E.g., Centerior, Coalition for Economic Competition, PG&E. 
Coalition for Economic Competition proposes that the Commission 
accept just and reasonable regional stranded cost recovery 
mechanisms in such situations to enable regional transmission 
associations (whether through pool and interpool arrangements or 
regional transmission groups) to collect through Commission-filed 
rate schedules from interconnected utilities charges equal to the 
costs otherwise stranded as a result of Commission-jurisdictional 
service realignments.
---------------------------------------------------------------------------

    Several commenters believe that close coordination between the 
Commission and state regulators as to the calculation of stranded costs 
is important in the case of municipalization.<SUP>715 A number of state 
commissions suggest that the Commission allow the states to set the 
level of retail-turned-wholesale stranded costs to be recovered in 
wholesale transmission rates set by the Commission.<SUP>716 They submit 
that this approach would respect state interests in controlling the 
rate impact of stranded costs, while allowing the Commission to design 
cost recovery, and would address the needs of industrial customers and 
other stakeholders by providing a forum before state regulators who 
will be more aware of their particular needs. Further, they contend 
that this approach would prevent relitigation of issues, minimize 
forum-shopping, and prevent legitimate and verifiable costs from 
falling through the cracks or being double-recovered.<SUP>717 NY 
Industrials asks the Commission to clarify that utilities will not be 
allowed to seek cost recovery at both the Commission and state 
commissions.
---------------------------------------------------------------------------

    \715\ E.g., SoCal Edison, OH Com, NY Com, MI Com, Coalition on 
Federal-State Issues.
    \716\ E.g., MI Com, NY Com, Ohio Com.
    \717\ PG&E proposes a similar approach, noting that if there are 
differences in the stranded cost method used by the Commission and 
the states, an incentive may remain for retail customers to 
municipalize merely to take advantage of more favorable stranded 
cost treatment at the Commission.
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Commission Conclusion
    We reaffirm our preliminary determination that this Commission 
should be the primary forum for addressing the recovery of stranded 
costs caused by retail-turned-wholesale customers. If such a customer 
is able to reach a new generation supplier because of the new open 
access (through the use of a FERC-filed open access transmission tariff 
or through transmission services ordered pursuant to section 211 of the 
FPA), we believe that any costs stranded as a result of this wholesale 
transmission access should be viewed as ``wholesale stranded costs.'' 
Such costs would not be stranded but for the action of this Commission 
(either through a mandatory FPA section 205-206 open access tariff or 
an order under FPA section 211) in permitting the new wholesale entity 
to become an unbundled transmission services customer of the utility 
and thereby to obtain power from a new supplier.<SUP>718 There is a 
clear nexus between the FERC-jurisdictional transmission access 
requirement and the exposure to non-recovery of prudently incurred 
costs. In these circumstances, we believe that this Commission should 
be the primary forum for addressing recovery of such costs. To avoid 
forum-shopping and duplicative litigation of the issue, we expect 
parties to raise claims before this Commission in the first 
instance.<SUP>719
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    \718\ Costs that are exposed to nonrecovery when a retail 
customer or a newly-created wholesale power sales customer ceases to 
purchase power from the utility and does not use the utility's 
transmission system to reach a new generation supplier (e.g., 
through self-generation or use of another utility's transmission 
system) do not meet the definition of ``wholesale stranded costs'' 
for which this rule provides an opportunity for recovery. Such costs 
are outside the scope of this rule because such costs would not be 
stranded as a result of the new open access. See Section IV.J.12.
    \719\ We recognize that we took a different approach to retail-
turned-wholesale stranded cost recovery in United Illuminating, 
where we suggested that state and local regulatory authorities or 
the courts should be able to provide an adequate forum to address 
retail franchise matters, including recovery of stranded costs 
caused by municipalization, but said we would consider revisiting 
the question if United Illuminating could demonstrate the lack of a 
forum. 63 FERC at 62,583-84. Since the issuance of that decision, 
however, we have had an opportunity to re-analyze the nature of the 
stranded cost problem in cases where a retail customer becomes a 
wholesale customer, including the potential that there might not be 
a state regulatory forum for recovery of such costs. In these 
circumstances, we have determined that where such costs are stranded 
as a result of wholesale open access transmission, these costs 
should be viewed as wholesale stranded costs and this Commission 
should be the primary forum for addressing their recovery.
---------------------------------------------------------------------------

    Some commenters have asked us also to be the primary forum for 
stranded cost recovery in situations in which an existing municipal 
utility annexes territory served by another utility or otherwise 
expands its service territory. We decline to do so because in these 
situations there is no direct nexus between the FERC-jurisdictional 
transmission access requirement and the exposure to non-recovery of 
prudently incurred costs. The risk of an existing municipal utility 
expanding its territory was a risk prior to the Energy Policy Act and 
prior to any open access requirement.
    Nevertheless, we are concerned that there may be circumstances in 
which customers and/or utilities could attempt, through indirect use of 
open access transmission, to circumvent the ability of any regulatory 
commission--either this Commission or state commissions--to address 
recovery of stranded costs.<SUP>720 We reserve the right to address 
such situations on a case-by-case basis.
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    \720\ The CA Com has asked that, ``(t)o the extent of FERC's 
authority, it should assume jurisdiction to fulfill a backstop role 
in case retail customers evade a state-determined transition charge 
by becoming retail customers of an entity not subject to the state 
regulatory commission's jurisdiction. In assuming jurisdiction, the 
Commission should defer to the state commission's determination and 
allocation of stranded costs for the departing retail customer.'' CA 
Com March 18, 1996 Response to Supplemental Comments of PG&E.
---------------------------------------------------------------------------

    As we indicated in the Supplemental Stranded Cost NOPR, if the 
state has permitted any recovery from departing retail-turned-wholesale 
customers (for example, if it imposed an exit fee prior to, or as a 
condition of, creating the wholesale entity), that amount will not, in 
fact, be stranded, and we will deduct that amount from the legitimate 
stranded costs for which we will allow recovery.
    As discussed in Sections IV.J.8-IV.J.9, we will require the same 
evidentiary demonstration for recovery of stranded costs from a retail-
turned-wholesale customer, and will apply the same procedures for 
determining stranded cost obligation, as that required in the case of a 
wholesale requirements customer.

[[Page 21647]]

7. Recovery of Stranded Costs Caused by Retail Wheeling
    In the Supplemental Stranded Cost NOPR, we stated that both this 
Commission and state commissions have the legal authority to address 
stranded costs that result from retail customers who obtain retail 
wheeling from public utilities in order to reach a different 
generation supplier.<SUP>721 Because the vast majority of commenters 
urged the Commission not to assume responsibility for retail 
stranded costs, except in certain circumstances, we preliminarily 
concluded that it is appropriate to leave it to state regulatory 
authorities to deal with any stranded costs occasioned by retail 
wheeling. We proposed to entertain requests to recover stranded 
costs caused by retail wheeling only when the state regulatory 
authority does not have authority under state law to address 
stranded costs at the time when the retail wheeling is 
required.<SUP>722 In so doing, we preliminarily accepted the view 
that stranded costs caused by retail wheeling are primarily a matter 
of local or state concern and thus, with the limited exception 
discussed above, generally must be recovered through retail charges.
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    \721\ As discussed in Section IV.I, the Commission's authority 
to address retail stranded costs derives from its jurisdiction over 
the rates, terms and conditions of unbundled transmission in 
interstate commerce used by retail customers that obtain retail 
wheeling. The states' authority derives from state jurisdiction over 
local distribution facilities and over the service of delivering 
electric energy to end users, and from the authority to impose, 
among other things, retail exit fees and surcharges on local 
distribution rates.
    \722\ We proposed to require the same evidentiary demonstration 
for recovery of stranded costs from a retail customer that obtains 
retail wheeling as that required in the case of a wholesale 
requirements customer. We also reaffirmed our proposal in the 
initial Stranded Cost NOPR that a utility will have to show that the 
stranded costs are not more than the net revenues that the retail 
customer would have contributed to the utility had it remained a 
retail customer of the utility, and that the utility has taken and 
will take reasonable steps to mitigate stranded costs. FERC Stats. & 
Regs. para. 32,514 at 33,128.
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    We noted that the states have a number of mechanisms for addressing 
stranded costs caused by retail wheeling, one of which is a surcharge 
to state-jurisdictional rates for local distribution.\723\ We 
encouraged the states to use the mechanisms available to them to 
address stranded costs.<SUP>724 We also noted that the states may use 
their jurisdiction over local distribution facilities to address 
``stranded benefits,'' such as environmental benefits associated with 
conservation, load management, and other demand side management 
programs.<SUP>725
---------------------------------------------------------------------------

    \723\ As we noted in the Supplemental NOPR, a state may require 
payment of an exit fee before a franchise customer is permitted to 
obtain unbundled retail wheeling. If local distribution facilities 
are used by a retail wheeling customer, the state may allow recovery 
of stranded costs through rates for use of such local distribution 
facilities. In addition, as discussed in Section IV.I, because we 
believe that states have authority over the service of delivering 
electric energy to end users, not merely the local distribution 
facilities themselves, state authorities can assign stranded costs 
and benefits through a local distribution service charge, and may do 
so based on usage (kWh), demand (kW), or any combination or method 
they find appropriate. If a state decides not to take any of these 
routes, it may consider whether to allow recovery of stranded costs 
from remaining retail customers or whether shareholders should bear 
all or part of those costs. Id. at 33,129.
    \724\ Id. at 33,129-30.
    \725\ Id. at 33,098 n. 230.
---------------------------------------------------------------------------

Comments
    A number of commenters support the Commission's proposal for 
addressing stranded costs caused by retail wheeling.<SUP>726
---------------------------------------------------------------------------

    \726\ E.g., Utilicorp, Houston L&P, PG&E, Freedom Energy Co, WI 
Com.
---------------------------------------------------------------------------

    Other commenters urge the Commission to take a greater role in 
retail stranded cost recovery and to entertain requests to recover 
stranded costs as a backstop where: (1) State regulatory authorities 
have the authority to address stranded costs but either choose not to 
exercise that authority or fail to permit full stranded cost recovery; 
<SUP>727 or (2) the state commission's authority is unclear.<SUP>728
---------------------------------------------------------------------------

    \727\ E.g., EEI, EGA, Coalition for Economic Competition, 
Utilities for Improved Transition, Atlantic City, Arizona, 
Centerior, Com Ed, Detroit Edison, El Paso, LILCO, NU, NSP, NYSEG, 
United Illuminating, BG&E, Sierra, Southern, UT Industrials, NRECA. 
NRECA argues that unless the Commission addresses stranded costs 
caused by retail wheeling where a state commission lacks authority, 
or has authority but decides not to exercise it, there could be a 
jurisdictional gap into which many rural electric cooperatives could 
fall.
    \728\ E.g., CSW.
---------------------------------------------------------------------------

    Commenters that support a greater Commission backstop role argue, 
among other things, that because the Commission has exclusive 
ratemaking jurisdiction over any stranded cost charges imposed ``for or 
in connection with'' interstate transmission service by public 
utilities, the Commission has an obligation to regulate the recovery of 
stranded costs from interstate retail transmission customers.<SUP>729 A 
number of these commenters argue that the determining factor is who has 
the jurisdiction to review the rates for the service, not who has the 
jurisdiction to order the service.<SUP>730 They explain that the 
Commission has jurisdiction over generating facilities and associated 
costs to the extent appropriate to establish just and reasonable rates 
for jurisdictional services. They disagree with other commenters who 
argue that only the jurisdiction under whose authority the costs were 
incurred and initially recovered should have authority to order 
recovery of stranded costs.<SUP>731
---------------------------------------------------------------------------

    \729\ E.g., EEI, Illinois Power, PSNM, Entergy, Nuclear Energy 
Institute, Coalition for Economic Competition.
    \730\ E.g., Coalition for Economic Competition, Illinois Power, 
Utilities for Improved Transition, EEI.
    \731\ EEI notes, for example, that as use of electrical 
facilities shifts between retail and wholesale, jurisdiction over 
the rates to recover the allocated cost of service shifts between 
state commissions and this Commission, and that the regulatory 
authority is determined by the nature of the transactions and the 
classification of the customer, not the jurisdiction under which the 
costs originally arose.
---------------------------------------------------------------------------

    These commenters contend that the Commission cannot abdicate its 
regulatory responsibilities by either deferring to the state 
commissions or otherwise failing to independently address the 
issue.<SUP>732 EEI and the Coalition for Economic Competition refer to 
``a long line of cases (where) the courts have held that where a 
federal regulatory agency * * * is charged with implementing a 
statutory framework, that agency is without authority to deviate from 
or abdicate its statutory responsibilities.'' <SUP>733 According to 
Coalition for Economic Competition, for example, the Commission could 
satisfy its obligation to address stranded costs that arise from retail 
wheeling by allowing states to determine retail stranded cost charges 
in the first instance; to the extent that the state allows full 
recovery, Coalition for Economic Competition submits that the 
Commission's obligation would be satisfied.
---------------------------------------------------------------------------

    \732\ E.g., Illinois Power, Utilities For Improved Transition, 
EEI, Coalition for Economic Competition.
    \733\ EEI Initial Comments at IV-13; see also Coalition for 
Economic Competition Initial Comments at 23-31.
---------------------------------------------------------------------------

    EEI asserts that it would be unduly discriminatory and preferential 
for the Commission to refuse to address all stranded costs arising from 
retail wheeling. According to EEI, the same arguments that support the 
Commission's decision to address costs that are stranded where retail 
load municipalizes and where the state regulatory authority, at the 
time retail wheeling is required, lacks authority to act, apply with 
equal force to all other retail stranded costs. EEI submits that the 
nexus in these cases is that Commission-jurisdictional transmission 
service is the means by which the costs are stranded.\734\
---------------------------------------------------------------------------

    \734\ See also SoCal Edison.
---------------------------------------------------------------------------

    Utility Working Group argues that the NOPR inappropriately 
characterizes the Commission's jurisdiction over retail stranded costs 
and that this could later be used against the Commission's exercise of 
its full authority. According to Utility Working Group, the NOPR 
depicts the Commission's jurisdiction as

[[Page 21648]]

being derived from state law (in other words, the Commission will act 
where state regulatory authorities have no authority over retail 
stranded costs and will not act where state regulatory authorities have 
such authority). If the Commission desires to afford substantial 
deference to the states regarding retail stranded costs, Utility 
Working Group contends that the final rule should reflect that policy 
determination; however, the rule should not confuse policy with 
jurisdiction by purporting to place limits on, or attempting to waive, 
the Commission's jurisdiction over such costs.
    Entergy asserts that the Commission's jurisdiction over multi-state 
utilities provides further support for our jurisdiction over retail 
stranded costs in certain contexts. Entergy states that most of the 
eleven multi-state registered holding company systems have some form of 
Commission-jurisdictional agreement that allocates production and 
transmission costs among the systems' affiliated operating companies. 
It asserts that these agreements by their very nature allocate costs 
among jurisdictions (that is, between states). Many of these agreements 
equalize the cost of generating reserves among affiliated operating 
companies, and such reserve equalization formulas can shift retail 
stranded costs among states unless the Commission provides a regulatory 
forum to address cost-shifting. Citing Middle South Energy,<SUP>735 and 
City of New Orleans v. FERC,<SUP>736 Entergy submits that the 
Commission cannot sit on the sidelines when it comes to stranded retail 
costs on the Entergy system. According to Entergy, Commission and 
judicial precedent place on the Commission the responsibility to ensure 
that federally-approved costs and cost allocations are not undermined 
by state action.
---------------------------------------------------------------------------

    \735\ Opinion 234, 31 FERC para. 61,305, on reh'g, 32 FERC para. 
61,425 (1985).
    \736\ 875 F.2d 903 (D.C. Cir. 1989), cert. denied sub nom. 
Mississippi v. FERC, 494 U.S. 1078 (1990).
---------------------------------------------------------------------------

    Commenters also express concern that it will not be possible to be 
sure that a state regulatory authority has authority over retail 
stranded costs until after years of litigation. If the Commission waits 
for the resolution of challenges to state authority and a court holds 
that the state regulatory authority is without authority, these 
commenters assert that the bar on retroactive ratemaking could leave 
the states and the Commission without a remedy to compensate utilities 
for stranded costs.\737\ A number of commenters suggest that while the 
states should be allowed to set retail wheeling stranded cost charges 
in the first instance, the Commission should accept filings to preserve 
a utility's ability to recover retail stranded costs from the time the 
customer departs if the state-authorized charges are not upheld in 
court. They submit that this would put customers on notice of the 
potential for Commission action and thereby avoid the retroactivity 
problem.<SUP>738
---------------------------------------------------------------------------

    \737\ E.g., NU, Coalition for Economic Competition, Illinois 
Power, EEI.
    \738\ E.g., NEPCO, EEI, Coalition for Economic Competition, 
Entergy.
---------------------------------------------------------------------------

    Some commenters express concern that if the Commission does not 
take more decisive action on retail wheeling stranded costs, the result 
will be wasteful litigation that will discourage competition by causing 
financial uncertainty and higher financing costs for investor-owned 
utilities and higher rates for consumers.<SUP>739 Coalition for 
Economic Competition also asserts that stranded cost charges would be 
greatest at the start of a retail wheeling program, thereby making the 
years during which the state-authorized charges are subject to appeal 
more important for recovery purposes.
---------------------------------------------------------------------------

    \739\ E.g., LILCO, Coalition for Economic Competition.
---------------------------------------------------------------------------

    A number of commenters support Commission-established uniform 
standards for, and uniform recovery of, costs stranded as a result of 
open access to the interstate transmission system.<SUP>740 They argue 
that disparate state treatment of stranded costs would be economically 
inefficient and discriminatory and would burden interstate 
commerce.<SUP>741 Several commenters support state involvement in the 
establishment of uniform standards.<SUP>742
---------------------------------------------------------------------------

    \740\ E.g., NU, NSP, Illinois Power, Coalition for Economic 
competition, PSE&G, Utilities For Improved Transition, Philip 
Morris, EEI.
    \741\ Freedom Energy Co. rejects this argument on the basis that 
state regulation has never been wholly consistent and yet utilities 
have not asked for federal unification of state ratemaking policies 
or resolution of differences.
    \742\ E.g., PSNM, GA Com, Omaha PPD, Illinois Power.
---------------------------------------------------------------------------

    In contrast to the commenters that support a greater Commission 
role in retail stranded cost recovery, NARUC and a number of other 
commenters oppose any Commission involvement in retail stranded 
costs.<SUP>743 These commenters contend, among other things, that the 
Commission lacks authority over these costs. Even if the Commission 
could assert such jurisdiction, they argue that as a policy matter it 
would be inappropriate for the Commission to delve into complicated 
legal and policy issues governed by varying state regulatory regimes.
---------------------------------------------------------------------------

    \743\ E.g., CA Com, MD Com, VA Com, IN Com, NH Com, NV Com, NY 
Com, OH Com, FL Com, AZ Com, TX Com, ELCON, NY Industrials, NY AG, 
NY Consumer Protection, MA DPU, Iowa Board, IN Industrials, Texas 
Industrials, NM Industrials, Reynolds, NYMEX, Legal Environmental 
Assistance, CO Consumers Counsel, NJ Ratepayer Advocate, IBM, ME 
Industrials, Jay, WEPCO, NH General Court.
---------------------------------------------------------------------------

    According to some of these commenters,<SUP>744 section 201(a) of 
the FPA precludes an exercise of federal jurisdiction over retail 
stranded cost recovery because the Commission's jurisdiction extends 
``only to those matters which are not subject to regulation by the 
States.'' <SUP>745 NM Industrials argues that a lack of state 
commission authority is an affirmative state determination, either by 
act or omission, that stranded costs must be dealt with in a particular 
manner. It submits that the Commission also lacks authority over retail 
stranded costs when states either decide not to address such costs or, 
in the Commission's opinion, grant insufficient recovery of stranded 
costs. NM Industrials asserts that the language of the FPA and its 
legislative history indicate that Congress wanted to preclude 
Commission jurisdiction in those areas where states could exercise 
effective control, and that this limitation covers all matters which 
are or can be regulated by the states, including the recovery of 
stranded investment. NM Industrials also suggests that assertion of 
Commission jurisdiction would violate the provision of section 212 of 
the FPA that prohibits the Commission from interfering with the states' 
authority over the transmission of energy directly to an ultimate 
consumer.<SUP>746
---------------------------------------------------------------------------

    \744\ E.g., NARUC, ELCON, NY Industrials, NM Industrials, NV 
Com.
    \745\ 16 U.S.C. 824(a).
    \746\ See also Freedom Energy Co. Reply Comments.
---------------------------------------------------------------------------

    Other commenters argue that the Commission's proposed treatment of 
retail stranded costs infringes on the states' jurisdiction over the 
allocation of costs that were under their jurisdiction when the costs 
were incurred. According to these commenters, the question of whether 
these costs should be recovered from other retail ratepayers, 
eliminated as excess capacity, or billed in some fashion to the 
customer now receiving wheeling service are purely questions of state 
ratemaking law.<SUP>747 Some commenters assert that, as a matter of 
policy, the Commission should stay out of retail stranded costs because 
only the states have sufficient knowledge and expertise regarding 
utility planning, investment,

[[Page 21649]]

and forecasting to address these costs adequately.<SUP>748
---------------------------------------------------------------------------

    \747\ E.g., ELCON, PA Com, NY Industrials, ND Com, VA Com, NM 
Com.
    \748\ E.g., OH Com, NY Industrials, NM Com, IN Com, WA Com, NV 
Com, NY Com, Suffolk County, NY AG, Tonko, PA Industrials, NH 
General Court.
---------------------------------------------------------------------------

    Commenters also express concern that the possibility of Commission 
involvement in retail stranded cost recovery will encourage forum-
shopping whenever state commission action is unfavorable, even when 
states have procedures to deal with stranded costs. They argue that the 
result would be endless litigation over where federal jurisdiction ends 
and where state jurisdiction begins. They suggest that if a state fails 
to address retail stranded cost recovery, the issue should be addressed 
in court or in state legislatures.<SUP>749 OH Com contends that a 
Commission policy that does not recognize states' authority over retail 
stranded costs would be a disincentive for states to permit retail 
wheeling.
---------------------------------------------------------------------------

    \749\ E.g., OH Com, PA Com, NM Com, CA Com, Blue Ridge.
---------------------------------------------------------------------------

    A number of commenters argue that recovery of retail stranded costs 
is not directly implicated by any Commission or Congressional action--
that most such costs would be created by retail wheeling, which is not 
the subject of the Commission's open access initiatives--and thus need 
not be dealt with as part of the final rule.<SUP>750
---------------------------------------------------------------------------

    \750\ E.g., Nucor, AEC & SMEPA.
---------------------------------------------------------------------------

    Commenters seek a number of clarifications concerning the 
Commission's position on, and the procedures for, retail stranded cost 
recovery. A number of commenters ask the Commission to clarify the 
states' role with respect to retail stranded cost recovery.<SUP>751 
Others address the type of evidence required to establish that the 
state regulatory authority lacks authority to address stranded costs 
when retail wheeling is required.<SUP>752
---------------------------------------------------------------------------

    \751\ E.g., NY Industrials, EGA, NJ BPU, Coalition on Federal-
State Issues.
    \752\ E.g., Iowa Board, Nevada Commission, CCEM; see also NE 
Public Power District.
---------------------------------------------------------------------------

    Several commenters express concern that customers receiving retail 
wheeling not be able to evade state stranded cost charges.<SUP>753 IL 
Com says that the Commission's proposal for determining whether 
facilities are state-jurisdictional ``local distribution'' facilities 
or Commission-jurisdictional ``transmission'' facilities in interstate 
commerce may not always provide a state with the opportunity to recover 
retail stranded costs through distribution rate surcharges. It says 
that the Commission does not offer any assurances that the case-by-case 
application of the proposed ``functional-technical test'' will result 
in a finding that ``local distribution'' facilities are used in all 
retail wheeling scenarios. PG&E asks the Commission to provide that all 
retail customers that opt for direct transmission access by definition 
take service over local distribution facilities and therefore may be 
subjected to a state-determined distribution rate that includes 
stranded cost surcharges.
---------------------------------------------------------------------------

    \753\ E.g., IL Com, PG&E, Public Service Co of CO.
---------------------------------------------------------------------------

    A number of commenters ask the Commission to clarify that, in 
issuing the final rule, the Commission is not endorsing (either 
implicitly or explicitly) retail wheeling.<SUP>754
---------------------------------------------------------------------------

    \754\ E.g., NRECA, Wisconsin EC, EEI, PECO, Missouri Basin 
Group.
---------------------------------------------------------------------------

    Several commenters express concern that stranded costs may arise in 
one state jurisdiction and be shifted to another.<SUP>755 For example, 
MT Com says that an analysis confined to a state's boundaries may 
reveal no stranded costs, but that such costs may indirectly arise 
because of common pool revenue recovery mechanisms, which may be the 
largest source of stranded costs for some utilities. Entergy raises a 
similar concern in the context of holding company or other multi-state 
situations. It argues that denial of retail stranded cost recovery by a 
state regulatory authority could harm customers in other states. 
Entergy proposes that, while state regulators should be given the 
opportunity in the first instance to assure that stranded costs are 
recovered and are not shifted to other states, the Commission should 
allow utilities to file retail wheeling tariffs with the Commission to 
preserve the right to seek recovery from the Commission.
---------------------------------------------------------------------------

    \755\ E.g., MT Com, Entergy.
---------------------------------------------------------------------------

    Several commenters oppose Entergy's proposal.<SUP>756 Among other 
things, they argue that the FPA does not authorize the Commission to 
act as an appellate court over retail regulators. They assert that, in 
the case of a multi-state holding company system, it is the Commission-
jurisdictional intra-system agreement (not a state's decision as to 
recovery of retail stranded costs) that determines the allocation of 
costs at wholesale among the affiliates. Several of these commenters 
suggest that if the holding company believes that, as a result of a 
state's disallowance of costs in retail rate base, the cost allocations 
under an intra-system agreement are unduly discriminatory, the holding 
company could propose to amend the agreement.<SUP>757
---------------------------------------------------------------------------

    \756\ E.g., NARUC, Entergy Retail Regulators, MS Com, Al Com.
    \757\ E.g., NARUC, MS Com.
---------------------------------------------------------------------------

    A number of commenters also express concern that services that 
investor-owned utilities provide to promote energy efficiency and 
conservation and to assist low-income residents and the elderly be 
continued.<SUP>758 NW Conservation Act Coalition suggests that the 
Commission should condition stranded cost recovery upon a showing by 
the utility that allowing recovery will not strand such social 
benefits.<SUP>759
---------------------------------------------------------------------------

    \758\ E.g., Homelessness Alliance, Black Mayors, National 
Women's Caucus, Vann, La Raza.
    \759\ NARUC and OH Com assert that, in determining whether a 
wholesale transmission transaction is a ``sham,'' the Commission 
should consider a retail customer's intent to bypass responsibility 
for supporting social programs.
---------------------------------------------------------------------------

    Various commenters endorse the use by state regulators of a 
distribution charge or other fee imposed on electricity consumption to 
address stranded social benefits.<SUP>760 NARUC and OH Com express 
concern that the Commission, by claiming authority over unbundled 
retail transmission services, may make it difficult for states to use 
non-bypassable ``wires charges'' or ``access fees'' to require all 
customer classes to support such programs.<SUP>761 NARUC asks the 
Commission to ensure that any jurisdiction we exercise over unbundled 
transmission services does not legally or practically foreclose the 
ability of individual states to fund such programs.<SUP>762 LILCO, as 
part of its argument that the Commission should provide a complete 
backstop for stranded cost recovery resulting from retail wheeling, 
urges the Commission to establish retail wheeling rates that provide 
for full recovery of any stranded costs, including stranded social 
benefits,

[[Page 21650]]

that are unrecovered after state stranded cost determinations.
---------------------------------------------------------------------------

    \760\ E.g., Natural Resources Defense, NW Conservation Act 
Coalition, Seattle, FTC, Northeast States for Coordinated Air Use 
Management, NARUC, OH Com. CO Com agrees that states should have the 
option to fund such programs through the imposition of surcharges on 
any form of electric service used to benefit retail customers, 
including surcharges on retail transmission rates. Seattle proposes 
either a simple fee on kWhs or a differential fee based on the type 
of resource and its environmental affects. DOE urges the Commission 
to work with state regulators to ensure that states have the ability 
to recover stranded retail costs and benefits in a way that prevents 
cost-shifting, forum-shopping, and uneconomic bypass (including 
bypass of stranded benefits).
    \761\ CO Com notes that the NOPR proposes to limit states to 
funding mechanisms that can be implemented solely at the local 
distribution level, presumably through the use of a surcharge on 
distribution facilities or so-called ``fee at the meter'' or the use 
of a local distribution system revenue decoupling mechanism. It 
suggests that neither of these options may be legally or practically 
feasible in many states for a wide variety of reasons (but does not 
expand on these reasons).
    \762\ Natural Resources Defense proposes that the Commission 
adopt the following language: ``The FPA does not affect state 
regulators' jurisdiction to apply distribution charges--either 
volume-based or fixed--to electricity that is used by any utility 
customer to provide end-use services (as distinguished from 
electricity that is purchased for resale to end-use customers).'' 
Natural Resources Defense Initial Comments at 3.
---------------------------------------------------------------------------

Commission Conclusion
    We believe that both this Commission and the states have the legal 
authority to address stranded costs that result when retail customers 
obtain retail wheeling in order to reach a different generation 
supplier, and that utilities are entitled, from both a legal and a 
policy perspective, to an opportunity to recover all of their prudently 
incurred costs. This Commission's authority to address retail stranded 
costs is based on our jurisdiction over the rates, terms, and 
conditions of unbundled retail transmission in interstate commerce. The 
authority of state commissions to address retail stranded costs is 
based on their jurisdiction over local distribution facilities and the 
service of delivering electric energy to end users. However, because it 
is a state decision to permit or require the retail wheeling that 
causes retail stranded costs to occur, we will leave it to state 
regulatory authorities to deal with any stranded costs occasioned by 
retail wheeling. The only circumstance in which we will entertain 
requests to recover stranded costs caused by retail wheeling is when 
the state regulatory authority <SUP>763 does not have authority under 
state law to address stranded costs when the retail wheeling is 
required.
---------------------------------------------------------------------------

    \763\ ``State regulatory authority'' has the same meaning as 
provided in section 3(21) of the FPA.
---------------------------------------------------------------------------

    Commenters that describe our action as an unlawful abdication or 
delegation of authority misconstrue the nature of our decision to leave 
retail stranded costs (with a limited exception) to state regulatory 
authorities.<SUP>764 We have not ``abdicated'' or ``delegated'' to 
state regulatory authorities our jurisdiction over the rates, terms, 
and conditions of retail transmission in interstate commerce; if retail 
transmission in interstate commerce by a public utility occurs, public 
utilities offering such transmission must comply with the FPA by filing 
proposed rate schedules under section 205. Instead, we have made a 
policy determination that the recovery of retail stranded costs--an 
issue over which either this Commission or state commissions could 
exercise authority by virtue of their jurisdiction over retail 
transmission in interstate commerce and over local distribution 
facilities and services, respectively--is primarily a matter of local 
or state concern that should be left with the state commissions. 
However, if the state regulatory authority does not have authority 
under state law to address stranded costs when the retail wheeling is 
required, then we will entertain requests to recover such 
costs.<SUP>765
---------------------------------------------------------------------------

    \764\ We reject the arguments of EEI and Coalition for Economic 
Competition that the Commission made findings in the initial 
stranded cost NOPR that ``inexorably'' lead to the conclusion that 
Commission action providing full recovery of retail stranded costs 
is required. Their reliance on Williams Natural Gas Company v. FERC, 
872 F.2d 438 (D.C. Cir. 1989), appeal after remand, 943 F.2d 1320 
(D.C. Cir. 1991) (Williams), is simply misplaced. Williams involved 
a rulemaking that was terminated by the Commission. The court stated 
that the Commission, ``having expressed these tentative views (that 
the incentive price for tight formation gas would disserve the 
public interest) and having solicited comments on the issue, was not 
free to terminate the rulemaking'' without providing a satisfactory 
explanation. 872 F.2d at 446, 450. Here, in contrast, we are issuing 
a Final Rule that reaffirms in many respects preliminary findings 
proposed in both the initial and Supplemental Stranded Cost NOPRs. 
Although the conclusion we reach based on those findings may be 
different than that which some commenters advocate, we have fully 
explained the basis for our decision.
    \765\ In these circumstances, the cases cited by commenters to 
support the proposition that an agency is not authorized to abdicate 
its statutory responsibilities or to delegate to parties and 
intervenors regulatory responsibilities (such as preparation of an 
environmental impact statement) are factually distinguishable and 
inapposite. See, e.g., FPC v. Texaco, 417 U.S. 380, 394 (1974) 
(Commission cannot exempt small-producer rates from compliance with 
just and reasonable standard); United States v. City of Detroit, 720 
F.2d 443, 451 (6th Cir. 1983) (district court inappropriately 
implied waiver of EPA statutory duty under Title II of the Federal 
Water Pollution Prevention and Control Act); State of Idaho v. ICC, 
35 F.3d 585, 595-96 (D.C. Cir. 1994) (an agency cannot abdicate its 
NEPA responsibilities in favor of the regulated party).
---------------------------------------------------------------------------

    Because we have accepted the view that stranded costs caused by 
retail wheeling are primarily a matter of local or state concern, we 
will not allow the states to use the interstate transmission grid as a 
vehicle for passing through any retail stranded costs, with the 
following limited exception. If the state regulatory authority does not 
have authority under state law when the retail wheeling is required to 
resolve the retail stranded cost issue, we will permit a utility to 
seek a customer-specific surcharge to be added to an unbundled 
transmission rate.
    We believe that most states have a number of mechanisms for 
addressing stranded costs caused by retail wheeling.<SUP>766 In 
addition, as further discussed in Section IV.I, we are defining in this 
rule ``facilities used in local distribution'' under section 201(b)(1) 
of the FPA. Rates for services using such facilities to make a retail 
sale are state-jurisdictional, and states will be free to impose 
stranded costs caused by retail wheeling on facilities or services used 
in local distribution. States may also use their jurisdiction over 
local distribution facilities or services to recover so-called stranded 
benefits. This rule is not intended to preempt any existing state 
authority to assess a stranded cost or stranded benefits charge on a 
retail customer that obtains retail wheeling. Moreover, since the 
charge is state jurisdictional, it is of no moment to our 
responsibilities under the FPA as to whether such charges are volume-
based (kWh), demand-based (kW), or customer-based (fixed).
---------------------------------------------------------------------------

    \766\ As discussed in the Supplemental NOPR (FERC Stats. & Regs. 
para. 32,514 at 33,129-30), these mechanisms include requiring an 
exit fee before a franchise customer is permitted to obtain 
unbundled retail wheeling and imposing a surcharge on local 
distribution rates. Commenters identified several other possible 
mechanisms in response to the initial Stranded Cost NOPR.
---------------------------------------------------------------------------

    We believe that our approach to retail wheeling stranded costs 
represents an appropriate balance between federal and state interests. 
This approach ensures that the rates for transmission in interstate 
commerce by public utilities (except in a narrow circumstance) will not 
be burdened by retail costs. It also helps to ensure that one state 
will not be able to impose costs stranded by its ordering of retail 
wheeling <SUP>767 on customers in another state.<SUP>768 In a holding 
company or other multi-state situation, we recognize that denial of 
retail stranded cost recovery by a state regulatory authority could, 
through operation of the reserve equalization formula in a Commission-
jurisdictional intra-system agreement, inappropriately shift the 
disallowed costs to affiliated operating companies in other states. The 
Commission is concerned about this potential for cost-shifting. We 
would not wish to see an intra-system agreement used as a means for one 
jurisdiction to shift to other jurisdictions retail stranded costs for 
which it would otherwise be responsible under that agreement. However, 
we will deal with such situations if they arise pursuant to public 
utility filings under section 205 or complaints under section 206. 
Thus, the need to amend a jurisdictional agreement to prevent retail 
stranded costs from being shifted to customers in other states will be 
addressed on a case-by-case basis. We encourage the affected state 
commissions in such situations to seek a mutually agreeable approach to 
this potential problem. If such a consensus solution resulted in a 
filing to modify a jurisdictional agreement, we would accord such a 
proposal deference, particularly if other interested parties support 
the filing. In the event that the state commissions and

[[Page 21651]]

other interested parties cannot reach consensus that would prevent cost 
shifting, the Commission would ultimately have to resolve the 
appropriate treatment of such stranded costs.
---------------------------------------------------------------------------

    \767\ As we stated in the Supplemental NOPR, we do not address 
whether states have the lawful authority to order retail wheeling in 
interstate commerce. Id. at 33,098 at n.228. In addition, we are 
neither endorsing nor discouraging retail wheeling.
    \768\ See id. at 33,098, 33,127-28.
---------------------------------------------------------------------------

    Should a situation arise in which a state regulatory authority 
concludes that it has no ability to address retail stranded costs, or 
the appropriate state courts ultimately determine that a state 
regulatory authority does not have authority to impose retail stranded 
costs, a utility may seek recovery here through its Commission-
jurisdictional retail transmission rates of costs stranded as of the 
date of the customer's departure. Because all parties are put on notice 
by this Rule of the potential for recovery through Commission-
jurisdictional retail transmission rates should state commission-
authorized retail wheeling charges be invalidated, such recovery (if 
allowed) would not be retroactive ratemaking.<SUP>769
---------------------------------------------------------------------------

    \769\ See Public Utilities Commission of the State of California 
v. FERC, 988 F.2d 154, 163-66 (D.C. Cir. 1993).
---------------------------------------------------------------------------

8. Evidentiary Demonstration Necessary--Reasonable Expectation Standard
    In the Supplemental Stranded Cost NOPR, the Commission made a 
preliminary determination that a public utility or transmitting utility 
seeking to recover stranded costs must demonstrate that it had a 
reasonable expectation of continuing to serve a customer. We indicated 
that the existence of a notice of termination provision in a wholesale 
requirements contract creates a rebuttable presumption that the utility 
had no reasonable expectation of serving the customer beyond the period 
provided for in the notice provision.<SUP>770 We proposed not to adopt 
a minimum notice period for purposes of applying the rebuttable 
presumption. This was because whether a utility has a reasonable 
expectation of continuing to serve a customer, and for how long, 
including whether there is sufficient evidence to rebut the presumption 
that no such expectation existed beyond the notice provision in the 
contract, will depend on the facts of each case.
---------------------------------------------------------------------------

    \770\ FERC Stats. & Regs. para. 32,514 at 33,117.
---------------------------------------------------------------------------

    We sought further comment concerning whether the reasonable 
expectation standard should apply if a utility has been making 
wholesale requirements sales to a customer in a non-contiguous service 
territory and where, in order to make such a sale possible, 
transmission service has been rendered by an intervening utility. We 
asked whether the Commission should take this as conclusive evidence 
that the customer had a choice of wholesale suppliers and, therefore, 
that the seller had no reasonable expectation that the contract would 
be extended. We further asked should we choose to provide the seller 
with an opportunity to prove that it had a reasonable expectation, what 
weight should be given to the fact that transmission service was 
rendered by the intervening utility. If the seller establishes that it 
had a reasonable expectation, and the former wholesale customer does 
not take unbundled transmission service from the former seller, we 
asked what if any means ought to be available for the collection of 
stranded costs.<SUP>771
---------------------------------------------------------------------------

    \771\ Id. at 33,118.
---------------------------------------------------------------------------

    We also proposed to require the same evidentiary demonstration for 
recovery of stranded costs from a retail-turned-wholesale customer or a 
retail customer that obtains retail wheeling as that required when a 
wholesale requirements customer leaves a utility's system. We proposed 
that the utility must demonstrate that it incurred stranded costs based 
on a reasonable expectation that the customer would continue to receive 
bundled retail services. We anticipated that the reasonable expectation 
test would be easily met in those instances in which state law awards 
exclusive service territories and imposes a mandatory obligation to 
serve. We requested comments on these proposals.<SUP>772
---------------------------------------------------------------------------

    \772\ Id. at 33,128.
---------------------------------------------------------------------------

Comments
a. Rebuttable Presumption
    Some commenters oppose treating a notice provision as a rebuttable 
presumption that the utility had no reasonable expectation of 
continuing to serve a customer. Commenters representing the financial 
community (Utility Shareholders and Utility Investors Analysts), for 
example, state that investment in generation and other costs incurred 
in providing utility service have not been tied to notice provisions. 
Based on the use of notice provisions in the past, and their infrequent 
use for termination, they state that the financial community has not 
viewed notice provisions as a determinant of the financial basis of 
investment in the industry.
    Other commenters also argue that the Commission interprets the 
intent behind termination notice provisions too narrowly. These 
commenters submit that the Commission should examine on a case-by-case 
basis whether a notice provision demonstrates a sufficient meeting of 
the minds between the parties that there was no reasonable expectation 
that the contract would be extended.<SUP>773 TVA notes that the 
existence of a notice provision in its contracts in no way implies that 
continued service would not be expected.
---------------------------------------------------------------------------

    \773\ E.g., Carolina P&L, CSW, Duke, Utilities for Improved 
Transition, Montaup, TVA, MidAmerican. MidAmerican states that, for 
years, utilities have entered into wholesale contracts containing 
termination notice provisions and, for years, customers have renewed 
and renegotiated those contracts. Duke agrees that more important 
indications of the utility's reasonable expectation of continuing to 
serve the customer can be found where the service has been included 
in the IRP process or the contract has been repeatedly renewed. 
Orange & Rockland proposes that there be a rebuttable presumption of 
recovery for long-standing (at least 10 years) contracts between 
utility affiliates on the basis that the existence of a long-
standing relationship is of greater significance than a notice 
provision.
---------------------------------------------------------------------------

    A number of commenters <SUP>774 note that some utilities have 
``evergreen'' contracts that remain in effect indefinitely unless 
either party gives notice that it intends to terminate the contract. 
They argue that, with no date certain for termination, the provider of 
bundled service must proceed on the assumption that it will have to 
meet its contract obligations on a continued basis. CSW recommends that 
the Commission limit the rebuttable presumption standard to contracts 
that contain a fixed contract termination date. IN Com suggests that 
where a contract contains an evergreen provision, the Commission should 
consider how often the contract has been automatically renewed and the 
length of the notice period.
---------------------------------------------------------------------------

    \774\ E.g., CSW, IN Com.
---------------------------------------------------------------------------

    A number of commenters suggest that the following factors should be 
conclusive proof of a reasonable expectation (or sufficient to 
conclusively rebut the presumption of no reasonable expectation): (1) 
An obligation under statute, certificate of public convenience and 
necessity, order or otherwise, granted to the utility to provide 
service to the area that includes the customer; (2) participation by 
the customer in regulatory proceedings that defer the utility's 
complete recovery of the costs associated with existing investment to a 
later period; or (3) service under a wholesale rate that averaged the 
cost of all of a utility's generation resources, both long-term and 
short-term.<SUP>775 Utilities For Improved Transition maintains that a 
customer whose rates were based on the totality of a utility's 
resources, including those with long life expectancies,

[[Page 21652]]

cannot claim that the governing expectation was that the utility would 
serve the customer only for a period of one to three years.
---------------------------------------------------------------------------

    \775\ E.g., El Paso, Utilities For Improved Transition.
---------------------------------------------------------------------------

    Other commenters, in contrast, assert that the rebuttable 
presumption does not go far enough. These commenters submit that a 
notice of termination provision should create a conclusive presumption 
that a utility had no reasonable expectation of continuing to serve a 
customer beyond the notice period.\776\ Some commenters \777\ also 
support a conclusive presumption of no reasonable expectation where one 
or more of the following grounds are present: (1) An explicit 
termination provision, regardless of the length of the pre-termination 
notice period; (2) an explicit provision for decreasing service or 
switching to partial requirements service; (3) a pre-existing 
transmission tariff or transmission service schedule; (4) NRC license 
conditions providing for transmission service or pooling rights; 
<SUP>778 (5) a municipal joint action agency or G&T cooperative with 
authority to supply the wholesale load in question; (6) a fixed-term 
contract; (7) membership in a power pool that provides access to 
regional markets; (8) a contract entered into after passage of the 
Energy Policy Act; or (9) other evidence of an ability to seek 
alternative suppliers. Several of these commenters, such as TAPS and 
Detroit Edison Customers, submit that a conclusive, irrebuttable 
presumption would decrease the number of disputes over stranded cost 
issues.
---------------------------------------------------------------------------

    \776\ See, e.g., ELCON, NRECA, APPA, American Forest & Paper, 
Central Montana EC, Municipal Energy Agency Nebraska, Arkansas 
Cities, Direct Service Industries, Atlantic City, TDU Systems, 
Fertilizer Institute, LG&E, ABATE, Oglethorpe.
    \777\ E.g., TAPS, Missouri Joint Commission, Detroit Edison 
Customers, LEPA, APPA, Cleveland.
    \778\ According to LEPA, the normal set of NRC license 
conditions included an explicit wheeling commitment and many of the 
license conditions clearly referenced the possibility that the 
wheeling commitment would lead to the loss of customers to whom the 
utility had been selling bulk power supply as well as retail power. 
LEPA submits that acceptance of such license conditions should have 
ended any reasonable expectation that a utility might have had of 
continuing to serve a full requirements customer, wholesale or 
retail, after the termination of its contract.
---------------------------------------------------------------------------

    Several comments were submitted concerning the examples listed in 
the NOPR that the Commission suggested, depending on all of the facts 
and circumstances, could establish a reasonable expectation that a 
contract would be extended. These examples include lack of access to 
alternative suppliers, repeated contract renewals, failure of a 
customer to object to the imposition of construction-work-in-progress, 
or communications between supplier and customer concerning including 
the customer's load in system planning.<SUP>779 Some commenters argue 
that evidence of this type should not be enough to rebut the 
presumption (or to overcome a summary judgment motion based on the 
presumption) of no reasonable expectation for contracts with notice 
provisions.<SUP>780 ELCON objects to using a customer's lack of 
alternative supply as evidence of a continued service obligation; it 
submits that the historic lack of supply alternatives has been caused 
by undue exercise of market power and should not be rewarded.<SUP>781 
Las Cruces suggests that if lack of opposition to construction-work-in-
progress evidences a reasonable expectation of continued service, 
continuous opposition should evidence a reasonable expectation that the 
customer will depart a system at the earliest possible date. With 
regard to the Commission's suggestion that communications with the 
customer on the customer's future plans could establish reasonable 
expectation, Direct Service Industries submits that no claimed reliance 
should be deemed reasonable unless the seller obtained express 
assurances from the customer that the customer intended to continue to 
purchase power from the seller beyond its current contract.
---------------------------------------------------------------------------

    \779\ See FERC Stats. & Regs. para. 32,514 at 33,117.
    \780\ E.g., TAPS, Phelps Dodge. Phelps Dodge suggests that 
evidence of past contract renewals, by itself, should not serve to 
rebut the presumption that the utility has no reasonable expectation 
of contract renewal in the future.
    \781\ In contrast, EEI believes that lack of access to 
alternative suppliers can be evidence that a utility reasonably 
expected to continue to serve a customer.
---------------------------------------------------------------------------

    We also received comments on the time at which the reasonable 
expectation had to exist. TAPS urges that the Commission should focus 
on whether a utility had a reasonable expectation of continued service 
when it entered into the most recent execution, renewal or amendment of 
the power supply contract.<SUP>782 PSE&G, on the other hand, argues 
that the focus of the Commission's review should be whether, at the 
time of incurring or obligating itself to incur the cost of serving a 
customer, the utility had a reasonable expectation of serving that 
customer for its planning horizon.
---------------------------------------------------------------------------

    \782\ If the investment now alleged to be stranded was incurred 
after the most recent amendment or extension to the contract, TAPS 
would focus the reasonable expectation review on such later date.
---------------------------------------------------------------------------

b. Application of Reasonable Expectation Standard to Non-Contiguous 
Service Territory
    Some commenters discuss the situation in which a utility has been 
making wholesale requirements sales to a customer in a non-contiguous 
service territory and, in order to make such a sale possible, 
transmission service has been rendered by an intervening utility. They 
argue that this situation presents conclusive evidence that the 
customer had a choice of wholesale suppliers and, therefore, that the 
seller had no reasonable expectation that the contract would be 
extended.<SUP>783 Direct Service Industries submits that if a customer 
has power supply options that do not rely on access to the selling 
utility's transmission system, the selling utility could have had no 
reasonable expectations other than those expressly created by contract. 
NM Industrials submits that allowing recovery of stranded costs in this 
situation would also constitute retroactive ratemaking in violation of 
Arkansas Louisiana Gas Company v. Hall.<SUP>784 It argues that by 
assessing stranded costs at the close of a contract's term against 
customers that do not even need a generating utility's transmission 
services to leave its system, the Commission would retroactively alter 
the terms and conditions of the rates for generation negotiated between 
the parties and approved by the Commission.
---------------------------------------------------------------------------

    \783\ E.g., IL Com, Utilicorp, PSG&E, NM Industrials.
    \784\ 453 U.S. 571 (1981).
---------------------------------------------------------------------------

    Other commenters submit that in these circumstances the Commission 
should give the supplier the opportunity to prove that it had a 
reasonable expectation that it would continue to serve the 
customer.<SUP>785 ELCON and WP&L state that the reasonable expectation 
standard should be satisfied (or not) by reference to the parties' 
existing contract, regardless of whether the customer is in a 
contiguous service territory.
---------------------------------------------------------------------------

    \785\ E.g., Florida Power Corp, Consumers Power, FL Com, TDU 
Systems.
---------------------------------------------------------------------------

    Utility Investors Analysts asserts that a seller will always have a 
reasonable expectation that a business relationship can be continued 
with a current customer and that the better presumption would be that 
the contract will be extended unless evidence to the contrary exists.

[[Page 21653]]

c. Application of Reasonable Expectation Standard to Retail-Turned-
Wholesale Customers or To Retail Wheeling
    A number of commenters support the Commission's proposal to apply 
the reasonable expectation standard in these cases.<SUP>786 PA Com 
submits that the case-by-case analysis contemplated by the Commission 
for establishing a utility's reasonable expectation of continuing to 
serve a wholesale requirements customer should also apply in the case 
of a retail-turned-wholesale customer or a retail customer that obtains 
retail wheeling.
---------------------------------------------------------------------------

    \786\ E.g., PA Com, Com Ed, CSW, United Illuminating, UFIT, 
PSNM, TDU Systems.
---------------------------------------------------------------------------

    Some commenters believe that the reasonable expectation test would 
be easily met in those instances in which state law awards exclusive 
service territories and imposes an obligation to serve.<SUP>787 Some 
contend that the reasonable expectation standard should be presumed met 
in these circumstances because state law obligates a utility to serve 
all retail customers. A number of commenters assert that such a 
presumption would obviate the need for case-by-case showings concerning 
the expectations of each utility and the nature of each 
franchise.<SUP>788 At a minimum, several commenters propose that the 
Commission adopt a rebuttable presumption that utilities had an 
obligation to serve retail customers and therefore that the reasonable 
expectation test is met in a retail-turned-wholesale customer scenario 
or in the case of costs stranded as a result of retail 
wheeling.<SUP>789
---------------------------------------------------------------------------

    \787\ E.g., Com Ed, Central and Southwest, United Illuminating, 
Utilities For Improved Transition, Utility Investors Analysts, 
Utility Shareholders.
    \788\ E.g., EEI, Minnesota Power, PECO, Puget, Centerior, 
Florida Power Corp, FL Com, Southern, SoCal Edison, NEPCO, Consumers 
Power, Coalition for Economic Competition. NEPCO asserts that the 
Supplemental Stranded Cost NOPR does not cite any comments or 
evidence casting doubt on the Commission's initial proposal (in the 
initial Stranded Cost NOPR) not to apply the reasonable expectation 
test to retail-turned-wholesale or retail customers that obtain 
retail wheeling on the basis that utilities operating under an 
obligation to serve at retail necessarily have an entitlement to 
recover the costs prudently incurred in fulfillment of that 
obligation.
    \789\ E.g., EEI, Detroit Edison, Centerior, Consumers Power, 
Ohio Edison.
---------------------------------------------------------------------------

    On the other hand, a number of commenters argue that there is no 
basis for a utility to reasonably expect that it will continue to serve 
a particular customer in states where franchises are non-
exclusive.<SUP>790 Several of these commenters argue that a utility 
operating under a non-exclusive franchise is faced with the ever-
present prospect that the communities it serves may build their own 
systems.<SUP>791
---------------------------------------------------------------------------

    \790\ E.g., Wing Group, Alma, Total Petroleum, Cleveland, ABATE, 
N.Y. Mayors, CAMU, Suffolk County.
    \791\ E.g., Wing Group, Total Petroleum, ABATE, CAMU, NY Mayors. 
Proposals advanced by commenters to address non-exclusive franchises 
include suggestions that the Commission: summarily reject claims to 
recover retail stranded costs where the utility has a non-exclusive 
franchise and historically has been subject to retail competition 
(e.g., Cleveland); apply a rebuttable presumption that a utility had 
no reasonable expectation of continued service where a municipal 
franchise is expiring and the municipality has put the retail 
supplier on notice that the municipality may seek an alternative 
source of power supply (e.g., Las Cruces); or provide that no 
stranded cost claim will be entertained absent a showing, by 
reference to applicable state law, that the utility had an exclusive 
service franchise obligation or was otherwise subject to an 
obligation to serve the customer that is departing its system (e.g., 
Phelps Dodge).
---------------------------------------------------------------------------

    Other commenters oppose the suggestion that the reasonable 
expectation test cannot be met where a franchise is non-exclusive or 
has terminated.<SUP>792 They argue that a utility's obligation to serve 
retail customers arises under state laws independent of the franchise. 
SoCal Edison explains that in states such as California, a franchise is 
nothing more than the source of a utility's right to use the city's 
streets, poles, rights of way, etc., and that a utility's duty to serve 
extends to all customers within its certificated service territories 
and not simply to those areas in which it has a franchise.
---------------------------------------------------------------------------

    \792\ E.g., Utility Working Group, SoCal Edison, Florida Power 
Corp, PG&E. Referring to the Commission's statement that it expects 
the reasonable expectation test to be easily met in those instances 
in which state law awards exclusive territories and imposes a 
mandatory obligation to serve, Utility Working Group asks the 
Commission to make clear in the final rule that it did not intend by 
that example that utilities with non-exclusive service territories 
would be presumed to fail the reasonable expectation test. According 
to Utility Working Group, the focus of the test must be on the 
utility's obligation to serve, which may be separate from any 
franchise arrangements.
---------------------------------------------------------------------------

Commission Conclusion
    We reaffirm that a utility seeking to recover stranded costs must 
demonstrate that it had a reasonable expectation of continuing to serve 
a customer. Whether a utility had a reasonable expectation of 
continuing to serve a customer, and for how long, will be determined on 
a case-by-case basis, and will depend on all of the facts and 
circumstances.<SUP>793
---------------------------------------------------------------------------

    \793\ The examples that the Commission provided in the 
Supplemental NOPR of possible ways to establish reasonable 
expectation were not intended to be dispositive of the issue. As we 
make clear in this Rule, whether a particular utility had a 
reasonable expectation that a contract would be extended will depend 
on all of the facts and circumstances.
---------------------------------------------------------------------------

    Further, we will apply the reasonable expectation standard in those 
cases where a utility has been making wholesale requirements sales to a 
customer in a non-contiguous service territory and, in order to make 
such a sale possible, transmission service has been rendered by an 
intervening utility. We believe it is appropriate to give the utility 
an opportunity to prove that it had a reasonable expectation of 
contract renewal in circumstances in which the remote customer becomes 
an unbundled transmission services customer of the former 
supplier.<SUP>794
---------------------------------------------------------------------------

    \794\ However, if the remote customer does not use the former 
supplying utility's open access tariff to reach the new supplier, 
there would be no ``wholesale stranded costs'' as that term is 
defined in this Rule. In this situation, we would not allow extra-
contractual recovery of stranded costs. Thus, there would be no need 
to address reasonable expectation. See Section IV.J.12.
---------------------------------------------------------------------------

    We also reaffirm our determination that the existence of a notice 
provision in a contract creates a rebuttable presumption that the 
utility had no reasonable expectation of serving the customer beyond 
the specified period. Whether or not a contract contains an 
``evergreen'' or other automatic renewal provision will be a factor to 
be considered in determining whether the presumption of no reasonable 
expectation is rebutted in a particular case.
    We will not adopt a minimum notice period for purposes of applying 
the reasonable expectation rebuttable presumption. Whether a utility 
had a reasonable expectation of continuing to serve a customer, 
including whether there is sufficient evidence to rebut the presumption 
that no such expectation existed beyond the notice provisions in a 
contract, will depend on the facts of each case.
    In addition, we reaffirm our preliminary determination to apply the 
reasonable expectation standard to retail-turned-wholesale customers. 
In this scenario, before the Commission will permit a utility to 
recover stranded costs, the utility must demonstrate that it incurred 
such costs based on a reasonable expectation that the retail-turned-
wholesale customer would continue to receive bundled retail service. 
Whether the state law awards exclusive service territories and imposes 
a mandatory obligation to serve would be among the factors to be 
considered in determining whether the reasonable expectation test is 
met in a particular case.<SUP>795
---------------------------------------------------------------------------

    \795\ The same procedures would apply to retail customers that 
obtain retail wheeling.
---------------------------------------------------------------------------

    We further note that we are not addressing in this Rule who will 
bear the stranded costs caused by a departing generation customer if 
the Commission finds that the utility had no reasonable expectation of 
continuing to serve that

[[Page 21654]]

customer. As we suggested in the initial Stranded Cost NOPR,<SUP>796 we 
anticipate that, in such a case, a public utility will seek in 
subsequent requirements rate cases to have the costs reallocated among 
the remaining customers on its system. However, we will not prejudge 
that issue here.
---------------------------------------------------------------------------

    \796\ FERC Stats. & Regs. para. 32,507 at 32,872.
---------------------------------------------------------------------------

9. Calculation of Recoverable Stranded Costs
    In the Supplemental Stranded Cost NOPR, the Commission proposed 
that the determination of recoverable stranded costs be based on a 
``revenues lost'' approach. Under this approach, stranded costs are 
calculated by subtracting the competitive market value of the power the 
customer would have purchased from the revenues that the customer would 
have paid had it stayed on the utility's generation system. We cited 
several benefits that we believe a ``revenues lost'' approach offers 
over a hypothetical cost-of-service approach, including avoidance of an 
asset-by-asset review, minimization of cost allocation procedures, and 
ease of application.<SUP>797
---------------------------------------------------------------------------

    \797\ Id. at 33,121.
---------------------------------------------------------------------------

    We sought comments on how to calculate what the utility's revenue 
stream would have been had the customer continued service. We also 
sought comments on how to calculate the revenues that the utility would 
receive in a competitive market for the stranded assets. This included 
whether we should require the utility to track the actual selling price 
of the power over time or require the utility to use an up-front 
approach (such as an estimate of the forecasted market value of the 
power for the period during which the customer would have taken 
service). We asked whether we should allow prices in futures markets or 
forward markets to be used in an up-front approach, assuming such 
financial instruments become available.<SUP>798
---------------------------------------------------------------------------

    \798\ Id.
---------------------------------------------------------------------------

    We suggested that the revenues lost approach automatically takes 
account of mitigation measures because it reduces the amount of 
stranded costs recoverable by a utility by the market price of the 
power that the customer no longer takes. We noted that this is 
particularly so if mitigation is reflected through a one-time, up-front 
estimate of the future market value of the power and is not trued up 
over time. We sought comments regarding implementation of a mitigation 
requirement. If mitigation is trued up over time, we asked how the 
Commission should ensure that the utility takes all reasonable steps to 
mitigate its own costs so as to minimize what the customer would have 
paid. We also asked how the Commission should ensure that the utility 
does its best to sell the power at its highest possible value. In 
addition, we asked whether there are other mitigation measures that 
should be taken into account (such as efficiency improvements that a 
utility would have undertaken regardless of whether the particular 
customer continued to take power under its contract, or cost savings 
resulting from the buy-out of a fuel contract made possible by the 
customer's departure).<SUP>799
---------------------------------------------------------------------------

    \799\ Id. at 33,123. We also asked how revenues received as a 
result of mitigation measures should be reflected in the 
determination of the amount of recoverable stranded costs; what 
special accounts, if any, should be created to track revenue 
liability for specific customers, revenues from mitigation measures, 
and other revenues received by the utility that offset the stranded 
cost liability; whether any adjustment should be permitted to the 
revenues that the utility claims will be realized in a competitive 
market for its stranded assets, and if so, how often and under what 
circumstances. Further, we sought comments on whether there are 
special costs that warrant some special consideration in the 
determination of stranded cost liability under a revenues lost 
approach, and if so, how they should be treated. Id. at 33,121-22.
---------------------------------------------------------------------------

    With regard to determining how long a utility could have reasonably 
expected to keep a generation customer (which we will call the 
``reasonable expectation period''), we preliminarily found that a one-
size-fits-all approach is not appropriate. We sought further comment 
with respect to whether the Commission ought to establish presumptions 
or, in the alternative, absolute limits on a customer's maximum 
liability when a utility establishes that it had a reasonable 
expectation that the contract would be extended. We inquired whether it 
would be appropriate to pick an outer limit equal to the revenues that 
the utility would lose during the length of one additional contract 
extension period, or during the length of the utility's planning 
horizon. We also asked what other events or criteria might be used to 
establish either presumptions or absolute limits on the reasonable 
expectation period.<SUP>800
---------------------------------------------------------------------------

    \800\ Id. at 33,122.
---------------------------------------------------------------------------

    In addition, we proposed procedures for providing a customer 
advance notice of how the utility would propose to calculate costs that 
the utility claims would be stranded by the customer's 
departure.<SUP>801 We invited comments on these procedures.<SUP>802
---------------------------------------------------------------------------

    \801\ Id. at 33,114-15.
    \802\ Id. at 33,115.
---------------------------------------------------------------------------

Comments
a. Revenues Lost Approach
    Numerous commenters, including almost all investor-owned utility 
commenters, support the revenues lost approach for calculating stranded 
costs.<SUP>803 Among other things, commenters maintain that the 
revenues lost approach is fair, reliable, and less complicated than the 
asset-by-asset approach. As discussed below, while some of these 
commenters support an ``up-front'' determination of stranded costs with 
no subsequent adjustments, others prefer use of a true-up mechanism 
whereby a customer's responsibility for stranded costs is adjusted to 
the extent that the actual competitive market value is different from 
the estimated market value used to determine the customer's up-front 
stranded cost charge.
---------------------------------------------------------------------------

    \803\ E.g., Centerior, NYSEG, Florida Power Corp, Houston L&P, 
NIMO, Orange & Rockland, Com Ed, PSE&G, EEI, PECO, Texas Utilities, 
PG&E, SoCal Edison, Dayton P&L, El Paso, IL Com, United 
Illuminating, Nuclear Energy Institute.
---------------------------------------------------------------------------

    Other commenters, on the other hand, oppose the revenues lost 
approach.<SUP>804 Some commenters state that the revenues lost approach 
provides no incentive to mitigate stranded costs because, by permitting 
a utility to recoup from a departing generation customer the difference 
between the contract price and a power resale price, the utility 
receives the same total revenues regardless of whether the customer 
stays or leaves and regardless of whether the utility effectively 
mitigates stranded costs.<SUP>805 Others maintain that the revenues 
lost approach is imprecise.<SUP>806 Referencing the problems associated 
with avoided cost projections used in setting QF rates under PURPA, 
some of these commenters submit that the revenues lost approach also 
requires significant assumptions (regarding projected revenue streams, 
service levels, and generic market value forecasts).<SUP>807 Among the 
other criticisms of the revenues lost approach that are raised by 
commenters are that it leads to over-recovery of stranded 
costs,<SUP>808 is

[[Page 21655]]

anticompetitive,<SUP>809 and that it leads to cost shifting.<SUP>810 
NARUC and TDU Systems also maintain that it is likely that assets 
stranded by a customer's departure from the utility's generation system 
will be used to serve new customers but that the revenues lost approach 
offers no method of accounting for such ``unstranding'' of assets.
---------------------------------------------------------------------------

    \804\ E.g., LG&E, TAPS, TDU Systems, ABATE, Blue Ridge, NY 
Energy Buyers, WP&L, PA Com, KY Com, American National Power, ELCON, 
Texaco, UT Com, NARUC, NIEP, DE Muni, Reynolds, Knoxville, Alma, 
APPA, NY Industrials, IL Industrials, SC Public Service Authority, 
Caparo, American Forest & Paper.
    \805\ E.g., NIEP, DE Muni and TDU Systems.
    \806\ E.g., SC Public Service Authority, ABATE, NY Energy 
Buyers, NARUC, ELCON, American Forest and Paper, APPA.
    \807\ E.g., NARUC, NYSEG.
    \808\ E.g., NRECA, NIEP, TDU Systems.
    \809\ E.g., TDU Systems, Blue Ridge, NY Energy Buyers.
    \810\ E.g., UT Com.
---------------------------------------------------------------------------

    A number of commenters request clarification of the stranded cost 
formula contained in the NOPR, including specific instructions 
regarding how to calculate the revenues the customer would have paid 
the utility had it remained a customer and the competitive market value 
of the power the customer would have purchased.<SUP>811 Some of these 
commenters suggest that the stranded cost issue will be more 
contentious if the final rule does not provide greater detail.<SUP>812 
Several commenters request that the Commission issue a detailed list of 
recoverable costs.<SUP>813 A number of commenters propose detailed 
alternatives to, or variations of, the revenues lost approach.<SUP>814
---------------------------------------------------------------------------

    \811\ E.g., Utility Investors Analysts, Public Power Council, 
Atlantic City, EEI, PA Com, NYSEG, Central Montana EC, Nebraska 
Public Power District, LG&E ABATE.
    \812\ Several commenters (Illinois Power, Oklahoma G&E, and 
Utility Investors Analysts) suggest that the Commission hold a 
technical conference to discuss how best to define the calculation 
of the formula components.
    \813\ Central Montana EC and NY Energy Buyers.
    \814\ See EEI, Electronic Data Systems, Knoxville, NIMO, NYSEG, 
NY Energy Buyers, Reynolds.
---------------------------------------------------------------------------

    Numerous commenters urge the Commission to be flexible and not 
overly prescriptive regarding the calculation of the formula 
components.<SUP>815 These commenters generally recommend that the 
Commission judge each stranded cost proposal on a case-by-case 
basis.<SUP>816
---------------------------------------------------------------------------

    \815\ E.g., Nuclear Energy Institute, EEI, Consumers Power, PA 
Com, Oklahoma G&E, Portland, Knoxville, MidAmerican, Seattle, Salt 
River, Washington and Oregon Energy Offices, SMUD, Caparo.
    \816\ Some commenters (e.g., Alma, Freedom Energy) oppose such 
flexibility. Alma maintains that clarity of rules is needed to 
provide participants in the competitive market as much certainty as 
possible about stranded cost charges likely to be recovered before 
they engage in alternative transactions. Freedom Energy similarly 
supports across-the-board or generic standards, as opposed to a 
case-by-case approach.
---------------------------------------------------------------------------

Definition and Calculation of Revenue Stream
    Some commenters maintain that the revenue stream component should 
be calculated based on the present rates paid by the customer.<SUP>817 
These commenters state that because present rates have been approved by 
various commissions, the costs have been shown to be legitimate, 
prudent, and verifiable.
---------------------------------------------------------------------------

    \817\ E.g., Centerior, Com Ed, Duke, Entergy, Florida Power 
Corp, Utility Investors Analysts, CA Energy Co, CSW.
---------------------------------------------------------------------------

    Other commenters oppose the use of current rates to calculate the 
utility's revenue stream. WP&L believes that the use of current rates 
would be overly generous and recommends capping the revenue measure at 
a regional average rate rather than a utility-specific rate. A number 
of other commenters argue that the effects of competition should be 
factored into the revenue stream by using the rates for capacity and 
energy actually offered or available in the utility's marketplace, such 
as incentive and special rates, not just the tariff rates to a 
particular customer.<SUP>818 Several commenters support removal of rate 
of return-related revenues associated with stranded assets, including 
risk premiums that are designed to compensate for potential nonrecovery 
of stranded costs.<SUP>819 EEI, in contrast, opposes any disallowance 
of rate of return-related revenues on the grounds that such a 
disallowance would violate the constitutional bar against the taking of 
private property without just compensation. Electronic Data Systems 
recommends calculation of the revenue stream using projected rates that 
include the effects of future rate increases.
---------------------------------------------------------------------------

    \818\ E.g., Alma, ABATE, DOD, TDU Systems, ELCON.
    \819\ E.g., NRECA, CA Energy Co, ABATE, DOD.
---------------------------------------------------------------------------

    The Commission requested comments on what categories of costs, in 
addition to investment costs, should be eligible for stranded cost 
recovery. In response, many commenters support the inclusion in the 
revenue stream calculation of additional costs, termed ``special'' 
costs, that may not be currently reflected in the rates paid by the 
departing customers, but that were incurred to provide service to these 
customers.<SUP>820 ``Special'' costs include: (1) Nuclear 
decommissioning costs; (2) environmental obligations existing at the 
time of the customer's departure; (3) purchased power contracts; (4) 
buyouts and buydowns of purchased power contracts; and (5) all 
regulatory assets, including deferred costs of generating assets for 
which regulators have promised recovery, deferred taxes, transition 
costs for post-employment benefits other than pensions, and contingent 
liability.
---------------------------------------------------------------------------

    \820\ E.g., EEI and various investor-owned utilities, Nuclear 
Energy Institute, NC Com, Legal Environmental Assistance, EPA, 
Utilities for Improved Transition, PA Com.
---------------------------------------------------------------------------

    Other commenters oppose the inclusion of ``special'' costs in the 
calculation of the revenue stream.<SUP>821 TAPS questions how a 
customer can be held responsible for a cost that, by definition, it was 
never under a contractual obligation to pay. WP&L states that 
suppliers' rates should already reflect reasonable estimates of 
decommissioning costs and, therefore, no additional recovery is 
warranted.
---------------------------------------------------------------------------

    \821\ E.g., TAPS, WP&L, UT Industrials, UtiliCorp, American 
Forest & Paper.
---------------------------------------------------------------------------

    Some commenters argue that the calculation of stranded costs should 
include social costs, such as demand side management, environmental 
costs, low income assistance costs, and costs associated with the 
management of fish and wildlife.<SUP>822
---------------------------------------------------------------------------

    \822\ E.g., DC Com, Sustainable Energy Policy, Washington and 
Oregon Energy Offices.
---------------------------------------------------------------------------

    NARUC states that the Commission should not preempt the ability of 
states to establish competitively neutral programs, such as DSM and 
energy efficiency, environmental mitigation, and R&D.
    Various commenters state that any determination of stranded costs 
should take into account all offsetting benefits realized by the 
transmission provider upon a customer's departure.<SUP>823 Some 
commenters describe these costs as ``stranded benefits.'' <SUP>824
---------------------------------------------------------------------------

    \823\ E.g., AEC & SMEPA, Electronic Data Systems, Freedom Energy 
Co, LG&E, American National Power, EGA, Entergy, AMP Ohio, TDU 
Systems, TAPS, Las Cruces.
    \824\ TDU Systems proposes that the Commission allow for the 
recovery of stranded benefits in one of two ways: (1) Require direct 
payment of stranded benefits to a wholesale purchaser whose contract 
is terminated; or (2) allow a party to continue to receive power at 
cost-based rates for a period sufficient for the purchaser to be 
``transitioned'' into a competitive market.
---------------------------------------------------------------------------

    Most commenters favor the removal of avoided variable costs from 
the calculation of stranded costs on the basis that only fixed costs 
are truly stranded.
    Some commenters support prioritizing stranded cost 
recovery.<SUP>825 These commenters argue that stranded costs should be 
categorized and ranked by the degree of responsibility that utilities 
had for their incurrence. Utilities would be allowed the greatest 
percentage of recovery for those stranded costs over which they had the 
least control.
---------------------------------------------------------------------------

    \825\ E.g., ELCON, NY Energy Buyers, SMUD, Caparo.
---------------------------------------------------------------------------

Definition and Calculation of the Competitive Market Value
    There generally was no consensus among the commenters concerning 
how

[[Page 21656]]

to determine the revenues a utility would receive in a competitive 
market for the stranded assets, that is, the competitive market 
value.<SUP>826 Proposals for calculating competitive market value 
include using: (1) The marginal cost of the released capacity; (2) the 
long-run marginal cost of the most competitive incremental generation 
replacement technology; (3) the marginal cost of requirements service; 
(4) a combination of the marginal costs of the utility, alternative 
suppliers, and others; (5) the cost of a combined cycle combustion 
turbine; (6) the price paid by the departing generation customer; (7) 
the highest price available in the market; and (8) auctions. In 
addition, to the extent that a futures market is sufficiently well-
developed when the Commission issues a final rule, several commenters 
believe that futures market prices could be used as an estimate of 
market value.<SUP>827
---------------------------------------------------------------------------

    \826\ E.g., Centerior, Duke, Entergy, Com Ed, Houston L&P, 
Florida Power Corp, Carolina P&L, NRRI, WP&L, DOE, CSW, UtiliCorp, 
LG&E, FL Com.
    \827\ E.g., WP&L, DOD, Duke, PSNM, ABATE, Houston L&P. The 
Commission notes that the New York Mercantile Exchange only recently 
began trading in electricity futures and that such trading was 
limited to two delivery points located within the Western 
Interconnection.
---------------------------------------------------------------------------

    MT Com contrasts the effect of using short-term nonfirm prices 
instead of long-term firm prices as the competitive market value. It 
states that if short-term nonfirm prices are used, the stranded cost 
estimate would be higher, because the market price of short-term 
nonfirm power is lower than both the market price of long-term firm 
power and the embedded cost price.
    Some commenters express concern regarding the difficulty of 
determining the market value of the displaced capacity under the 
revenues lost approach.<SUP>828 Among other things, commenters note 
that because a competitive market does not yet exist, the market price 
cannot be calculated in advance. For this reason, several commenters 
support an after-the-fact determination of market value.<SUP>829
---------------------------------------------------------------------------

    \828\ E.g., MI Com, NSP, NY Energy Buyers, KS Com.
    \829\ E.g., KS Com, NY Energy Buyers.
---------------------------------------------------------------------------

Snapshot Approach vs. True-Ups
    Commenters are split on whether the revenues lost approach should 
use a one-time snapshot approach <SUP>830 or whether true-ups should be 
required or allowed.<SUP>831 The primary rationale offered in support 
of a snapshot approach is certainty; <SUP>832 the primary rationale 
offered in support of true-ups is accuracy.
---------------------------------------------------------------------------

    \830\ Commenters that support a one-time, up-front approach 
include FL Com, Dayton P&L, Portland, DE Muni.
    \831\ Commenters that support true-ups include ELCON, NYSEG, MN 
DPS, Reynolds, TAPS, NIMO, DOE, Electric Consumers Alliance, Com Ed, 
United Illuminating, SoCal Edison.
    \832\ DE Muni urges rejection of true-ups on the basis that 
true-ups represent guaranteed recovery of 100 percent of stranded 
costs.
---------------------------------------------------------------------------

    Commenters that support true-ups note the inaccuracy associated 
with long-term avoided cost estimates contained in PURPA-mandated QF 
contracts and maintain that the projections required by the revenues 
lost approach will produce similarly disastrous results if true-ups are 
not permitted. As a component of the true-up calculation, some 
commenters favor inclusion of revenues associated with future load 
growth of remaining customers.<SUP>833 According to Electronic Data 
Systems, if these revenues are not included in a true-up calculation, 
the utility could over- or under-collect stranded costs, depending on 
whether and what type of load growth is anticipated. CA Energy Co and 
American National Power recommend consideration of load growth of 
remaining customers as a mitigating factor because the load increases 
of these customers allow the sale of the stranded capacity. CSW, on the 
other hand, opposes using the future load growth of remaining customers 
as a mitigation device. CSW states that the benefits of growth on the 
former supplier's system should flow to the customers who remain 
customers of that system. Ohio Ed agrees, except where the customer 
proves that the utility has deferred or cancelled capacity resource 
additions in response to departing customers.
---------------------------------------------------------------------------

    \833\ E.g., Electronic Data Systems, Alma, American National 
Power, CA Energy Co, NARUC, NRECA.
---------------------------------------------------------------------------

    Other commenters suggest that the Commission should not prescribe 
one method over the other.<SUP>834 EGA, for example, states that 
customers should have the choice of paying either a projected fixed 
amount or a charge that is periodically trued up.
---------------------------------------------------------------------------

    \834\ E.g., Atlantic City Electric, EGA, Conservation Law 
Foundation.
---------------------------------------------------------------------------

Mitigation
    A number of commenters agree that the revenues lost approach 
effectively encompasses mitigation.\835\ Others argue that mitigation 
should (or could) be accomplished through divestiture of assets or 
capacity auctions.\836\ LG&E states that a utility requesting recovery 
of stranded costs should be required to auction that portion of its 
system to the highest bidder. The difference between the auction price 
and the depreciated value of the auctioned assets could be used to 
determine stranded costs. However, LG&E does not advocate complete 
recovery of this difference; rather, it argues that this amount could 
be used as a starting point.
---------------------------------------------------------------------------

    \835\ E.g., Utility Investors Analysts, Duke, PSE&G, Com Ed, 
United Illuminating, Entergy.
    \836\ E.g., NIEP, LG&E, TDU Systems, EGA, NY Energy Buyers, 
ELCON, American National Power.
---------------------------------------------------------------------------

    Several commenters argue that the revenues lost approach can 
produce anticompetitive results if capacity auctions or divestiture are 
not required.\837\ A number of these commenters contend that utilities 
that recover significant stranded costs (while still maintaining 
control over the stranded capacity) can use the freed capacity to make 
sales in the market at subsidized prices. They maintain that these 
utilities do not have to worry about recovery of fixed costs because 
those costs are recovered by the stranded cost charge. According to 
these commenters, utilities can then remarket (or ``dump'') stranded 
capacity at artificially low prices (made possible by the subsidy from 
the stranded cost recovery) and thereby gain a competitive advantage in 
other transactions.\838\ If the utilities are permitted to remarket the 
displaced capacity, CA Energy Co states that market-sensitive floor 
prices should be set to prevent utilities from reselling power from 
stranded assets at artificially low prices.
---------------------------------------------------------------------------

    \837\ E.g., LG&E, Allegheny, TDU Systems, EGA, AMP Ohio, CA 
Energy Co, WP&L, Torco.
    \838\ CA Energy Co maintains that an anticompetitive intent 
could be hidden by the argument that power must be dumped to 
mitigate stranded costs. It thus submits that, even without 
intending to do so, a utility could cripple competition by 
depressing market rates to artificially low levels.
---------------------------------------------------------------------------

    Suggestions as to how to prevent such anticompetitive consequences 
include allowing the customer to own or control the residual asset or 
amount of stranded capacity equivalent to the lost revenues. According 
to EGA, the customer could market the capacity it would have had to pay 
for through stranded cost charges and thus prevent the utility from 
remarketing the capacity after it has been paid stranded costs.
    Several commenters take a harder line and would require suppliers 
seeking stranded cost recovery to offer for sale to the departing 
customer a ``slice'' of their system.\839\ TDU Systems states that the 
purchase of an undivided slice of the system is superior to divestiture 
of a specific asset because the utility cannot keep the wheat and leave 
the purchaser with the chaff. TDU Systems would also make purchase 
rights to the system assignable. According to TDU

[[Page 21657]]

Systems, this mitigation scheme is the only possible way to justify the 
revenues lost approach. TDU Systems argues that this proposal would 
inflict no harm on the utility, which would be fully compensated for 
the stranded assets. It also suggests that the ability to purchase a 
slice of the supplier's system would serve as an important bargaining 
tool in stranded cost negotiations, which would help level the playing 
field among the parties.
---------------------------------------------------------------------------

    \839\ E.g., TDU Systems, Arkansas EC.
---------------------------------------------------------------------------

    Other mitigation proposals include: (i) Requiring each utility to 
prepare a mitigation plan under the supervision of an independent 
expert that must be approved by the parties or by the Commission before 
stranded cost recovery is permitted; \840\ (ii) requiring a utility to 
report annually for a five-year period its mitigation activities and to 
identify its stranded costs yet to be recovered; \841\ and (iii) 
setting the market value of the displaced capacity at a high level 
(thereby reducing the stranded cost charge) to provide a mitigation 
incentive.\842\ A number of commenters support customer-controlled 
mitigation, arguing, among other things, that the entity responsible 
for paying stranded costs has the best incentive to mitigate them.\843\ 
Others support some form of utility sharing of stranded costs to give 
utilities an incentive to mitigate stranded costs.\844\
---------------------------------------------------------------------------

    \840\ See, e.g., CA Energy Co.
    \841\ See, e.g., PSNM.
    \842\ See WP&L.
    \843\ E.g., EEI, PA Com, AMP Ohio, TAPS.
    \844\ E.g., ABATE, Fertilizer Institute, IL Com, KS Com, San 
Francisco, UT Industrials, ELCON, CA Energy Co, MT Com, Caparo, WA 
Com, Education, NRRI, NY Energy Buyers, Reynolds, DOD, DC Com.
---------------------------------------------------------------------------

b. Reasonable Expectation Period (Period of Expected Continued Service)
    Numerous commenters oppose setting absolute limits on the period 
over which a customer's liability for stranded costs would be 
determined.\845\ They suggest instead that the Commission should apply 
the facts of each case, including the facts used to prove a reasonable 
expectation of continued service, to its determination of a reasonable 
expectation period. Among the factors commenters propose for 
consideration are: the utility's planning horizon; the average 
remaining life of the utility's generating facilities or a specific 
number of years that coincides with the duration of a utility-specific 
stranded cost recovery plan; utility projected load growth; dedicated 
facility construction lead times; estimated time to market stranded 
assets; the lesser of the utility's need date for new generation or the 
cross-over date when the market generation price is expected to equal a 
customer's embedded cost less other charges and compensation; and the 
period for which estimated revenues exceed market values. Commenters 
representing the financial community \846\ oppose limiting cost 
recovery from the departing generation customer based on the term of 
the contract. They argue that it was reasonable for a utility to expect 
to continue to serve a customer, or customers who would take its place, 
through the life of the assets; otherwise, the asset could not have 
been financed in the first place.
---------------------------------------------------------------------------

    \845\ See, e.g., Florida Power Corp, Central and South West, Com 
Ed, EEI, Montana, PECO, Minnesota DPS, NIMO, NSP, SoCal Edison, PA 
Com, Central Louisiana, Utility Investors Analysts, Salt River, 
Orange & Rockland.
    \846\ E.g., Utility Investors Analysts and Utility Shareholders.
---------------------------------------------------------------------------

    A number of other commenters urge the Commission to prescribe 
limits on a customer's maximum liability.\847\ Some commenters believe 
that the utility's planning horizon is the reasonable expectation 
period.\848\ PSE&G states that since utilities invested and incurred 
costs to serve customers based on the planning horizon, the planning 
horizon is the only logical period. Other commenters propose that the 
reasonable expectation period be limited to one contract extension 
period, or to the shortest of: (i) One additional contract renewal 
period; (ii) the utility's planning horizon; (iii) the period it would/
does take for load growth on the seller's system to absorb the lost 
load; or (iv) the contractual notice period.\849\ Other suggested 
limits include the weighted average remaining life of all generating 
assets; \850\ the in-service date of the utility's next avoidable 
generating unit or purchased power contract that is projected to have a 
capacity factor comparable to the departing generation customer's load 
factor minus a one-time mitigation effort; \851\ and a rebuttable 
presumption that two years is the maximum time for a utility reasonably 
to expect to receive revenue from tariff sales or ``open-ended'' 
contracts.\852\
---------------------------------------------------------------------------

    \847\ E.g., NIEP, TAPS, Allegheny, Central Montana, Municipal 
Energy Agency Nebraska, PSNM, ABATE, ELCON, PSE&G, UtiliCorp.
    \848\ E.g., PSE&G, PSNM, ELCON, Oklahoma G&E, Duke. Oklahoma G&E 
supports use of the utility's planning cycle for retail stranded 
costs and use of the contract term for wholesale stranded costs. 
Duke states that the Commission should permit the customer and the 
transmission provider to establish the compensation period at 
something less than the maximum period.
    \849\ E.g., UtiliCorp, WP&L, Missouri Joint Commission, TAPS, 
Municipal Energy Agency Nebraska, TDU Systems.
    \850\ E.g., Carolina P&L.
    \851\ E.g., FL Com.
    \852\ E.g., UT Industrials.
---------------------------------------------------------------------------

    Other commenters propose recovery periods that range from three to 
five years (e.g., Central Montana EC),\853\ five years (e.g., Public 
Power Council), and eight years (e.g., Allegheny).\854\
---------------------------------------------------------------------------

    \853\ Central Montana describes as ``excessive'' the recovery 
period offered to it by Montana. Central Montana states that it gave 
notice under a five-year notice provision and that Montana responded 
with a stranded cost demand extending 14 years after notice of 
termination (nine years from the date service would terminate).
    \854\ Allegheny would exempt three types of stranded costs from 
such a limit: (1) Those due to PURPA power purchases (it submits 
that these were federally-mandated rather than profit-motivated 
business decisions); (2) those due to regulatory assets (such as 
deferred taxes); and (3) those due to municipalization. In addition, 
it favors establishing a rebuttable presumption that these special 
costs are eligible for stranded cost recovery.
---------------------------------------------------------------------------

    GA Com and AZ Com state that stranded cost recovery should not go 
on indefinitely. GA Com states that stranded costs should be collected 
for a sufficient period of time to ensure full recovery and 
indifference on the part of the utilities' remaining native load 
customers. AZ Com states that a specific termination period will also 
create an incentive for utilities to mitigate stranded costs.
c. Proposed Stranded Cost Recovery Procedures
    Several commenters \855\ urge the Commission to be flexible in 
evaluating proposed mechanisms for recovery of stranded costs, 
including the payment method, noting that an approach suitable to one 
utility and its customers may not be suitable to another. They say that 
utilities within a region might find a mechanism that meets their 
region's unique characteristics.
---------------------------------------------------------------------------

    \855\ E.g., EEI, Centerior, PECO, Houston L&P, Salt River.
---------------------------------------------------------------------------

    Some commenters oppose certain aspects of the procedures proposed 
in the NOPR. For example, TAPS objects that the NOPR procedure aimed at 
providing advance notice to the customer of its potential stranded cost 
obligation resembles the procedure rejected in Cajun. It says that 
``the customer will likely be forced to spend significant time and 
resources `litigat[ing] to determine the price of a product(,)' thereby 
`introduc[ing] deal-killing transactional costs and uncertainties.' '' 
(citing Cajun, 28 F.3d at 179). TAPS proposes that the seller be 
required to produce a stranded cost estimate that reflects a good 
faith, reasonable estimate of the likely impact of mitigation and that 
sellers making excessive and unsupported stranded cost claims be 
penalized. At a minimum, it argues that the seller should be held 
responsible for the costs

[[Page 21658]]

reasonably expended by the buyer to litigate the stranded cost claim.
    DE Muni asserts that if filing a complaint to redress grievances 
related to the recovery of stranded costs is to be a meaningful remedy, 
the final rule should set a time limit within which the complaint must 
be resolved.
    A number of commenters offer modifications to the recovery 
procedures set forth in the NOPR, including: (1) Extending a utility's 
response time for providing stranded cost liability estimates from 30 
days to at least 60 days; \856\ (2) requiring a utility to provide to 
each wholesale customer within six months of the effective date of the 
final rule: (a) The formula that the utility proposes to use to 
calculate the customer's maximum possible stranded cost exposure 
without mitigation; and (b) an actual calculation of the customer's 
stranded cost exposure assuming the customer left the utility's system 
six months after the effective date of the final rule; \857\ (3) 
allowing customers that desire to litigate their stranded cost 
liability to do so in a forum in which all litigating customers 
participate; \858\ (4) requiring utilities to disclose their estimated 
transition cost liabilities (and the nature of those liabilities) 
before the effective date of the final rule to permit a realistic 
evaluation of the scope of the transition cost problem and possibly 
facilitate resolution of some disputes by settlement; \859\ (5) 
requiring any utility seeking stranded cost recovery to provide a list 
of the stranded facilities to the departing generation customer and 
offer that customer an equity position in those facilities in return 
for payment of stranded costs, thereby enabling the departing customer 
to recover some of its stranded costs payment when any of the 
facilities becomes useful again; \860\ (6) requiring a ``good faith 
request'' for an estimate of stranded costs based on an expected date 
of departure from the providing utility's system and mitigation efforts 
expected to be undertaken by the utility; \861\ and (7) requiring 
documented evidence that a utility made a good faith attempt to settle 
with a departing generation customer before the utility is given the 
opportunity to recover stranded costs.\862\
---------------------------------------------------------------------------

    \856\ E.g., Entergy.
    \857\ E.g., Associated Power.
    \858\ E.g., Associated Power.
    \859\ E.g., Texaco.
    \860\ E.g., Heartland.
    \861\ E.g., PSNM, ELCON.
    \862\ E.g., ELCON.
---------------------------------------------------------------------------

Commission Conclusion
    We reaffirm our proposal that the determination of recoverable 
stranded costs should be based on the ``revenues lost'' approach. We 
find that the revenues lost approach is the fairest and most efficient 
way to balance the competing interests of those involved.
    After careful consideration of the comments submitted, we have 
decided to adopt the following formula for calculating a departing 
generation customer's stranded cost obligation (SCO), on a present 
value basis, under a revenues lost approach:

SCO=(RSE-CMVE x L
where:
RSE=Revenue Stream Estimate--average annual revenues from the departing 
generation customer over the three years prior to the customer's 
departure (with the variable cost component of the revenues clearly 
identified), less the average transmission-related revenues that the 
host utility would have recovered from the departing generation 
customer over the same three years under its new wholesale transmission 
tariff.\863\
---------------------------------------------------------------------------

    \863\ In the case of a retail-turned-wholesale customer, 
subtraction of distribution system-related costs may also be 
appropriate.
---------------------------------------------------------------------------

CMVE=Competitive Market Value Estimate--determined in one of two ways, 
at the customer's option: Option (1)--the utility's estimate of the 
average annual revenues (over the reasonable expectation period ``L'' 
discussed below) that it can receive by selling the released capacity 
and associated energy, based on a market analysis performed by the 
utility; or Option (2)--the average annual cost to the customer of 
replacement capacity and associated energy, based on the customer's 
contractual commitment with its new supplier(s).
L=Length of Obligation (reasonable expectation period)--refers to the 
period of time the utility could have reasonably expected to continue 
to serve the departing generation customer. We reaffirm that we do not 
believe that a one-size-fits-all approach is appropriate for 
determining the length of a customer's obligation. If the parties 
cannot reach agreement as to the length of the customer's obligation, 
this period is to be determined through litigation as a part of the 
threshold issue of whether the utility had a reasonable expectation of 
continuing to serve the customer.
    Application of the foregoing formula and collection of the 
resulting stranded costs are subject to the following conditions:
    1. Cap on SCO. The quantity (RSE-CMVE) can be no greater than the 
average annual contribution to fixed power supply costs (defined as RSE 
less variable costs) that would have been made by the departing 
generation customer had it remained a customer.
    2. Changes in Customer Revenues. If the customer's rates (or 
contract demand amounts, if relevant) changed during the three-year 
period prior to the termination of its existing requirements contract, 
then the RSE should be calculated using the customer's most recent 12 
months of revenue.
    3. CMVE Option 2 Conditions. Option 2 (a CMVE equal to the average 
cost to the customer of replacement capacity and associated energy) 
would be available to a customer whose alternative purchase(s) runs 
concurrent with L, or, if longer than L, contains rates that do not 
fluctuate over the duration of the contract. The customer would be 
required to demonstrate (at the time it chooses this option) that the 
replacement capacity contract(s) is for service equivalent to the 
released capacity (that is, firm power for a period at least equal to 
L), and must also clearly identify the rates to be paid for the 
replacement service.
    4. Payment Options. The method and term of payment should be 
negotiated, but is ultimately left to the customer's discretion. 
Possible payment options include a lump-sum payment, an amortization of 
a lump-sum payment over a reasonable period of time, or a surcharge on 
the customer's transmission rate.
    5. Applicability. The formula is designed for determining stranded 
costs associated with departing wholesale generation customers and for 
retail-turned-wholesale customers.<SUP>864
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    \864\ The formula is not to be used for recovering stranded 
costs associated with retail wheeling. We believe the formula is 
unworkable in this scenario because one of its key elements--the 
option for a customer to market or broker the utility's power--may 
not be practicable for retail customers. Therefore, stranded costs 
associated with retail wheeling will be determined on a case-by-case 
basis.
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    6. Marketing/Brokering Option. The Commission will allow the 
customer, at its sole discretion, a choice to market the released 
capacity and associated energy (or to contract with a marketer for such 
service). Alternatively, the customer may choose to broker the released 
capacity and associated energy (or to contract with a broker).<SUP>865
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    \865\ The customer may also decide to remain a requirements 
customer for L. If the customer elects to remain a requirements 
customer, the utility will be obligated to continue service to the 
customer for the duration of L.

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[[Page 21659]]

    7. Released Capacity and Associated Energy. A utility requesting 
stranded cost recovery must indicate the amount of system capacity and 
the amount of associated energy released by the departing generation 
customer and used in the revenues lost calculation. This will allow the 
departing generation customer to fairly consider exercising a choice to 
market or broker the released capacity and associated energy.
    The formula balances a number of goals, including: (1) Ensuring 
full recovery of legitimate, prudent and verifiable stranded costs; (2) 
requiring the utility to mitigate stranded costs; (3) providing 
certainty for departing generation customers; and (4) creating 
incentives for the parties to renegotiate their existing requirements 
contracts or otherwise settle stranded cost claims without resort to 
litigation.
    Contrary to the objections of some commenters that the revenues 
lost approach creates no incentive to mitigate stranded costs, the 
formula automatically encompasses mitigation by reducing the departing 
generation customer's stranded cost obligation by the competitive 
market value of the released capacity and associated energy. Further, 
the option provided in the formula for a customer to market or broker 
the released capacity and associated energy protects the customer from 
a utility trying to overrecover stranded costs by estimating a low 
value for the released capacity and associated energy and thereby 
provides the customer some assurance that stranded costs will be 
minimized. Specifically, if a customer believes the utility's 
competitive market value estimate (CMVE) is too low, it can market or 
broker the released capacity and associated energy and reduce its 
stranded cost obligation.<SUP>866 We accordingly will not impose a 
separate mitigation obligation on the utility above that which is 
already subsumed in the revenues lost approach. In addition, a utility 
will continue to be subject to an ongoing prudence obligation to sell 
excess capacity off-system and/or to dispose of uneconomic assets.
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    \866\ This option also addresses the concerns of commenters 
that, by failing to require auctions or divestiture of stranded 
capacity, the Rule would allow a utility recovering stranded costs 
to sell the freed capacity at subsidized prices, thereby gaining a 
competitive advantage in other transactions. If the customer avails 
itself of this option, the utility would no longer control the 
released capacity.
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    We recognize that some commenters oppose the revenues lost approach 
as imprecise. However, any ratemaking method that relies on estimates 
will be subject to forecasting error. Moreover, in direct response to 
commenter concerns, we have gone to great lengths in this rule to 
provide specificity with respect to the calculation of the components 
of the formula. We believe that use of the formula will narrow the 
scope of disputes over the calculation of stranded costs, lend 
precision to the stranded cost amount it produces, and provide 
certainty to departing generation customers with respect to their 
stranded cost obligations.
Calculation of the Revenue Stream Estimate (RSE)
    The RSE component of the formula is based on revenues paid by the 
departing generation customer during the last three years of its 
contract or retail service. We believe that the use of ``present'' 
revenues in the calculation of the revenue stream has numerous 
advantages over other approaches advocated. The use of present revenues 
eliminates disputes over estimates of future revenues, thereby adding 
certainty to the calculation. It also eliminates the need for a 
detailed listing of includable costs, relying instead on the assumption 
that present rates include all of the utility's costs of providing 
service. Further, the rates that produce present revenues have been 
approved by regulators, which strongly suggests that the costs included 
in them are prudent, legitimate and verifiable.<SUP>867
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    \867\ The present rates, whether established by settlement or 
otherwise, have been found to be just and reasonable. In other 
words, they are neither confiscatory nor exorbitant.
---------------------------------------------------------------------------

    We reject the suggestion by commenters that a utility be required 
to calculate the revenue stream using any lower rate being offered by 
the utility for service comparable to that being taken by the customer 
when the customer departs the utility's generation system. A revenue 
stream calculated in this manner could deny a utility the opportunity 
to fully recover its stranded costs or could shift costs to other 
customers, a result we find unacceptable. Similarly, the elimination of 
return-related revenues from the revenue stream effectively would 
require shareholders to absorb stranded costs, which is contrary to our 
determination that a utility is entitled to an opportunity to fully 
recover legitimate, prudent and verifiable stranded costs.
Calculation of the Competitive Market Value Estimate (CMVE)
    We recognize the difficulty associated with estimating the 
competitive market value of the capacity and associated energy not 
purchased by the departing generation customer. However, we believe 
that an up-front estimate, which provides flexibility to the utility 
and a measure of certainty to customers, is superior to other 
proposals, provided the right mix of incentives and options is included 
in the formula.
    A utility requesting stranded cost recovery must estimate CMVE 
based on a market analysis, with all assumptions and work papers made 
available to the departing generation customer. This provides a utility 
with the flexibility to choose the methodology that it feels produces 
the best estimate of the competitive market value of the released 
capacity and associated energy. We note that numerous proposals for 
calculating competitive market value were made in the comments. The 
Commission believes that the flexibility provided by the formula we 
adopt in this Rule permits the filing utility to avail itself of many 
of these recommendations.
    At the same time, a utility may have an incentive to underestimate 
CMVE and thereby increase the stranded costs charge. To address this 
issue, the formula contains several features designed to create an 
incentive to produce a good faith estimate of stranded costs and to 
safeguard customers if a utility fails to do so. For example, the 
formula provides a departing generation customer with the option to 
market or broker the released capacity and associated energy if it 
believes the utility's estimate is too low. If the marketing option is 
chosen, the customer would buy the released capacity from the utility 
at the utility's market value estimate. The associated energy would be 
purchased at the utility's average system variable cost. The customer 
would then resell the released capacity and energy and keep the 
resulting revenues. If the revenues it receives are greater than the 
utility's market value estimate, the customer will have reduced its 
stranded cost obligation. If the customer chooses the brokering option 
and the released capacity and associated energy are purchased by a 
third-party for more than the utility's market value estimate, the 
difference between the average annual revenues produced by the sale and 
the utility's CMVE estimate will be used to lower the customer's 
stranded cost obligation. The utility may be required to show in a 
compliance filing that it has reduced the customer's stranded cost 
obligation under such circumstances.
    If the customer chooses CMVE Option 2 and meets its conditions, 
CMVE will be set at the average price that the customer pays its new 
supplier. The customer will test the market and choose the best deal 
available. Hence,

[[Page 21660]]

the price the customer pays its alternative supplier is arguably a more 
accurate measure of the competitive market value of the capacity and 
associated energy not taken from the host utility. Whether to exercise 
Option 2 resides solely with the customer.
    We further note that the sale of all or part of a utility's 
generating assets could be used as a method to determine competitive 
market value of such assets. Under the theory that an asset sale price 
reflects the highest value for the utility's assets, the Commission 
would presume that the competitive market value established under an 
open asset sale (i.e., an offer to sell assets to any taker) would 
fully satisfy the utility's responsibility to minimize stranded costs. 
If a stranded cost claim involves divestiture of assets, the amount of 
stranded costs associated with those assets would be the book value 
less the sale price. The Commission would determine the appropriate 
stranded cost charge based on the facts presented.
Snapshot Approach Versus True-Ups
    The revenues lost formula is based on a one-time snapshot approach. 
We favor this approach over the true-up approach because it creates 
certainty and will produce reasonably accurate results. True-ups, on 
the other hand, while theoretically more accurate, require periodic 
recalculation of stranded costs, which creates ongoing uncertainty and 
disputes. In addition, true-ups will result in additional transaction 
costs. We believe that an approach that provides certainty and 
establishes cost responsibility up front is best for what is 
fundamentally a transition issue.
Implementation Procedures <SUP>868
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    \868\ These procedures apply to a potential departing generation 
customer who is an existing wholesale requirements customer of a 
public utility, or a retail customer of a public utility who is 
contemplating becoming a wholesale transmission customer (such as 
through municipalization). They may be used at the option of the 
potential departing generation customer. An existing wholesale 
requirements customer may use the procedures in conjunction with, or 
in lieu of, a complaint under section 206 to amend its existing 
requirements contract to add an explicit stranded cost provision, as 
discussed in Section IV.J.5.
---------------------------------------------------------------------------

    In the Supplemental Stranded Cost NOPR, we proposed procedures to 
provide a potential departing generation customer with advance notice 
of how the utility would propose to calculate costs that the utility 
claims would be stranded by the customer's departure.<SUP>869 These 
procedures are modified as follows to incorporate the findings made in 
this rule:
---------------------------------------------------------------------------

    \869\ FERC Stats. & Regs. para. 32,514 at 33,114-15; 33,128-29.
---------------------------------------------------------------------------

    (1) A customer may, at any time before the termination date 
specified in its existing wholesale requirements contract,<SUP>870 
request the public utility to provide an estimate of the customer's 
stranded cost obligation based on the revenues lost formula contained 
in this Rule,<SUP>871 as of the date set forth in the customer's 
request. The customer should specify in its request, to the extent 
possible, pursuant to its rights under its power sales requirements 
contract with the seller,<SUP>872 the date on which the customer is 
considering substituting alternative generation for the requirements 
purchase and the amount of the substitute generation. Any remaining 
generation requirements to be purchased from the existing supplier 
after this date should be clearly indicated. The customer may seek 
further information on how the stranded cost charge would vary as a 
result of choosing different dates or different amounts of substitute 
purchases. The customer also should indicate its preferred payment 
method, such as a lump-sum payment, an amortization of a lump-sum 
payment, or a surcharge (such as monthly or annual) on the customer's 
transmission rate.
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    \870\ If the customer is a retail customer contemplating 
becoming a wholesale transmission customer, it may at any time 
request the public utility to provide an estimate of its stranded 
cost obligation.
    \871\ Because the formula reduces a customer's stranded cost 
obligation by the competitive market value of the capacity and 
associated energy that would be released by the customer's 
departure, we will not adopt the proposal in the Supplemental 
Stranded Cost NOPR to allow a potential departing customer to 
receive an estimate of the customer's ``maximum possible stranded 
cost exposure without mitigation.'' Requiring the utility to provide 
an estimate that reflects the competitive market value of the 
capacity and associated energy to be released will better enable the 
customer to assess its supply options.
    \872\ If the customer is a retail customer contemplating 
becoming a wholesale transmission customer, it should specify in its 
request, to the extent possible, the date on which the customer is 
considering becoming a wholesale transmission customer of the 
utility and the amount of generation, if any, it will continue to 
purchase from its existing supplier.
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    (2) The utility shall, within thirty days of receipt of the 
request, or other mutually agreed-upon period, provide the customer 
with an estimate of the customer's stranded cost obligation. The 
response shall include: (i) Estimates of RSE, CMVE, and L according to 
the revenues lost formula and based on the information supplied by the 
customer; (ii) supporting detail (including the underlying market 
analysis that forms the basis for the CMVE estimate) indicating how 
each element in the formula is derived to enable the customer to 
understand the basis for each element; (iii) a detailed rationale 
justifying the basis for the utility's reasonable expectation of 
continuing to serve the customer beyond the termination date in the 
contract; <SUP>873 (iv) an estimate of the amount of released capacity 
and the amount of associated energy that would result from the 
customer's departure, based on the information supplied by the 
customer, including detailed support for the amount of the released 
capacity and the amount of associated energy, and the market value of 
each, for each year of the reasonable expectation period, and how those 
amounts are consistent with the RSE and CMVE estimates; and (v) the 
utility's proposal for any contract amendment needed to implement the 
customer's payment of stranded costs (the proposed modification should 
also reflect the customer's chosen payment method).
---------------------------------------------------------------------------

    \873\ If the customer is a retail customer contemplating 
becoming a wholesale transmission customer, the utility should 
provide a detailed rationale justifying the basis for its reasonable 
expectation of continuing to provide the customer bundled retail 
service.
---------------------------------------------------------------------------

    (3) If the customer believes that: (i) The utility has failed to 
establish that it had a reasonable expectation of continuing to serve 
the customer beyond the contract term; <SUP>874 (ii) the proposed 
stranded cost charge (or any of the elements used to compute it) is 
unreasonable; (iii) the amount of released capacity and the amount of 
associated energy assumed to be sold is unreasonable; or (iv) the 
utility's proposal for any contract amendment needed to implement the 
customer's payment of stranded costs is unreasonable, the customer will 
have thirty days in which to respond to the utility explaining why it 
disagrees. The Commission expects parties to attempt to resolve any 
disputed issues.
---------------------------------------------------------------------------

    \874\ Subsection (i) above also would apply to a retail customer 
contemplating becoming a wholesale transmission customer if the 
customer believes that the utility has failed to establish that it 
had a reasonable expectation of continuing to provide the customer 
bundled retail service.
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    (4) If the parties are unable to resolve the matter using the 
procedures in (1)-(3) above, the customer may either: (a) File a 
petition for declaratory order, or a section 206 filing seeking to 
amend an existing requirements contract, to seek a Commission 
determination as to whether: (i) The utility has met the reasonable 
expectation standard; (ii) the proposed stranded cost charge satisfies 
the other evidentiary standards set forth in this Rule; (iii) the 
amount of released capacity and the amount of associated energy 
proposed by the utility is reasonable; or (iv) the utility's proposal 
for any contract amendment needed to implement the customer's payment 
of

[[Page 21661]]

stranded costs is reasonable; or (b) wait until the proposed stranded 
cost charge is filed by the utility under section 205 of the FPA, and 
contest it at that time.<SUP>875 In either case, because estimates of 
RSE and CMVE may change over time, any estimate of stranded costs 
provided by a utility to a customer will not be considered binding 
prior to any filing by either party with the Commission. However, any 
stranded cost estimate filed by the utility in a section 205 or 206 
proceeding, or in response to a petition for a declaratory order, shall 
be considered to be a binding estimate of the customer's maximum 
stranded cost obligation for purposes of litigation. Similarly, any 
estimate of stranded cost obligation filed by a customer in a petition 
for declaratory order or a section 205 or 206 proceeding shall be 
considered to be a binding estimate of the customer's minimum stranded 
cost obligation for purposes of litigation.<SUP>876 Estimates of 
stranded cost obligation that are filed by either party with the 
Commission shall include the information, including the supporting 
detail, identified in (2) above.
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    \875\ As discussed above, retail customers contemplating 
becoming wholesale transmission customers may use the same 
procedures. As also discussed above, customers under existing 
requirements contracts with public utilities have the option of 
making a filing under section 206 seeking to amend the contract to 
add an explicit stranded cost provision, without having to go 
through these procedures.
    \876\ Although estimates by the utility or the customer may be 
binding for purposes of litigation, this does not mean that the 
parties may not settle at any time on another amount.
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    (5) If a utility intends to file for stranded cost recovery from a 
customer through either a stranded cost amendment to its existing 
contract or a surcharge on transmission rates, it must file its 
stranded cost estimate no later than 120 days prior to the end of the 
customer's contract term. The filing shall include the information, 
including the supporting detail, set forth in (2) above. The customer, 
of course, may contest the contents of such a filing.<SUP>877
---------------------------------------------------------------------------

    \877\ A customer requesting a section 211 order for transmission 
services from a transmitting utility also may incur a stranded cost 
obligation. Any estimate of stranded cost obligation resulting from 
the requested transmission services should be included as part of 
the utility's good faith response to the customer's request for 
transmission services. See 18 CFR 2.20. Because the Commission will 
apply the revenues lost formula to any request for stranded cost 
recovery as a part of its determination of the appropriate charge 
for transmission services ordered in a section 211 proceeding, we 
encourage non-public utilities to use the revenues lost formula to 
estimate a customer's stranded cost obligation.
---------------------------------------------------------------------------

Conditions of the Marketing/Brokering Option
    A customer may choose to market or broker a portion or all of the 
released capacity and associated energy identified by the utility in 
its stranded cost estimate (or to contract with a marketing/brokering 
agent). Importantly, by exercising the marketing or brokering option, 
the customer does not relinquish its right to contest any aspect of the 
utility's stranded cost estimate, including whether the utility is 
entitled to recover stranded costs for the period that the customer has 
agreed to market or broker any released capacity and associated energy. 
To implement this option, a customer must inform the utility in writing 
of its decision no later than 30 days after the utility files its 
estimate of stranded costs for the customer with the Commission. Before 
marketing or brokering of the released capacity and associated energy 
can begin, the utility and customer must execute an agreement 
identifying, at a minimum, the amount of capacity and associated energy 
the customer is entitled to schedule, the price of capacity and 
associated energy, and the duration of the customer's marketing/
brokering of the released capacity and associated energy. Parties are 
encouraged to settle disputes over these and any other marketing/
brokering implementation issues. The negotiations should be guided by 
the principle that the utility must allow the customer to market or 
broker the released capacity and associated energy under terms and 
conditions comparable to those for a utility resale of the capacity and 
associated energy to a third party. If agreement over marketing or 
brokering cannot be reached, the parties may seek to include the issue 
as a part of a proceeding initiated at the Commission with respect to 
the utility's stranded cost estimate for the customer.<SUP>878 Upon 
issuance of an order resolving the disputed issues, the customer may 
reevaluate its decision to exercise the marketing/brokering option. The 
customer also may choose to market or broker any released capacity and 
associated energy not being marketed or brokered under an earlier 
agreement with the utility. A customer must notify the utility in 
writing within 30 days of issuance of the Commission's order resolving 
the disputed issues whether the customer will market or broker a 
portion or all of the capacity and energy associated with stranded 
costs allowed by the Commission.
---------------------------------------------------------------------------

    \878\ Because litigation of stranded costs may extend beyond the 
date of the customer's departure, the customer may also file a 
petition for a declaratory order requesting expedited resolution of 
marketing or brokering implementation issues.
---------------------------------------------------------------------------

Payment for Released Capacity and Associated Energy Under the Marketing 
Option
    If the customer chooses to market released capacity and associated 
energy, it shall pay the utility's estimate of the competitive market 
value of the capacity, or, if the marketing option is exercised after a 
Commission order, it shall pay the competitive market value amount as 
determined by Commission order. In addition, for all energy scheduled 
to be delivered, the customer shall pay the utility's average system 
variable costs. The customer may also choose to market only a portion 
of the released capacity and/or for a shorter period. In this 
situation, the customer will also pay the competitive market value for 
the released capacity plus the utility's average system energy costs. 
The customer's liability for payment of stranded costs is unaffected by 
its decision to market released capacity and associated energy.<SUP>879 
In addition, to the extent that the customer chooses to market a 
portion or all of the capacity alleged by the utility to be stranded, a 
final determination with respect to the customer's stranded cost 
obligation will not affect any prior marketing agreement.
---------------------------------------------------------------------------

    \879\ If the customer can market the released capacity and 
associated energy for a higher price than the customer paid for it, 
the customer effectively reduces its stranded cost obligation, i.e., 
the incremental revenue received offsets a portion of the customer's 
stranded cost payment to the utility.
---------------------------------------------------------------------------

Payment for Stranded Costs Under the Brokering Option
    If the customer chooses to broker a portion or all of the released 
capacity and associated energy, any revenue received from such 
brokering activity shall be used to offset the utility's estimate of 
the competitive market value of the brokered capacity and associated 
energy.<SUP>880 Once a brokering agreement is executed between the 
customer and the utility, if the customer's brokering efforts fail to 
produce a buyer within 60 days of the date of that agreement, the 
customer shall relinquish all rights to broker the released capacity 
and associated energy and will pay stranded costs as determined by the 
formula.
---------------------------------------------------------------------------

    \880\ For example, if the customer brokers any released capacity 
and associated energy for a higher price than the utility's 
estimated competitive market value of that capacity and energy, the 
difference between the utility's estimate and the brokered price 
will be used to increase the utility's CMVE component of the 
stranded cost calculation, thereby reducing the customer's stranded 
cost obligation.

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[[Page 21662]]

10. Stranded Costs in the Context of Voluntary Restructuring
    In the Supplemental Stranded Cost NOPR, we noted that the 
functional unbundling of wholesale services does not require corporate 
unbundling (such as disposition of assets to a non-affiliate, or 
establishing a separate corporate affiliate to manage a utility's 
transmission assets). At the same time, we indicated that some 
utilities may ultimately choose some form of corporate 
unbundling.<SUP>881 We reaffirm in this Final Rule that we are willing 
to consider case-specific proposals for dealing with stranded costs in 
the context of any restructuring proceedings that may be instituted by 
individual utilities.
---------------------------------------------------------------------------

    \881\ FERC Stats. & Regs. para.32,514 at 33,132.
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11. Accounting Treatment for Stranded Costs Comments
    A number of commenters ask the Commission to provide accounting 
treatment guidance as part of its procedures for implementing its 
policies on stranded costs and their recovery.<SUP>882
---------------------------------------------------------------------------

    \882\ See, e.g., EEI, NSP, LILCO, Central Hudson, Deloitte & 
Touche, Centerior.
---------------------------------------------------------------------------

    NSP states that the Commission will need to provide appropriate 
accounting guidance for the final stranded cost recovery methodology, 
including accounting for any portion of stranded cost recovery 
representing capital costs, the effect of any interperiod differences 
between the stranded cost calculations and the authorized recovery 
period, and the effects of differences between book and income 
implications of the stranded cost recovery mechanism. NSP also asserts 
that, in addressing the accounting implications of the final rule, the 
Commission must consider the requirements of the Financial Accounting 
Standards Board (FASB) Statement of Financial Accounting Standards No. 
121, ``Impairment of Long-Lived Assets'' (SFAS No 121).
    NASUCA states that one of the Commission's stated goals in 
providing stranded cost recovery is to protect against cost shifting. 
NASUCA argues that the Commission should adopt an accounting rule that 
assures that any federal resolution of wholesale stranded costs does 
not impose any cost shifting to captive customers.
    EEI and Centerior argue that the Uniform System of Accounts as 
presently configured does not support the Commission's proposed 
policies on stranded cost recovery. Further, EEI states that even with 
the revenues lost approach, which EEI supports, utilities will still 
have to account for their assets on a class-of-asset by class-of-asset 
basis. EEI argues that this is necessary to ensure that the costs of 
the assets are expensed in the proper accounting period. EEI states 
that one of the basic principles of financial accounting is that 
expenses should be matched with the related revenues.
Commission Conclusion
    As discussed in Section IV.J.3, this rule adopts a direct 
assignment approach for the recovery of stranded costs from departing 
generation customers. Under the revenues lost approach, stranded cost 
recovery is limited to the departing generation customer's contribution 
to fixed costs that the utility otherwise would not recover because of 
the customer's departure.
    We recognize that there are certain similarities between the 
financial reporting objectives of SFAS No. 121 and the determination of 
stranded costs. However, there are also important differences between 
SFAS No. 121 and our approach to stranded costs. The revenues lost 
approach does not attempt to identify specific uneconomic assets and is 
not limited to only long-lived assets. Instead, it uses a formulary 
methodology that encompasses all fixed costs of providing service.
    From a financial accounting standpoint, our approach to stranded 
costs creates the potential for a mismatch between the periods in which 
the stranded costs are charged to expense and any revenues provided for 
their recovery are included in net income determinations. This is 
because the earning process entitling a utility to the benefits of 
stranded cost recovery and thereby requiring the recognition of revenue 
may be completed prior to the time that the stranded costs must be 
charged to expense under generally accepted cost recognition criteria. 
This circumstance in a cost-based regulated environment creates the 
undesirable potential for double recovery of the same cost, cost 
shifting, and inappropriate financial reporting.
    In order to avoid this potential, utilities shall not recognize 
revenues intended to provide for recovery of stranded costs from 
wholesale requirements customers prior to the time that the stranded 
costs are charged to expense, unless prior Commission approval to do so 
has been obtained. Absent Commission approval, utilities shall defer 
such amounts in Account 253, Other Deferred Credits, and amortize them 
to Account 456, Other Electric Revenues, consistent with the period the 
related costs are charged to expense. Also, we will require a utility 
to submit its proposed accounting for stranded costs and related 
revenues as part of its rate filing requesting recovery of stranded 
costs under section 205 of the FPA.
12. Definitions, Application, and Summary
    In the Supplemental Stranded Cost NOPR, the Commission described 
proposed amendments to our regulations to establish filing requirements 
for public utilities and transmitting utilities that seek stranded cost 
recovery. We proposed to define ``wholesale stranded cost'' as ``any 
legitimate, prudent and verifiable cost incurred by a public utility or 
a transmitting utility to provide service to: (i) A wholesale 
requirements customer that subsequently becomes, in whole or in part, 
an unbundled wholesale transmission services customer of such public 
utility or transmitting utility, or (ii) a retail customer, or a newly 
created wholesale power sales customer, that subsequently becomes, in 
whole or in part, an unbundled wholesale transmission services customer 
of such public utility or transmitting utility.'' We sought comments on 
whether this definition should encompass the situation where a 
wholesale requirements customer ceases to purchase power from the 
utility that had been making wholesale requirements sales to such 
customer without becoming an unbundled transmission services customer 
of that utility.<SUP>883
---------------------------------------------------------------------------

    \883\ FERC Stats. & Regs. para. 32,514 at 33,115.
---------------------------------------------------------------------------

Comments
    We received numerous comments both supporting and opposing 
revisions to the proposed definition of wholesale stranded 
costs.<SUP>884 Several commenters oppose broadening the definition to 
include costs stranded by customers that do not become unbundled 
transmission service customers of the former supplier.<SUP>885 For 
example, EGA argues that the loss of an industrial customer that 
chooses to self-generate or the loss of a requirements customer as a 
result of a newly-created municipal system that interconnects with a 
transmitting utility that is not the customer's former supplier could 
have happened at any time. EGA states that revenues lost as a result of 
either

[[Page 21663]]

scenario have nothing to do with regulatory reforms and should not be 
considered ``stranded'' costs.
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    \884\ EEI asks the Commission to expand the definition of 
stranded costs to account for the case where the Commission has 
proposed to address purely retail stranded costs (that is, where a 
state regulatory authority does not have authority to address 
stranded costs at the time that retail wheeling is required). 
However, the regulations will contain a definition of ``retail 
stranded costs'' to account for this case. See Sec. 35.26(b)(5) of 
the Final Rule.
    \885\ E.g., EGA, Direct Service Industries, Memphis.
---------------------------------------------------------------------------

    Other commenters disagree.<SUP>886 Puget asserts that permitting 
departing generation customers to avoid paying stranded costs if they 
do not take unbundled transmission from their former suppliers would 
create an incentive for departing customers (or their new electric 
suppliers) to build unneeded and uneconomic new transmission lines. 
Puget says that it also could be a disincentive to engage in regional 
transmission planning and coordination because the existence of new 
transmission facilities needed to achieve regional reliability and 
efficiency may increase the likelihood that departing generation 
customers could import their power supplies over those new facilities 
and avoid paying the utility's stranded costs.<SUP>887
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    \886\ E.g., Atlantic City, Carolina P&L, Consumers Power, 
Minnesota Power, Knoxville, Alma, Florida Power Corp, El Paso, 
Central Louisiana, Southern, WP&L, FL Com, Utility Investors 
Analysts, Florida Power Corp, El Paso, Central Louisiana, TDU 
Systems, NW Conservation Act Coalition, Puget, NU, EEI.
    \887\ Several commenters also ask the Commission to expand the 
definition of wholesale stranded cost to include the situation where 
a wholesale supplier loses wholesale load as a result of a 
requirements customer's loss of retail load because of retail 
wheeling, municipalization or retail taps from another utility's 
system. E.g., Utilities For Improved Transition, Montaup, SC Public 
Service Authority. In addition, a number of commenters ask the 
Commission to treat the members of a single G&T cooperative system 
as a single economic unit and to revise the definition of wholesale 
stranded costs to allow a transmitting G&T cooperative (the arm of 
the cooperative system that provides the transmission) to recover 
the costs stranded when a retail customer of one of its member 
distribution cooperatives takes advantage of the open access 
environment by becoming a wholesale entity. E.g., Big Rivers EC, 
NRECA, Tri-County EC, TDU Systems.
---------------------------------------------------------------------------

    Some of these commenters propose using an exit fee to collect 
stranded costs from a customer that does not take unbundled 
transmission from its former supplier, since a transmission surcharge 
is not available in this circumstance.<SUP>888 Other methods proposed 
include: (1) Conditioning Commission approval of the transmission rates 
or wholesale power rates charged by the transmission-providing utility 
upon the inclusion of a surcharge to recover the former supplier's 
stranded costs or upon the transmission-providing utility otherwise 
agreeing to guarantee the payment of the stranded costs or act as 
billing agent for the former supplier; <SUP>889 (2) authorizing the 
former supplier to levy a stranded cost charge on the transmission-
providing utility (if that utility is interconnected with and has 
transmission contracts with the former supplier); (3) if a retail 
customer becomes annexed to a municipal utility and does not take 
unbundled transmission services from its former supplier, permitting 
recovery of stranded costs from the municipal utility through its 
jurisdictional transmission rates; or (4) requiring a public utility 
providing transmission service for a customer that has left its former 
supplier to agree, as a condition to recovery of its own stranded 
costs, to ensure the payment of any stranded costs incurred by the 
former supplier.<SUP>890
---------------------------------------------------------------------------

    \888\ E.g., Carolina P&L, NU, Florida Power Corp, PSNM, 
Southern, Mountain States Petroleum Assoc, FL Com.
    \889\ In its reply comments, Memphis Light objects to the 
proposal that the Commission condition approval of all new power 
contracts for those customers that leave a utility's system without 
using the transmission services of the original utility upon the 
inclusion of a provision to recover the stranded cost for the 
previous power supplier. It argues that this proposal could result 
in nonrecovery from some customers because wholesale customers faced 
with such a provision would pursue non-jurisdictional contracts and/
or generate within the confines of their own systems.
    \890\ E.g., EEI, El Paso, NU, Atlantic City, PG&E, Coalition for 
Economic Competition, NW Conservation Act Coalition, Puget, NRECA, 
Cajun, East Kentucky, FL Com, Associated EC, Utilities For Improved 
Transition, TDU Systems, TVA.
---------------------------------------------------------------------------

    Commenters also address the use of the terms ``legitimate, prudent, 
and verifiable'' in the definitions of wholesale and retail stranded 
costs. Several commenters suggest that the Commission's use of the word 
``prudent'' could imply that utilities have to relitigate the prudence 
of costs that the Commission and state commissions have already 
approved; these commenters believe that utilities should not have to 
relitigate prudence.<SUP>891 Some argue that once a regulatory agency 
(state or federal) has allowed recovery of the costs in rates, or 
promised future recovery, utilities should not have to undergo a second 
regulatory review to recover those costs if they become 
stranded.<SUP>892
---------------------------------------------------------------------------

    \891\ E.g., EEI, NSP, Arizona, United Illuminating, Entergy, 
SCG&E, PECO, NRECA.
    \892\ E.g., EEI, Centerior, NSP, SCG&E, PECO, Tucson Power, 
Arizona.
---------------------------------------------------------------------------

    Commenters recommend that the Commission address this situation by: 
Striking the word ``prudent'' from the definition or specifying that 
the prudence requirement is satisfied by previous regulatory 
authorization; <SUP>893 dropping the terms ``legitimate, prudent and 
verifiable'' from the definition and using instead ``allowed,'' 
``accepted,'' or ``allowable''; <SUP>894 or adding ``or approved by 
state commission'' after the words ``legitimate, prudent and 
verifiable'' in the definitions of both wholesale and retail stranded 
costs.<SUP>895
---------------------------------------------------------------------------

    \893\ E.g., PECO, Entergy.
    \894\ E.g., EEI, SCG&E, Carolina P&L.
    \895\ E.g., Atlantic City. EEI also proposes that at the time of 
filing of a stranded cost recovery charge (whether as an amendment 
to a contract or a surcharge to a transmission rate), the Commission 
limit its inquiry to the issue of the stranded cost charge rather 
than allowing all aspects of a rate or contract to be opened up. EEI 
states that this is what the Commission did in the natural gas 
context, where it permitted limited rate filing cases under section 
4 of the NGA.
---------------------------------------------------------------------------

    Other commenters oppose these proposals, suggesting that the 
prudence analysis for stranded cost purposes may involve questions of 
prudence different from those that arise in a ratemaking 
context.<SUP>896 DE Muni objects that replacing ``legitimate, prudent 
and verifiable'' with ``allowed, accepted, or allowable'' could enable 
a utility to recover costs that the utility may not be able to prove 
were prudent, legitimate, and verifiable.
---------------------------------------------------------------------------

    \896\ E.g., Alcoa, Cleveland.
---------------------------------------------------------------------------

    A number of commenters submit that ``legitimate, prudent and 
verifiable'' costs should not include the costs of uneconomic plants or 
costs resulting from utilities' independent business decisions (as 
distinguished from costs the utility was forced by regulation to 
incur).<SUP>897
---------------------------------------------------------------------------

    \897\ E.g., Mountain States Petroleum Assoc, Caparo, Torco.
---------------------------------------------------------------------------

    Several other commenters address the rule's application to 
wholesale requirements customers.<SUP>898 AMP-Ohio asks the Commission 
to clarify that the reference to ``wholesale requirements customer'' is 
to a full requirements customer, not a partial requirements customer. 
It says that no transmission provider should have any reasonable 
expectation of continuing to serve loads of partial requirements 
customers. TAPS suggests that references to ``new wholesale 
requirements contract'' in proposed Sec. 35.26(c)(1) should be 
conformed to the defined term ``new contract'' in proposed 
Sec. 35.26(b)(7). In addition, it suggests that the Commission clarify 
the regulations by clearly foreclosing stranded cost claims for ``new 
contracts'' without express exit fees, instead of simply failing to 
provide for such recovery.
---------------------------------------------------------------------------

    \898\ E.g., AMP-Ohio, PA Munis, TAPS.
---------------------------------------------------------------------------

Commission Conclusion
    We will retain the definition of ``wholesale stranded cost'' 
proposed in the Supplemental Stranded Cost NOPR.<SUP>899 We believe it 
would be inappropriate to expand the definition to include the 
situation where a

[[Page 21664]]

wholesale requirements customer <SUP>900 (or a retail-turned-wholesale 
customer) ceases to purchase power from the utility without using the 
transmission services of that utility.<SUP>901 Any costs that the 
utility might incur as a result of the loss of the requirements 
customer in this scenario would be outside the scope of this Rule. The 
premise of this Rule is that, where a customer uses the new open access 
to obtain power from a new generation supplier, the customer must pay 
the costs that were incurred on its behalf under the prior regulatory 
regime. However, if a customer leaves its utility supplier by 
exercising power supply options (such as access to another utility's 
transmission system or self-generation) that do not rely on access to 
the former seller's transmission, there is no nexus to the new open 
access rules.<SUP>902 If a customer is able to obtain power from a new 
supplier by using the transmission system of another utility, it is 
likely that the customer could have made these arrangements in the 
absence of the new open access rules. The new transmission provider 
would have had little incentive to deny transmission services to the 
customer in order to protect an existing power supply arrangement, 
since it was not the customer's power supplier in the first place. 
Indeed, it is likely that the neighboring utility would have a positive 
incentive to provide the transmission service in order to increase its 
revenues. This incentive is unchanged by open access transmission.
---------------------------------------------------------------------------

    \899\ For the reasons articulated below, we accordingly will 
reject the various revisions to the definition that were proposed by 
commenters.
    \900\ ``Wholesale requirements contract'' is defined as ``a 
contract under which a public utility or transmitting utility 
provides any portion of a customer's bundled wholesale power 
requirements'' (emphasis added). Thus, a ``wholesale requirements 
customer'' for purposes of the Rule can be either a full or a 
partial requirements customer. We reject AMP-Ohio's suggestion that 
the Commission make a blanket finding that a utility could not have 
had a reasonable expectation of continuing to serve a partial 
requirements customer. For example, a partial requirements customer 
may have met part of its needs with its own generation but because 
it could not build more of its own generation locally it had to 
depend on the utility for the remainder of its needs in the absence 
of the new open access. Also, a partial requirements customer may 
have been able to reach alternative suppliers for only a portion of 
its requirements due to transmission constraints. If this were the 
case, the partial requirements supplier may well have had a 
reasonable expectation of continuing to serve the balance of the 
customer's load.
    \901\ The definition of ``retail stranded cost'' contains a 
similar requirement (i.e., the retail customer must become, in whole 
or in part, an unbundled retail transmission services customer of 
the public utility or transmitting utility from which the customer 
previously received bundled retail services). We will retain it for 
the same reasons discussed above.
    \902\ As we have said, this Rule is not intended to insulate a 
utility from the normal risks of competition.
---------------------------------------------------------------------------

    Some commenters have asked us to eliminate the term ``prudent'' 
from the definition of stranded costs. We will not do so; we will 
retain the requirement that stranded costs be ``legitimate, prudent and 
verifiable.'' A determination that a utility had a reasonable 
expectation of continuing to serve a customer would not, in all 
circumstances, mean that costs incurred by the utility were prudent. 
Prudence of costs, depending upon the facts in a specific case, may 
include different things: e.g., prudence in operation and maintenance 
of a plant; prudence in continuing to own a plant when cheaper 
alternatives become available; prudence in entering into purchased 
power contracts, or continuing such contracts when buy-outs or buy-
downs of the contracts would result in savings. The Commission 
therefore cannot make a blanket assumption that all claimed stranded 
costs will have been prudently incurred. However, we clarify that we do 
not intend to relitigate the prudence of costs previously 
recovered.<SUP>903
---------------------------------------------------------------------------

    \903\ As the Commission has previously indicated, however, in 
the case of formula rates, approval of a formula rate constitutes 
approval of the formula, and not the underlying costs. See, e.g., 
New England Power Company, et al., 72 FERC para.61,148 at 61,761 
(1995); Boston Edison Company, Opinion No. 376, 61 FERC para.61,026 
at 61,145 (1992).
---------------------------------------------------------------------------

    Thus, this Rule will permit a public utility or transmitting 
utility to seek recovery of wholesale stranded costs as follows. First, 
for stranded costs associated with new wholesale requirements contracts 
(that is, any wholesale requirements contract executed after July 11, 
1994), the regulations will allow recovery of stranded costs only if 
the contract contains an explicit stranded cost provision that permits 
recovery. By ``explicit stranded cost provision'' we mean a provision 
that identifies the specific amount of stranded cost liability of the 
customer(s) and a specific method for calculating the stranded cost 
charge or rate.. We clarify that provisions in requirements contracts 
executed after July 11, 1994 but before the date on which this Final 
Rule is published in the Federal Register that explicitly reserved the 
right to stranded cost recovery pending the outcome of this Rule will 
be deemed ``explicit stranded cost provisions.'' However, provisions in 
requirements contracts executed after July 11, 1994 but before the date 
on which this Final Rule is published in the Federal Register that 
postpone the issue of stranded cost recovery without specifically 
providing for recovery of stranded costs will not be considered 
``explicit stranded cost provisions.''
    Second, for existing wholesale requirements contracts (that is, any 
wholesale requirements contract executed on or before July 11, 1994), a 
utility may not recover stranded costs if recovery is explicitly 
prohibited by the contract (including associated settlements) or by any 
power sales or transmission tariff on file with the Commission.
    Third, for existing wholesale requirements contracts that do not 
address stranded costs through exit fee or other explicit stranded cost 
provisions, a public utility may seek recovery of stranded costs only 
as follows: (1) If the parties to the existing contract renegotiate the 
contract and file a mutually agreeable amendment dealing with stranded 
costs, and the Commission accepts or approves the amendment; (2) if 
either or both parties seeks an amendment to the existing contract 
under sections 205 or 206 of the FPA, before the contract expires, and 
the Commission accepts or approves an amendment permitting stranded 
cost recovery; or (3) if the public utility files a request, before the 
contract expires, to recover stranded costs through a departing 
generation customer's transmission rates under FPA sections 205-206 or 
211-212.
    Fourth, if the selling utility under an existing wholesale 
requirements contract is a transmitting utility but not also a public 
utility, and the contract does not address stranded costs through an 
explicit exit fee or other stranded cost provision, the transmitting 
utility may seek to recover stranded costs through a surcharge to a 
departing generation customer's transmission rates under FPA sections 
211-212. Such utility may not seek recovery of stranded costs through a 
section 211-212 transmission rate if the existing requirements contract 
does contain an explicit exit fee or other stranded cost provision.
    Fifth, for a retail-turned-wholesale customer, a public utility or 
transmitting utility may file a request to recover stranded costs from 
the newly-created wholesale customer through that customer's 
transmission rates under FPA sections 205-206 or 211-212.
    Sixth, for customers who obtain retail wheeling, a public utility 
or transmitting utility may seek recovery through Commission-
jurisdictional transmission rates only if the state regulatory 
authority had no authority under state law to address stranded costs 
when retail wheeling is required.

[[Page 21665]]

K. Other

1. Information Reporting Requirements for Public Utilities
    In the NOPR, the Commission did not propose any changes to its 
information filing requirements for public utilities.
Comments
    Many IOUs argue that the current information filing requirements 
competitively disadvantage traditional public utilities and unfairly 
benefit sellers, such as power marketers, that are not required to 
provide comparable information.<SUP>904 They urge the Commission to 
eliminate the requirement for public disclosure of competitively 
sensitive, proprietary, or otherwise confidential Form No. 1 data. They 
contend that requiring such disclosure only from traditional public 
utilities harms such public utilities and compromises the development 
of efficient competition. Illinois Power asks the Commission to review 
all information that utilities must file, including EIA 860, EIA 767, 
and FERC Form No. 715.
---------------------------------------------------------------------------

    \904\ E.g., NIPSCO, Illinois Power, Centerior, Ohio Edison, EEI.
---------------------------------------------------------------------------

    A number of commenters believe that some type of information 
requirement must also be placed on non-public utility entities.<SUP>905 
PacifiCorp suggests that the Commission should require transmitting 
utilities that do not file a Form No. 1 to file similar information 
annually with the Commission. Ohio Edison asserts that the Commission 
should extend its use of the reciprocity concept to require the filing 
of operating data with the Commission. Further, if non-public utility 
entities are not required to disclose certain information, Ohio Edison 
asserts that all public utilities that have received approval to sell 
power at market-based rates, including traditional utilities, should 
also be free from having to disclose such information.
---------------------------------------------------------------------------

    \905\ E.g., NSP, Ohio Edison.
---------------------------------------------------------------------------

    Arizona argues that enforcing comparability vis-a-vis non-public 
utility transmitting utilities would seem to invite jurisdictional 
challenge. Thus, it would support legislation to broaden the 
Commission's jurisdiction.<SUP>906
---------------------------------------------------------------------------

    \906\ See also Minnesota P&L.
---------------------------------------------------------------------------

Commission Conclusion
    We will not adopt the suggestion made by a number of commenters 
that we now eliminate the public disclosure of allegedly competitively 
sensitive, proprietary, or otherwise confidential data submitted to the 
Commission on Form No. 1, as well as on other Commission forms. The 
information that we collect from public utilities is necessary to carry 
out our jurisdictional responsibilities and is used, among other 
things, to evaluate the reasonableness of cost-based rates subject to 
our jurisdiction and the operation of power markets.<SUP>907 Moreover, 
as we explained in ConEd,

    \907\ See, e.g., Consolidated Edison Company of New York, Inc. 
and Central Hudson Gas & Electric Corp., 72 FERC para. 61,184 at 
61,891 (1995) (ConEd).
---------------------------------------------------------------------------

    [R]eports required to be submitted by Commission rule and 
necessary for the Commission's jurisdictional activities are 
considered public information. 18 CFR 388.106. In addition, the 
Commission has long required jurisdictional utilities to submit Form 
1 data on a form that states on its cover that the Commission does 
not consider the material to be confidential.<SUP>908

    \908\ 72 FERC at 61,891.
---------------------------------------------------------------------------

    We are sensitive to the lack of symmetry in the generation 
information we require from traditional public utilities, particularly 
those that have market-based rate authority, and the generation 
information we require from other public utilities (e.g., public 
utility marketers) authorized to sell at market-based rates.<SUP>909 
However, the record in this proceeding is insufficiently developed for 
us to make and support a well-informed decision requiring a different 
reporting scheme, particularly given the industry's current rapid pace 
of change. Also, we are not persuaded that the burdens borne by 
traditional public utilities (primarily annual reports submitted months 
after-the-fact) are impairing the competitiveness of these utilities so 
much that we must act hastily now, instead of deferring a decision to a 
more appropriate proceeding. Moreover, we are required to regulate the 
rates of public utilities and, although we are moving toward greater 
reliance on market-based generation rates, we continue to regulate 
generation on a cost basis for most traditional public utilities, 
particularly rates for sales from existing generation. To assure that 
these rates are just and reasonable, we, as well as the customers of 
public utilities, need the more detailed information our regulations 
require public utilities to submit.
---------------------------------------------------------------------------

    \909\ We note that public utility marketers are required to file 
quarterly transaction reports so that the Commission can monitor the 
reasonableness of their charges and their ability to exercise market 
power. See Heartland Energy Services, Inc., 68 FERC para. 61,223 at 
62,065-66 (1994). Unlike traditional public utilities, marketers do 
not use cost-based rates. Approval of the generation rates of non-
jurisdictional transmitting utilities is not subject to our 
jurisdiction.
---------------------------------------------------------------------------

    Accordingly, at this time, we will not change our information 
reporting requirements. As the industry becomes more competitive, we 
will monitor our reporting requirements to make sure that they are 
needed, fair to all segments of the industry, and consistent with the 
workings of a competitive environment.
2. Small Utilities
    In the NOPR, we did not address whether special provisions were 
needed for small public utilities and small transmission customers 
because of the possible burden of unbundling, open access tariffs, and 
the OASIS requirement.
Comments
    A number of commenters assert that the unbundling requirement poses 
significant problems for smaller public utilities and that small 
utilities should not be subject to the same requirements as larger 
utilities.<SUP>910 St. Joseph notes that in small utilities one system 
operator typically runs the system operations center. Functional 
unbundling, it asserts, would require the addition of another operator 
for each shift at great cost to the small utility. Central Hudson 
estimates that unbundling would result in an approximately 10 percent 
increase in the wholesale price, putting small utilities at a 
competitive disadvantage.
---------------------------------------------------------------------------

    \910\ E.g., Central Hudson, Central Illinois Light, CVPSC, 
Citizens Utilities, East Kentucky, IPALCO, Montana-Dakota Utilities, 
Seattle, St. Joseph, Tallahassee, VT DPS.
---------------------------------------------------------------------------

    Several commenters assert that many small utilities enjoy little or 
no transmission market power because their systems tend to be in 
parallel with large systems and are bypassed as a result. They say that 
customers prefer to deal with one large regional utility rather than 
pay pancaked transmission rates for service through two or more small 
utilities.
    Citizens Utilities argues that some systems are radial spurs of 
much larger systems and merely serve to link points of interconnection. 
It claims that a network tariff is not applicable in such a case and 
that it is unlikely that third parties would request service over such 
small or isolated systems. It recommends that if a utility is basically 
a spur system and faces little present or future demand for third-party 
service, the Commission should either relax the open access 
requirements or defer them until a section 211 request is submitted.
    East Kentucky proposes that the Commission exempt not-for-profit 
utilities from the requirement to separate the functions related to 
operation and marketing, since small G&T cooperatives exist solely to 
serve the needs of their owner-member distribution cooperatives.

[[Page 21666]]

    VT DPS suggests that waiver of marketing and transmission personnel 
separation requirements may be appropriate in the case of smaller 
utilities that do not operate control areas. St. Joseph proposes that 
the Commission establish a threshold level based on system demand of 
1000 MW, below which unbundling of wholesale transmission functions 
from other dispatching functions would not be required. Alternatively, 
St. Joseph proposes an exemption from unbundling where the utility can 
demonstrate that it has no market power and that unbundling would not 
materially improve the level of competition in the generating market.
    Central Hudson believes that the Commission should allow the 
development of a short form tariff or else defer the functional 
unbundling requirement for smaller utilities and use the section 211 
process in the interim to provide flexibility for these utilities.
    Oregon Trail EC, a small rural electric, public utility 
cooperative, requests that the Commission revise proposed Sec. 35.28 of 
its regulations to provide that the generic open access transmission 
requirements apply only to public utilities that operate facilities 
used for the transmission of electric energy in interstate commerce. It 
explains that it owns one transmission line that it leases to BPA, 
which operates the line as part of its integrated transmission network. 
Thus, Oregon Trail EC states that it cannot meet the requirements of 
the open access rule. It also points out that the Commission exempted 
Oregon Trail EC and other similarly situated utilities from the 
transmission reporting requirements of Form No. 715 because they did 
not engage in transmission planning.
    ALCOA suggests that the default tariffs for smaller utilities with 
transmission systems unlikely to be used by others should not become 
effective automatically. Rather, the default tariffs should become 
effective only when service is requested. Citizens Utilities suggests 
that relaxed tariff requirements be established for small utilities 
with insignificant demand for transmission service.
    BG&E believes that a utility using its system on a network basis 
for economic dispatch should not be required to file a network service 
tariff if there is no customer to take the service. It suggests that if 
municipalization were to occur, the Commission could then require the 
utility to file, within 60 days, a network service tariff to serve the 
new municipal.
Commission Conclusion
    We are sympathetic to the array of concerns raised by small public 
utilities and small transmission customers. The regulations we are 
adopting include waiver provisions under which public utilities and 
transmission customers, and non-public utility entities seeking 
exemption from the reciprocity condition, may file requests for waivers 
from all or part of the Commission's regulations or for special 
treatment.<SUP>911 However, it is difficult to imagine any circumstance 
that would justify waiving the requirements of this Rule for any public 
utility that is also a control area operator.
---------------------------------------------------------------------------

    \911\ Non-public utility entities could request that the 
Commission find that they can satisfy the reciprocity condition 
without meeting all or some of the requirements that public 
utilities must meet. The requests could encompass a wide variety of 
circumstances. For example, a non-public utility could agree to 
offer comparable transmission services but not wish to have an OASIS 
or separate transmission personnel from wholesale marketing 
personnel due to the cost of doing so. The Commission could find 
that the entity nevertheless satisfied the reciprocity condition.
---------------------------------------------------------------------------

    We recognize, for example, that it might be a financial burden on 
small public utilities to unbundle generation from transmission, follow 
standards of conduct that separate transmission personnel from 
wholesale marketing personnel, and maintain an OASIS. These 
requirements may be particularly burdensome for small public utilities 
that own no generation and buy at wholesale on a radial transmission 
line from another utility's grid. In addition, if a small public 
utility's service territory is part of another utility's control area, 
the small public utility should be permitted to make a showing that it 
should be exempt from all or some of the Rule. In this circumstance, we 
will consider granting a waiver if the utility can show that: (1) It 
does not own transmission facilities, (2) it has turned control of its 
facilities over to someone else (such as the control area operator) who 
complies with the rule as its agent, or (3) no one is likely to ask to 
use its facilities (e.g., because they are radial lines), and it 
commits to file an open access tariff within 60 days of a request to 
use its facilities and to comply with the rule in all other ways.
    Because the possible scenarios under which small entities may seek 
waivers from the Final Rule are diverse, they are not susceptible to 
resolution on a generic basis and we will require applications and 
fact-specific determinations in each instance. We note here that any 
waivers that we may grant depend upon the facts presented in each case. 
If the circumstances that give rise to the exemption change, the waiver 
may no longer be appropriate. For example, a radial line today could 
very easily become part of a network tomorrow and a portion of a grid 
that no one is interested in using today could become an important 
transmission link tomorrow, especially if retail access is allowed.
    In addition, we will apply the same standards to any entity seeking 
a waiver. This includes public utilities seeking waiver of some or all 
of the requirements of the rule, as well as non-public utilities 
seeking waiver of the reciprocity provisions contained in the pro forma 
open access tariff. Thus, we would not apply the open access 
reciprocity provision to small non-public utilities that are not 
control area operators and either do not own or control transmission or 
have transmission that no one is likely to ask to use. They would not 
have to provide an open access tariff, establish an OASIS, or separate 
operators of transmission from wholesale purchasers in order to satisfy 
the reciprocity condition for obtaining transmission service. However, 
they will have to apply for this waiver and demonstrate that they 
qualify for the waiver.
3. Regional Transmission Groups
    In the NOPR, we again expressed our support for the voluntary 
formation of regional transmission groups (RTGs).<SUP>912 We also 
explained that the potential benefits of RTGs would not be undermined 
by the rules proposed in the NOPR.
---------------------------------------------------------------------------

    \912\ FERC Stats. & Regs. para. 32,514 at 33,095.
---------------------------------------------------------------------------

a. Incentives for RTGs to Form and Resolve Regional Transmission Issues
Comments
    A number of commenters urge the Commission to provide incentives 
for the formation of RTGs within two years of the adoption of the final 
rule.<SUP>913 Several commenters argue that the Commission should 
encourage a regional approach to transmission issues by expanding the 
role of RTGs.<SUP>914 Com Ed also claims that contract path pricing 
problems probably will need to be resolved at the regional level.
---------------------------------------------------------------------------

    \913\ E.g., AMP-Ohio, Missouri Joint Commission, MT Com, WEPCO, 
Nebraska Public Power District, Texas-New Mexico.
    \914\ E.g., WEPCO, Portland, WA Com.
---------------------------------------------------------------------------

    Sierra Pacific Power, which views open access as the major benefit 
of RTGs, questions the need to provide incentives for the development 
of RTGs once open access is implemented. However, it does see that RTGs 
may help promote open access with non-public utility entities, who have 
shown

[[Page 21667]]

an increased interest in joining RTGs. American Wind and MT Com request 
that the Commission adopt policies that will encourage a close working 
relationship between RTGs and state authorities.
    Otter Tail contends that the final Rule should stop short of 
establishing any conditions on the formation, governance, or functions 
of RTGs, arguing that such issues are complex and outside the scope of 
the NOPR. ALCOA and Missouri Joint Commission encourage the Commission 
to make certain that its policy regarding RTGs is not implemented in a 
manner that conflicts with the new open access regime.
Commission Conclusion
    We continue to support the development of RTGs and encourage the 
formation of regional tariffs.<SUP>915 In our Policy Statement 
Regarding Regional Transmission Groups, we first explained our support 
for such voluntary associations.<SUP>916 We again explained our support 
in the NOPR:


    \915\ If an RTG is not a corporate person, each utility member 
of the RTG may file the same or complementary tariffs.
    \916\ 58 FR 41626 (August 5, 1993), FERC Stats. & Regs., 
Regulations Preambles para. 30,976 (RTG Policy Statement).
---------------------------------------------------------------------------

    We believe that RTGs can speed the development of competitive 
markets, increase the efficiency of the operation of transmission 
systems, provide a framework for coordination of regional planning 
of the system and reduce the administrative burden on the Commission 
and on members of RTGs by providing for voluntary resolution of 
disputes.<SUP>917


    \917\ FERC Stats. & Regs. para. 32,514 at 33,095.
---------------------------------------------------------------------------

    To further encourage the development of RTGs, we will accept 
regional open access transmission tariffs developed by RTGs that are 
consistent with the objectives of this Rule. This should make it easier 
for all parties in a region to coordinate their activities.
b. Deference to RTGs To Develop Regional Tariffs and Prices
Comments
    A number of commenters urge the Commission to give considerable 
deference to RTGs on such issues as the formulation of pricing methods 
and RTG member duties.<SUP>918 Nebraska Public Power District requests 
that the Commission consider permitting a megawatt-mile pricing 
mechanism for MAPP. NWRTA urges the Commission to define clearly how 
much deference it will accord to RTGs and explicitly grant deference to 
RTGs on such matters as dispute resolution and decisionmaking 
processes. It also asks that the Commission honor the reciprocity 
provisions related to Canadian participation that are contained in the 
NWRTA agreement. Nevada Power requests the Commission to accept, as not 
unduly discriminatory, RTG open access tariffs that reflect the 
members' specific terms and conditions so long as the tariffs satisfy 
the substantive requirements of the final rule. It proposes that such 
tariffs be allowed to become effective without hearing or refund 
obligation.
---------------------------------------------------------------------------

    \918\ E.g., UT Com, ID Com, LA DWP, Nebraska Public Power 
District, Salt River, Nevada Power. See also NEPCO, United 
Illuminating, Utility Working Group.
---------------------------------------------------------------------------

    Texas-New Mexico, while encouraging deference to RTGs in general, 
argues that deference must be conditioned upon a requirement that the 
RTG provide not only equal access but also terms and conditions of 
service that are comparable to what a customer could otherwise obtain 
under the final Rule tariff or under section 211 of the FPA.
    Southwest TDU Group contends that RTGs should not be given 
deference, and RTG filings should be subject to the same standards and 
scrutiny as non-RTG filings.
Commission Conclusion
    As we explained in the RTG Policy Statement, we intend to give 
deference to the planning, dispute resolution, and decisionmaking 
processes of an RTG. With respect to pricing proposals submitted by 
RTGs, we believe that RTGs may be able to develop solutions to such 
problems as loop flows through innovative flow-based pricing 
methodologies. As we stated in the Transmission Pricing Policy 
Statement, we will afford considerable deference to an RTG.
4. Pacific Northwest
Comments
    Commenters in the Pacific Northwest ask the Commission to be 
flexible in reviewing tariffs that are based on regional practices, and 
that differ from the final Rule tariff as a result. Public Generating 
Pool urges the Commission to recognize that the Northwest's 
transmission system has been developed and is operated to support the 
region's coordinated power system. That is, it wants all hydro spill to 
be treated equally with no preference between federal and non-federal 
power. Also, it asserts that firm available transmission capacity in 
the Northwest must be worked out by the NWRTA RTG to account for the 
contingent operation of generation to avoid hydro spill.
    Similarly, other commenters note that the Northwest's integrated 
transmission system was constructed to support a unique regionwide 
hydroelectric-dependent generating system and that flexibility is 
needed to accommodate the characteristics of the system.
    WA Com argues that imposition of a uniform national tariff would 
not reflect the region's specific system characteristics or operating 
practices. It argues that the final Rule could impede rather than 
promote efficient competition in the Northwest. It believes that the 
Commission should defer to RTGs for defining and implementing wholesale 
transmission access terms and conditions at the regional level.
    The Washington and Oregon Energy Offices, while supporting the 
adoption of regional practices, argues that uniform transmission 
principles should apply for all transmitting entities in the region. 
They argue that dispatch decisions are complicated by flood control, 
salmon passage, navigation, irrigation, and other constraints. Puget 
requests that the Commission give each transmitting utility the 
flexibility to file tariffs that fit unique or unusual circumstances 
and allow for regional market differences.
    Because the terms and conditions offered by the smaller 
transmission owners in the Northwest are determined by the terms and 
conditions offered by Bonneville, Pacific Northwest Coop argues that 
the terms and conditions for wholesale power transmission, ancillary 
services, and RINs should be deferred until BPA's 1996 rate case is 
resolved and until appropriate regional and national systems and 
protocols are developed.
Commission Conclusion
    As we explained with respect to RTGs, we encourage the filing of 
regional open access transmission tariffs.<SUP>919 The Final Rule pro 
forma tariff contains provisions allowing utilities to modify tariff 
terms to reflect prevailing regional practices. This should permit 
entities in the Pacific Northwest to address unique circumstances that 
exist in the Pacific Northwest and to incorporate prevailing regional 
practices (e.g., treatment of hydropower generation in the priority of 
dispatch) into their open access transmission tariffs.<SUP>920 This 
should also encourage

[[Page 21668]]

other regional solutions, such as the development of regional ISOs, to 
transmission problems.
---------------------------------------------------------------------------

    \919\ Also, as we explained with respect to RTGs, we will review 
pricing proposals in regional tariffs pursuant to our Transmission 
Pricing Policy Statement.
    \920\ This Rule will not resolve disputes over federal hydro 
preference policies or over the agreements incorporated in the 
Northwest Power Planning Act.
---------------------------------------------------------------------------

    In addition, although we will put the Final Rule pro forma tariff 
(which already allow for certain provisions consistent with regional 
practices) into effect for all public utilities 60 days after 
publication of this Rule in the Federal Register, utilities may file 
regional tariffs or propose deviations in the pro forma tariff based on 
additional regional needs to be effective at any time thereafter. Such 
proposals, however, will have to be consistent with the requirements of 
the Final Rule and be reasonable, generally accepted in the region and 
consistently adhered to by the transmission provider. Further, we will 
not permit entities in a region to claim different sets of prevailing 
regional practices.
5. Power Marketing Agencies
a. Bonneville Power Administration (BPA)
Comments
    Washington Water Power explains that for open access transmission 
to be fully realized in the Pacific Northwest there must be federal 
legislation to remove the monopoly protections of federally generated 
power. Until then, Washington Water Power suggests certain mitigating 
measures that would increase competition in the Pacific Northwest. It 
also urges the Commission to take BPA's special characteristics into 
account in issuing the final rule.
    Public Power Council encourages the Commission to make broad use of 
section 211 to mandate transmission access to ensure that BPA continues 
to provide comparable open access transmission.<SUP>921
---------------------------------------------------------------------------

    \921\ See also Puget, Portland, Reynolds.
---------------------------------------------------------------------------

    Public Generating Pool argues that the extent to which BPA's 
tariffs are allowed to deviate from the rule should be governed by the 
technical characteristics of the system and not by BPA's 
status.<SUP>922
---------------------------------------------------------------------------

    \922\ See also Public Power Council.
---------------------------------------------------------------------------

    Direct Service Industries argues that the non-discrimination 
standard is made applicable to BPA by section 212(i) and that the 
Commission has the authority to review all BPA rates under the 
Northwest Power Act (citing Pacific Northwest Electric Power Planning 
and Conservation Act, section 7(a), 16 U.S.C. 839e(a)). It also argues 
that functional unbundling is particularly important for BPA because of 
BPA's market power and relative freedom from regulation. Clark also 
argues that the Commission should require BPA to meet the comparability 
standard. It alleges that BPA refuses to provide comparable service. It 
asserts that the Commission has authority to remedy the problem under 
the Energy Policy Act amendments to section 212, which Clark states 
gives the Commission authority over BPA's transmission practices. Clark 
also notes that BPA is a member of WRTA and, as such, must provide 
comparable service.
    Pacific Northwest Coop argues that many of the issues presented in 
this rulemaking are currently being contested in the BPA rate case in 
Docket Nos. WP-96/TR-96 and TC-96. It says that the Commission should 
defer application of the rule to Pacific Northwest Coop and all of 
BPA's customers until conclusion of the rate case.
    Washington and Oregon Energy Offices asserts that it would be 
proper for the Commission ``to impose similar transmission price 
structures upon Bonneville under section 211 orders as it will for 
jurisdictional [public] utilities under sections 205, 206, and the 
NOPR.''
    With respect to stranded costs, BPA notes that it may be necessary 
to tailor a stranded cost policy for BPA that addresses the goals of 
open access and wholesale stranded cost recovery in a manner consistent 
with BPA's unique circumstances. BPA asks the Commission to defer 
consideration of its stranded investment and related cost recovery 
issues until it makes a rate filing with the Commission.<SUP>923 It 
further argues that the rule should not address whether and how BPA 
stranded costs might be recovered in transmission rates approved by the 
Commission under authority other than sections 211 and 212. Clark 
argues that the Commission's stranded cost recovery policy is 
inapplicable to BPA.
---------------------------------------------------------------------------

    \923\ See also Snohomish, NPPC, W&O, Public Power Council, 
Washington and Oregon Energy Offices, Direct Service Industries.
---------------------------------------------------------------------------

    NW Conservation Act Coalition makes the following suggestions: (1) 
The Commission should grant BPA the authority to levy exit fees on 
customers who are terminating service and who do not use BPA's 
transmission system for their new power transaction; (2) any affected 
person should be allowed to petition the Commission for review of BPA's 
rates for inadequate or inappropriate mitigation of its stranded 
benefits; (3) the rule should insist upon a requirement that open 
access and stranded cost recovery be permitted only if the entities 
involved can show there will be no lessening of support for public 
purposes; and (4) the Commission should clarify that the Direct Service 
Industries customers are retail customers and that they will be subject 
to recovery of stranded costs and benefits.
Commission Conclusion
    BPA is not a public utility under section 201(e) of the FPA and, 
thus, is not subject to the requirements of this Rule to put the Final 
Rule pro forma tariff into effect. However, there are three 
circumstances under which the Commission may review BPA's transmission 
access and pricing policies. First, BPA could file an open access 
tariff and accompanying rates for review and confirmation under section 
7 of the Pacific Northwest Electric Power Planning and Conservation Act 
(Northwest Power Act) <SUP>924 and at that time could ask the 
Commission to find that its tariff meets the Commission's open access 
policies. Second, BPA is a transmitting utility subject to a request 
for mandatory transmission services under section 211 of the FPA. 
Transmission required of BPA under section 211 would have to be 
consistent with the requirements imposed on BPA under its organic 
statutes, the Northwest Power Act, and the Federal Columbia River 
Transmission System Act.<SUP>925 Third, if BPA receives open access 
transmission from a public utility, it is subject to the reciprocity 
provision contained in the utility's Final Rule pro forma tariff. If 
BPA seeks to comply with the reciprocity provision, it could use the 
declaratory order procedures we have provided in this rule for non-
public utility transmission providers. Finally, we note that BPA has 
agreed to provide open access as a member of two RTGs approved by this 
Commission.
---------------------------------------------------------------------------

    \924\ 16 U.S.C. 839-839h.
    \925\ 16 U.S.C. 838-838j.
---------------------------------------------------------------------------

    With respect to stranded costs, BPA has asked us to clarify that 
the Stranded Cost Rule does not address whether and how BPA stranded 
costs might be recovered in transmission rates approved by the 
Commission under authority other than sections 211 and 212 of the FPA 
(namely, section 7 of the Northwest Power Act). We clarify that this 
rule addresses only stranded costs recovered by public utilities under 
the FPA and transmitting utilities (including BPA) that are subject to 
mandatory transmission requests under FPA section 211. It does not 
address stranded cost recovery by BPA under the Northwest Power Act.

[[Page 21669]]

b. Other Power Marketing Agencies
Comments
    SEPA requests that the final rule assure that SEPA can receive 
network transmission service when necessary. It also indicates that it 
has 58 customers that receive less than one MW of power, but that the 
NOPR pro forma point-to-point tariff contains a one MW minimum 
scheduling requirement. Thus, it requests that the final rule allow 
some flexibility with respect to this requirement so that it can carry 
forward its marketing program.
    DOE notes that the Western Area and Southwestern Area Power 
Administrations have pledged to offer transmission services that are 
comparable to those required of public utilities to the extent not 
otherwise prohibited by law.
Commission Conclusion
    Federal power marketing agencies (PMAs) are not public utilities as 
defined under section 201(e) of the FPA and, thus, are not required by 
this rule to file non-discriminatory open access transmission 
tariffs.<SUP>926 However, to the extent a PMA receives open access 
transmission service from a public utility, it is subject to the 
reciprocity provisions in the utility's pro forma tariff.<SUP>927 If a 
PMA seeks to comply with the reciprocity provision, it can file a 
proposed tariff and seek a declaratory ruling.
---------------------------------------------------------------------------

    \926\ PMAs, however, are transmitting utilities subject to 
requests for mandatory transmission services under section 211 of 
the FPA.
    \927\ See Section IV.G.4.f.
---------------------------------------------------------------------------

    With respect to SEPA's concern that the proposed point-to-point 
tariff has a one MW minimum scheduling requirement, but many of its 
customers have loads of less than one MW, we clarify that the Final 
Rule pro forma tariff will allow SEPA to continue to schedule service 
for these customers. Under SEPA's current transmission arrangements, it 
is allowed to aggregate loads within a single control area that are 
less than one MW individually, but jointly are more than one MW, to 
meet the requirement at an interface. The revised language in the Final 
Rule tariff permits this practice to continue. We also clarify that 
SEPA, as a seller of power to multiple purchasers inside several 
control areas, is eligible to receive network service.
6. Tennessee Valley Authority
Comments
    TVA is concerned that the final rule may place TVA at a 
disadvantage because its opportunities to participate in the 
electricity market outside the TVA area are so severely limited by 
statute. It explains that it is restricted from directly participating 
in the new competitive landscape except through limited power exchange 
opportunities with a few neighboring systems. It urges the Commission 
to recognize these circumstances in the final rule. TVA is also 
concerned that its regional customers may face stranded costs because 
its ability to mitigate those costs by making replacement sales to new 
customers is limited.
Commission Conclusion
    TVA is not a public utility under section 201(e) of the FPA and, 
thus, is not required to file a non-discriminatory open access 
transmission tariff under this rule.<SUP>928. However, if TVA receives 
open access transmission service from a public utility, it is subject 
to the reciprocity provision in the utility's pro forma tariff. If TVA 
seeks to comply with reciprocity, it may avail itself of the 
Commission's reciprocity safe harbor approach, through a declaratory 
ruling, if it is fearful that a public utility may deny it service 
simply on a claim that TVA's non-discriminatory open access tariff is 
not satisfactory.<SUP>929 The details of this safe harbor procedure are 
set forth in Section IV.G.4.f.
---------------------------------------------------------------------------

    \928\ TVA, however, is a transmitting utility subject to 
requests for mandatory transmission services under section 211 of 
the FPA.
    \929\ We recognize that sections 212(f)(1) and 212(j) of the 
FPA, as amended by the Energy Policy Act, limit the applicability of 
section 211 to TVA, but conclude that this limitation in no way 
affects our application of the reciprocity requirement to TVA. 
Limitations on TVA's authority to market power are not the product 
of this rule but rather of TVA's enabling legislation. Thus, it is 
for Congress to decide whether TVA should be permitted greater 
marketing authority. As noted in our earlier discussion of 
reciprocity, TVA is not being required to file an open access 
tariff. Rather it is being precluded from taking advantage of 
benefits available under this rule without providing comparable use 
of its system to others.
---------------------------------------------------------------------------

7. Hydroelectric Power
Comments
Non-Firm Transactions
    ID Com believes that the NOPR unfairly discriminates against hydro-
based utilities. It argues that utilities that rely heavily on 
hydropower need to engage in non-firm market transactions that depend 
on water levels; e.g., during low water years, a utility must have 
access to the transmission system to make non-firm, off-system 
purchases. It asserts that the NOPR treats non-firm sales and purchases 
as subordinate to firm transactions and does not allow the utility to 
reserve capacity for its critical, but non-firm, transactions. ID Com 
also asserts that the NOPR would, in effect, strand the utility's 
investment in the production plant being used to generate power for the 
non-firm sales.
    Idaho complains that the NOPR unfairly allows a customer to buy and 
reserve firm transmission rights surplus to its needs, but does not 
permit a utility to do the same. It explains that this problem is 
particularly acute for hydro utilities and argues that they must be 
allowed to reserve at tariff rates at least a portion of available 
transmission capacity for firm and non-firm wholesale transactions. In 
the alternative, Idaho asserts that the transmission owner should not 
be required to provide point-to-point service for transmission uses 
other than from demonstrated firm obligations.
Commission's Licensing Practices
    National Hydropower argues that in light of the NOPR the Commission 
should reexamine the manner in which it exercises its FPA Part I 
authority with respect to (1) economic feasibility determinations, (2) 
section 10(a) findings, (3) determinations of section 10(j) 
recommendations, and (4) section 13. For example, it states that the 
NOPR suggests that all future electric resource selection decisions 
should be based exclusively on short-run marginal cost comparisons. 
Because, it asserts, hydroelectric power provides many public interest 
benefits not susceptible to precise quantification, the Commission 
should clarify how non-price factors are to be considered in a post-
final rule wholesale electric marketplace.
Commission Conclusion
Non-Firm Transactions
    As we explained above with respect to the Pacific Northwest, we 
will permit entities to incorporate prevailing regional practices 
(e.g., treatment of hydropower generation in the priority of dispatch) 
into regional open access transmission tariffs. This should permit 
entities in a region to resolve concerns over the scheduling of non-
firm hydropower. In addition, if a utility and its customers can agree 
on the scheduling of non-firm hydropower and the disruption of firm 
transactions, we would permit that resolution to be incorporated into 
the utility's tariff. Utilities are permitted to consider seasonal 
variations in hydropower availability in the determination of Available 
Transmission Capacity to be posted on the OASIS.
Commission's Licensing Practices
    The issues raised by National Hydropower with respect to our

[[Page 21670]]

hydroelectric licensing practices are beyond the scope of this 
rulemaking. Indeed, National Hydropower has already raised its concerns 
in a petition to the Commission to revise our hydroelectric licensing 
procedures, filed on July 10, 1995. That is the proper proceeding in 
which to address our hydroelectric licensing practices.
8. Residential Customers
Comments
    Several commenters are concerned that the rule may undermine the 
financial position of public utilities so that they will not be able to 
provide many of the programs that benefit low-income residents (e.g., 
assistance to low-income and elderly consumers, weatherization and 
energy conservation programs, and payment of taxes that provide many 
city services).<SUP>930
---------------------------------------------------------------------------

    \930\ E.g., Urban League, Latin League, Black Mayors, 
Homelessness Alliance, National Women's Caucus, La Raza.
---------------------------------------------------------------------------

    La Raza is concerned that the rule will permit large preferred 
customers to opt out of the regulated structure, leaving behind a 
smaller and less affluent base to support the long-term investments 
made under the previous regulatory environment.
    Home Builders is concerned that utilities may compensate for 
reduced profits under the proposed rule by raising infrastructure 
charges and hookup fees for new homes, thus reducing new home sales.
    State and City Supervised Housing for Equity in Electric Rates 
states that publicly supervised housing is uniquely qualified to obtain 
open access electricity from wholesale markets, and that the Commission 
should adopt policies that bring competitive benefits to residents of 
such housing.
Commission Conclusion
    While some residential consumers may be apprehensive about the 
changes that this rule may have on the electric industry, we are 
convinced that the changes we are proposing for wholesale markets will 
benefit them. As wholesale transmission open access becomes a reality, 
residential consumers should reap the benefits of more competitive bulk 
power markets and associated lower costs. This rule does not require 
retail transmission access for retail customers of any size. Moreover, 
this rule does not require any changes in programs such as assistance 
to low-income and elderly consumers and weatherization and energy 
conservation. As discussed in Section IV.I, those programs are under 
the jurisdiction of the individual states, and will remain under their 
jurisdiction. Indeed, this rule contains several safeguards to maintain 
the ability of states to impose conditions on retail access, such as 
conditions that help to protect residential customers from becoming the 
residual payer of stranded costs.

V. Environmental Statement

    This section reviews and adopts the final environmental impact 
statement (FEIS) prepared by the Commission staff in connection with 
this rule. It identifies the alternatives considered by the agency in 
reaching its decision; analyzes and considers whether and to what 
extent the chosen alternative--adoption of this rule--is likely to 
result in environmental harm; evaluates alternatives and suggestions 
for mitigating environmental harm from the rule, if any; and states the 
Commission's decision.

Summary

A. The Environmental Impact Statement

    The Commission decided to prepare an environmental impact statement 
(EIS) evaluating the environmental consequences that could result from 
adoption of this rule. We did so largely in response to the claims of 
several commenters, including the Environmental Protection Agency 
(EPA), who charge that the rule will have significant adverse 
environmental effects.
    Although a number of issues were raised, by far the most prominent 
concern arises from the theory that competitive market conditions 
created by the rule will provide an advantage to power suppliers who 
produce power from coal-fired facilities that are not subject to 
stringent environmental controls on nitrogen oxides (NO<INF>X) 
emissions.<SUP>931 Under this theory, these facilities, located 
primarily in the Midwest and South, will, as a result of the rule, 
generate more power and emit more NO<INF>X, which will contribute to 
ozone formation. The ozone could add to pollution both in those regions 
and more significantly in the Northeast, to which area such pollutants 
could be transported. Those who propound this theory argue that it is 
the responsibility of the Commission, using its authority under the 
Federal Power Act, to effect environmental controls that will mitigate 
what they predict will be significant increases in NO<INF>X emissions 
associated with this rule.
---------------------------------------------------------------------------

    \931\ References throughout the Environmental Statement are to 
emissions from the electric industry, and not to emissions from all 
sources.
---------------------------------------------------------------------------

    The staff prepared an FEIS based upon computer modeling simulations 
of power generation patterns and NO<INF>X emissions likely to occur as 
a result of the rule. Staff used widely accepted models for studying 
economic conditions in power markets and simulating emissions of 
NO<INF>X and other pollutants. These models took into account a variety 
of different assumptions concerning significant factors such as coal 
and natural gas prices and other competitive conditions. These factors 
are critical because increased use of coal-fired generation tends to 
increase NO<INF>X emissions, while increased use of gas-fired 
generation is environmentally more benign.
    The examination in the FEIS of the environmental effects that are 
likely to result from implementing the rule is based on an analytic 
framework that was shaped by comments received in the scoping process 
and on the DEIS. The study was revised to reflect the frozen efficiency 
reference case assumptions requested by EPA and other commenters. This 
was done to ensure full disclosure of possible environmental impacts 
even though the Commission disagrees that use of these assumptions is 
appropriate.
    It has been observed in the context of agency preparation of an 
environmental study that ``(t)he NEPA process involves an almost 
endless series of judgment calls.'' <SUP>932 That is particularly true 
where, as here, the agency undertakes to examine the impacts of a 
proposed regulatory program. In designing an effective assessment of 
the environmental impacts of the rule, the Commission had to make a 
number of judgments as to the type and the scope of studies necessary 
to analyze the proposals sufficiently. Commenters also raised many 
issues related to the design of the study. For example, the Center for 
Clean Air Policy contends that the Commission should model a range of 
mitigation policies; the Missouri Department of Natural Resources 
contends that the impact of the rule on generation may be locally 
intense and that these effects should have been studied; and other 
commenters sought to have the Commission examine different database or 
modeling assumptions.
---------------------------------------------------------------------------

    \932\ Coalition on Sensible Transportation, Inc. v. Dole, 826 
F.2d 60, 66 (D.C. Cir. 1987). The Court added that ``[i]t is of 
course always possible to explore a subject more deeply and to 
discuss it more thoroughly. The line-drawing decisions necessitated 
by this fact of life are vested in the agencies, not the courts.'' 
Id.
---------------------------------------------------------------------------

    For these and similar matters we exercised our judgment as to the 
appropriate manner in which to treat the issue. For example, we 
determined not to model a range of mitigation

[[Page 21671]]

policies because we did not find that the impacts of the rule require 
the Commission to adopt or implement a plan of mitigation. It would 
have been extremely difficult, if not impossible, to examine the many 
varied local impacts that could be expected across the Nation in 
response to the Rule. We made judgments as to the appropriate database 
and modeling assumptions to use--in some cases, those assumptions were 
shaped or changed by comments we received.
    In short, many competing considerations came into play during the 
design of the complex analysis used to examine the environmental 
effects of the rule. We exercised our judgment, for example, based on 
consideration of whether matters are within the scope of the rule, the 
most appropriate way to study the effects of the proposal, and whether 
the issues raised were relevant to a consideration of the environmental 
effects of the rule. The Commission's response to issues raised by 
commenters is reflected in the response to comments set forth in 
Appendix J of the FEIS. We conclude that the FEIS reflects the 
appropriate consideration of these and many similar issues.

B. Major Issues

    Some comments on the draft environmental impact statement (DEIS), 
as well as earlier comments in response to Commission scoping 
inquiries, raise two major areas of objection to the Commission's 
analysis. First, commenters claim that in determining what NO<INF>X 
emission levels would be in the future with the adoption of the rule, 
the Commission did not compare the emissions levels associated with the 
rule against the appropriate base case. They argue that the Commission 
should have analyzed and compared the impacts of the rule to a ``no-
action'' alternative that assumes that the Commission abandons all its 
open access policies, not just this rule. Some commenters, including 
EPA, go even further, suggesting that the Commission compare emission 
levels projected to result from the rule against a ``frozen 
efficiency'' case in which other major factors--factors that would 
increase industry efficiency independent of the Rule--do not occur. 
Such factors include adoption of pro-competitive state policies and 
actions by utilities to undertake mutually beneficial voluntary 
transactions that do not require the use of open access tariffs 
mandated under this rule. Commenters who advocate either a different 
``no-action'' alternative or the frozen efficiency case expect that 
studies using those assumptions will show that the rule will cause 
significantly greater NO<INF>X emissions than shown in the 
DEIS.<SUP>933
---------------------------------------------------------------------------

    \933\ See Section V, Discussion, Subsection C.
---------------------------------------------------------------------------

    Assuming these results, these commenters raise their second major 
area of concern, which is mitigating the presumed effects of the rule. 
These arguments vary somewhat but share a common theme: That the 
Commission has a responsibility, either as a legal or public policy 
matter, to mitigate what they expect to be the significant 
environmental impact associated with the rule. They suggest various 
mitigation schemes, including a FERC-administered NO<INF>X emission 
allowance program along the lines of the sulfur dioxide (SO<INF>2) 
program enacted by Congress and administered by the EPA under the Clean 
Air Act. Other proposals would have the Commission condition the right 
of a seller to use an open access tariff on certification that the 
source of the power sold is in compliance with (as yet undetermined) 
emissions limitations. Another proposal would have the Commission 
impose a charge on emissions to be paid by utilities to a fund 
established by the Commission. The added cost to the utilities would 
work to account for, or ``internalize'', the external costs of 
emissions.
    Commenters advocating Commission-administered mitigation argue that 
the mechanisms under current law for regulating NO<INF>X emissions are 
cumbersome and slow, and that the Commission should not (some argue, 
may not) go forward with the rule unless it puts in place environmental 
regulatory mechanisms that prevent further increases in NO<INF>X 
emissions.
    Various legal theories are advanced as a basis for Commission 
environmental regulation under the Federal Power Act. Some argue that 
the conditioning authority under the Federal Power Act is sufficient to 
enable us to fashion comprehensive controls on emissions from utility 
generators because there is a direct causal nexus between power trading 
(which we regulate) and generation (which we do not). Others argue that 
such authority lies in the use of our power to impose requirements on 
utilities ``in the public interest'', enhanced by the National 
Environmental Policy Act. Others argue that, in remedying undue 
discrimination, we must correct competitive advantages arising from 
Congressional decisions to exempt certain kinds of generation 
facilities from some Clean Air Act regulation.

C. Commission Conclusions

    After reviewing the comments and the additional studies conducted 
by staff in response to the comments, the Commission adopts the 
findings in the FEIS.
    First, the findings show that, without the rule, NO<INF>X emissions 
are expected to decline until at least the year 2000. Thereafter, again 
without the rule, NO<INF>X emissions are expected to increase steadily 
through the year 2010 (the end of the FEIS study period). The extent of 
the decrease and the increase will largely be determined by the 
relative prices of natural gas and coal, the two main fuels used to 
generate electric power in most regions.<SUP>934
---------------------------------------------------------------------------

    \934\ Generally, a relative advantage for coal is likely to 
increase environmental impacts while a relative advantage for 
natural gas is likely to create modest environmental benefits.
---------------------------------------------------------------------------

    In reaching this conclusion, the FEIS used two ``base'' cases. In 
one (the ``High-Price-Differential Base Case''), natural gas was 
assumed to become substantially more expensive compared with coal than 
it is today. In the other (the ``Constant-Price-Differential Base 
Case''), natural gas was assumed to maintain essentially the same price 
relative to coal that has existed for the last ten years. The two cases 
describe the range of emissions due to fuel price uncertainty without 
the rule and demonstrate the overall trends of decreases until 2000 and 
increases thereafter.
    Second, the FEIS finds that the rule will not in any significant 
respect affect these overall trends.
    The potential impact of the rule was studied initially under two 
scenarios.<SUP>935 In one (the ``Competition-Favors-Gas Scenario''), 
the rule is assumed to result in efficiency gains in the electric 
industry that would tend to favor natural gas as a fuel. In this 
scenario the effect of the rule is slightly beneficial. Total NO<INF>X 
emissions are reduced overall by about two percent nationwide from the 
base cases. In the other (the ``Competition-Favors-Coal Scenario''), 
the rule is assumed to result in efficiency gains in the electric 
industry that would tend to favor coal as a fuel. In this scenario the 
effect is again slight, showing approximately a one percent increase in 
NO<INF>X emissions nationwide from the base cases. In both scenarios, 
however, the rule does not have an overall effect on NO<INF>X emission 
trends.
---------------------------------------------------------------------------

    \935\ A third scenario considered improved conditions for the 
transmission system only. This scenario showed very small effects 
from the rule and is not addressed further here.
---------------------------------------------------------------------------

    Stated differently, under any case studied, with or without the 
rule, there will be an overall net decrease in NO<INF>X

[[Page 21672]]

emissions through the year 2000.<SUP>936 Thereafter, NO<INF>X emissions 
begin to increase. The rule does not materially affect either the 
decline prior to 2000 or the increase thereafter.
---------------------------------------------------------------------------

    \936\ These results are set forth graphically and in tabular 
form in the FEIS at pp. ES-3 and ES-13. They are also reproduced in 
Appendix H.
---------------------------------------------------------------------------

    Based on these findings the Commission concludes that a 
comprehensive, Commission-imposed mitigation scheme to address the 
environmental consequences of the rule is not appropriate. If 
competition favors gas, the effects are beneficial and mitigation is 
unnecessary. If competitive conditions favor coal through the year 
2010, and NO<INF>X emissions increase slightly as a result of the rule, 
these minor effects would be effectively mitigated as a part of a 
comprehensive NO<INF>X cap and trading allowance scheme developed by 
EPA in cooperation with the Ozone Transport Assessment Group (OTAG) and 
administered by EPA and state environmental regulators under the 
clearly established authority of the Clean Air Act.
    Further, the Commission believes that staff has selected the 
appropriate ``no-action'' alternative. An alternative that requires the 
Commission to reverse all its other open access policies is simply not 
a ``no-action'' alternative. To the contrary, it would require decisive 
action running counter to the direction from the Congress in the Energy 
Policy Act and the needs of the marketplace and electricity consumers.
    However, to ensure that the effects of the rule were analyzed 
fully, the FEIS did study a reference case based on the ``frozen 
efficiency'' case proffered by EPA and the Department of Energy 
(DOE).<SUP>937 Although, as described below, we believe this case to be 
highly unlikely, the results show that, even under this scenario, the 
impacts of the rule are not great and do not vary significantly from 
those projected by staff under the other assumptions.
---------------------------------------------------------------------------

    \937\ Although DOE agreed with EPA's request that we analyze the 
frozen efficiency case as a reference case, DOE believes that the 
DEIS selected the appropriate base case. DOE also argues that the 
mitigation of any adverse consequences from the rule should be 
addressed by EPA under the Clean Air Act or by the Congress.
---------------------------------------------------------------------------

    In one case requested by EPA, staff studied a combination of 
assumptions most likely to show significant increases in emissions 
associated with the rule; the case included EPA's frozen efficiency 
scenario, coupled with the ``Competition-Favors-Coal'' assumptions. 
Other cases requested by EPA posit dramatic increases in transmission 
capacity (that we find highly unlikely). Even this combination of 
assumptions--geared to demonstrate the greatest impact the rule might 
have on increased NO<INF>X emissions--produced little in the way of 
environmental consequences associated with the rule. Under these 
extreme (and unlikely) conditions, there would still be a net decrease 
in NO<INF>X emissions until at least the year 2000, albeit a smaller 
decrease than in the base cases. Comparing projections of emissions for 
the same years, emissions would be higher than the base cases only by 
two percent in 2000 and three percent in 2005.<SUP>938 It is only in 
the year 2010, assuming these improbable scenarios, that NO<INF>X 
emissions associated with the rule would be higher than the base case 
by even five percent.<SUP>939
---------------------------------------------------------------------------

    \938\ FEIS Table 6-10 at p. 6-17.
    \939\ Id.
---------------------------------------------------------------------------

    Based on these studies, including the EPA reference case, the 
Commission endorses the staff findings that the rule will affect air 
quality slightly, if at all, and that the environmental impacts are as 
likely to be beneficial as negative. This is true even under scenarios 
contrived to maximize emissions associated with the rule under 
circumstances that this Commission believes to be highly unlikely.
    Importantly, this is also true in the near- to mid-term. Until the 
year 2010, even the worst case (the frozen efficiency case) produces 
results very similar to those produced using assumptions the Commission 
believes to be reasonable. In short, the rule will not produce an 
``ozone cloud'' coming across the Appalachians to threaten the 
Northeast on the day the rule goes into effect. Assuming that any 
environmental impacts occur, they are years in the future and may well 
be beneficial. As a result, calls for Commission mitigation, and in 
particular for interim mitigation to ``fill the gap'' until programs 
under the Clean Air Act can be adopted, are unnecessary and 
disproportionate to the possible effects of the rule.
    We also endorse the staff view that it is neither within our 
statutory authority nor appropriate as a matter of policy to fashion 
from the FPA a comprehensive clean air regulatory program to address 
NO<INF>X emissions. As described below, we believe that the mitigation 
proposals proffered in comments exceed our statutory authority to 
regulate rates, terms and conditions of sales of electric energy and 
transmission of electric energy in interstate commerce. We are, in 
essence and by law, economic regulators. While we have an obligation 
under NEPA to take the environmental consequences of our actions into 
account in fashioning our decision--and we have done so--NEPA grants us 
no new regulatory powers. While NEPA extends our general obligation to 
engage in reasoned decisionmaking to include the consideration of 
possible environmental consequences of our actions, it compels no 
particular substantive result.
    Though our conditioning authority under sections 205 and 206 of the 
FPA is broad, our actions under it are confined to the subject matter 
of our jurisdiction. That subject matter excludes the physical aspects 
of generation and transmission. Our actions must derive from and 
advance our statutory mandate to protect consumers by establishing 
utility rates and business practices that are just, reasonable, and not 
unduly discriminatory or preferential. These authorities, however broad 
they are with respect to economic matters, are not unbounded; they may 
not be used to ``fill in the gaps'' of regulatory programs that, by 
law, are not our own.
    Moreover, even if it were possible to tease from the FPA some 
implicit authority to regulate NO<INF>X emissions from utility 
generators, it is not feasible for this Commission to develop and 
implement such a program. The mitigation schemes presented in comments 
are filled with unknowns and complexities that are best resolved by 
those charged with administration of the Nation's environmental laws. 
In some cases, the mitigation schemes are based on a model of utility 
transactions that is fundamentally at odds with the purposes of the 
rule. For example, several proposals would require the Commission to 
establish whether emissions from certain units or systems contribute to 
ozone noncompliance elsewhere, perhaps hundreds of miles away. Other 
proposals would require the Commission to establish baseline standards 
for emissions; generating units with emissions above that level would 
be required to adopt mitigation measures. The technical difficulties 
associated with these proposals are evident on their face. While 
resolving these issues is necessary to establish an effective NO<INF>X 
regulatory program, the Commission does not possess the requisite 
expertise to establish baseline NO<INF>X emission levels and address 
the difficult technical and policy issues that are presented in 
regulating NO<INF>X emissions. EPA is the agency with jurisdiction over 
and experience with such matters. Although efforts are underway to 
resolve these issues within the framework of the Clean Air Act, all air 
regulators agree that much work still needs to be done.

[[Page 21673]]

    Other proposals would require the Commission to track generation 
that is used for wholesale versus retail sales. However, for example, 
use of holding company corporate structures, as well as emerging market 
structures, would make it extremely difficult, if not impossible to 
distinguish between retail and wholesale transactions. In addition, 
such measures are inconsistent with the goals of the rule (and the 
Energy Policy Act) to eliminate time-consuming, inefficient 
transaction-based approvals that impede open access and to promote 
entry of sellers into bulk power markets on a competitive basis.
    Moreover, any such program implemented by this Commission could 
well undercut the existing regulatory scheme crafted by Congress under 
the Clean Air Act, as amended. In particular, we are being asked 
essentially to rework the legislative decisions made by Congress 
regarding certain coal-fired generators. Those decisions are at the 
heart of the 1990 Clean Air Act compromise. The only means Congress has 
made available for addressing these problems under current law are in 
the Clean Air Act. If these means prove insufficient to address the 
NO<INF>X problem overall, the case for change must be presented to the 
Congress.
    Although we have concluded that NO<INF>X emissions problems are 
most effectively addressed by clean air regulations within the 
framework of the Clean Air Act, we do recognize that the question of 
NO<INF>X emissions is a very important one. Our FEIS documents that, 
with or without this rule, NO<INF>X emissions from all sources are 
expected to increase over time. This will present a significant 
environmental issue for the Northeast, which is already struggling to 
reach current NO<INF>X reduction standards, as well as for other 
regions of the country that are being called on to participate in an 
inter-regional solution to the NO<INF>X problem. As the EPA rightly 
recognizes, attempting to frame an appropriate solution with the tools 
currently available is a tough job. We therefore understand why those 
concerned would try to enlist this Commission in an effort to solve 
this problem with regulatory mechanisms other than those set out in the 
Clean Air Act. We also understand why even the prospect of exacerbating 
that problem would ignite the kind of controversy reflected in the 
comments to this rule, and why, in response, those who have gained 
Congressional exemptions from certain regulations wish not to have 
those benefits undermined. At the same time, we understand, and have 
great sympathy with, the many commenters who have suggested that the 
economic benefits of this rule to consumers should not be suppressed or 
delayed by this difficult, ongoing debate.
    Our FEIS clearly demonstrates that this rule is not the appropriate 
vehicle for resolving this very important debate. We believe that our 
study makes a significant contribution nonetheless. We have added 
significantly to the understanding of the problem and have established 
a viable, current baseline for assessing future industry trends. This 
baseline should serve air regulators well in analyzing overall NO<INF>X 
emissions in the future.<SUP>940 We have resolved some important 
questions about the role of open access and have established clearly 
the influence of energy prices on NO<INF>X emissions in the future.
---------------------------------------------------------------------------

    \940\ For example, the data we used to project future industry 
generation and fuel use update by several years the data relied upon 
by EPA in its Regulatory Impact Analysis used as a basis for its 
recently proposed NO<INF>X rule, entitled ``Acid Rain Program; 
Nitrogen Oxides Emission Reduction Program.'' 61 FR 1442 (1996). We 
believe the data developed in the FEIS will make a useful 
contribution to EPA's effort.
---------------------------------------------------------------------------

    Our study also supports the view held by many commenters that the 
appropriate regulatory mechanisms for addressing the NO<INF>X problem 
overall, including emissions from electric utility generating plants, 
is a NO<INF>X emissions cap and allowance trading scheme along the 
lines of that developed by the Congress under the Clean Air Act for 
SO<INF>2 emissions. As staff suggests, even if there are slight 
environmental impacts associated with the rule, they are better and 
more effectively addressed as a part of a comprehensive NO<INF>X 
regulatory program. While Congress did not enact such a scheme for 
NO<INF>X, it did, as described below, empower the EPA to establish such 
a program. The EPA is the only federal agency with clear authority and 
expertise to address this problem. It should do so.
    The FEIS also identifies the importance of OTAG to the development 
of a fair and effective NO<INF>X regulatory program. OTAG, which 
includes representatives from all affected states, is currently at work 
developing the analytic basis needed for a regional consensus solution 
to the NO<INF>X problem. OTAG is also evaluating possible solutions, 
including an allowance trading scheme. We believe that OTAG's efforts 
are to be applauded, and we encourage the EPA and all interested 
parties to work with OTAG to address this issue of national concern.

Discussion

A. Compliance With NEPA Requirements

1. Background
    The Commission issued a NOPR in this proceeding on March 29, 1995. 
In doing so, we concluded that promulgating the proposed Rule would not 
represent a major federal action having a significant adverse impact on 
the human environment and that the proposed Rule fell within the 
categorical exemption provided in the Commission's regulations for 
electric rate filings submitted by public utilities under sections 205 
and 206 of the FPA.<SUP>941 Subsequently, the Commission determined 
that, despite the availability of the categorical exclusion, it would 
nonetheless prepare an environmental analysis. On July 12, 1995, the 
Commission directed staff to prepare an EIS to assess the environmental 
impacts of the proposed Rule. That notice requested comments on 
environmental issues and scheduled a scoping meeting for September 8, 
1995.<SUP>942
---------------------------------------------------------------------------

    \941\ 18 CFR 380.4(a)(15).
    \942\ 60 FR 36752 (1995).
---------------------------------------------------------------------------

    A Notice of Availability of the DEIS was published in the Federal 
Register on November 27, 1995.<SUP>943 The DEIS evaluated several 
potential alternatives and mitigation measures as summarized below.
---------------------------------------------------------------------------

    \943\ 60 FR 58304 (1995).
---------------------------------------------------------------------------

    A Notice of Availability of the FEIS was published in the Federal 
Register on April 19, 1996.<SUP>944
---------------------------------------------------------------------------

    \944\ 61 Fed.Reg. 17,296 (1996).
---------------------------------------------------------------------------

2. General Requirements
    Section 102 of NEPA, 42 U.S.C. 4332, requires that federal agencies 
prepare an EIS on proposals for major federal actions significantly 
affecting the quality of the human environment. The objective is to 
build into the agency decisionmaking process careful consideration of 
environmental aspects of proposed actions, including the evaluation of 
reasonable alternatives. Although we believe a categorical exclusion to 
be available,<SUP>945 the Commission has performed this EIS to ensure 
that this Rule is promulgated with the benefit of careful consideration 
of its environmental aspects.
---------------------------------------------------------------------------

    \945\ See 40 CFR 1507.3 (1995); 18 CFR 380.4 (1995).
---------------------------------------------------------------------------

3. Alternatives
    The consideration an agency must give in an EIS to alternatives to 
its proposed action is bounded by a number of factors, including 
notions of feasibility, whether basic changes would

[[Page 21674]]

be required to the statutes and policies of other agencies, and the 
extent to which the proposal would result in significant impacts. The 
United States Supreme Court (Supreme Court or Court) stated what is 
required in an EIS with regard to alternatives in Vermont Yankee 
Nuclear Power Corp. v. NRDC, 435 U.S. 519, 551 (1978): ``(A)s should be 
obvious even upon a moment's reflection, the term `alternatives' is not 
self-defining. To make an impact statement something more than an 
exercise in frivolous boilerplate the concept of alternatives must be 
bounded by some notion of feasibility.'' <SUP>946 In this regard, the 
Supreme Court quoted Natural Resources Defense Council v. Morton, 458 
F.2d 827, 837-38 (D.C.Cir. 1972), with approval as follows:
---------------------------------------------------------------------------

    \946\ Vermont Yankee, 435 U.S. at 551.
---------------------------------------------------------------------------

    There is reason for concluding that NEPA was not meant to 
require detailed discussion of the environmental effects of 
``alternatives'' put forward in comments when those effects cannot 
be readily ascertained and the alternatives are deemed only remote 
and speculative possibilities, in view of basic changes required in 
statutes and policies of other agencies--making them available, if 
at all, only after protracted debate and litigation not meaningfully 
compatible with the time-frame of the needs to which the underlying 
proposal is addressed.

The Supreme Court went on to discuss the concept of ``feasibility'', 
stating that:

Common sense also teaches us that the ``detailed statement of 
alternatives'' cannot be found wanting simply because the agency 
failed to include every alternative device and thought conceivable 
by the mind of man. Time and resources are simply too limited to 
hold that an impact statement fails because the agency failed to 
ferret out every possible alternative, regardless of how uncommon or 
unknown that alternative may have been at the time the project was 
approved.<SUP>947
---------------------------------------------------------------------------

    \947\ Id.
---------------------------------------------------------------------------

    Thus, an EIS must discuss the alternatives that are feasible and 
briefly discuss the reasons others were eliminated. There is no minimum 
number of alternatives that must be discussed.<SUP>948 An agency's 
consideration of alternatives is adequate if it considers an 
appropriate range of alternatives--it does not have to consider every 
available alternative.<SUP>949
---------------------------------------------------------------------------

    \948\ Laguna Greenbelt, Inc. v. DOT, 42 F.3d 517, 524-25 (9th 
Cir. 1994).
    \949\ Resources Limited, Inc. v. Robertson, 35 F.3d 1300, 1307 
(9th Cir. 1993).
---------------------------------------------------------------------------

    The range of alternatives that must be considered in the EIS need 
not extend beyond those reasonably related to the purposes of the 
project.<SUP>950 An agency is entitled to identify some parameters and 
criteria related to the proposal for generating alternatives to which 
it would devote serious consideration. Without such criteria, an agency 
could generate countless alternatives.<SUP>951 Alternatives that are 
unlikely to be implemented need not be considered, nor must an agency 
consider alternatives that are infeasible, ineffective, or inconsistent 
with basic policy objectives.<SUP>952 In this sense, central to 
evaluating practicable alternatives is the determination of a project's 
purpose.<SUP>953
---------------------------------------------------------------------------

    \950\ Id.
    \951\ Id.
    \952\ Id.
    \953\ National Wildlife Federation v. Whistler, 27 F.3d 1341, 
1345 (8th Cir. 1994).
---------------------------------------------------------------------------

    Furthermore, the range of alternatives that reasonably must be 
considered decreases as the environmental impact of a project becomes 
less and less substantial. If a proposal would have minimal 
environmental effect, the range of alternatives that must be considered 
is narrow. It would be an anomaly to require that an agency search for 
more environmentally sound alternatives to a project that it has 
determined will have no significant environmental effects.<SUP>954 
Moreover, feasible alternatives may be rejected if they present unique 
problems or cause extraordinary costs and community disruption.<SUP>955
---------------------------------------------------------------------------

    \954\ Missouri Mining, Inc. v. ICC, 33 F.3d 980, 984 (8th Cir. 
1994).
    \955\ Communities, Inc. v. Busey, 956 F.2d 619, 627 (6th Cir.), 
cert. denied, 506 U.S. 953 (1992).
---------------------------------------------------------------------------

    As applied to the instant case, NEPA does not require the 
consideration of alternatives that are remote and speculative 
possibilities because they would require basic changes to statutes and 
policies. Therefore, alternatives that would require the Commission to 
ignore open access policies enacted by Congress in the Energy Policy 
Act and to assume such policies would not be pursued by the states are 
not feasible and need not be considered. Likewise, the Commission need 
not consider alternatives that are ineffective or inconsistent with 
basic policy objectives, or that would cause extraordinary costs and 
community disruption. Finally, because the rule would have minimal 
environmental effect, the range of alternatives that must be considered 
is narrow. We conclude that staff has examined the appropriate 
alternatives in the FEIS and correctly determined that promulgation of 
the rule represents the most appropriate action.
    Certain commenters have argued that the alternative that calls for 
the Commission to abandon the policy of promoting transmission access 
is more appropriate for the no-action alternative than the no-action 
alternative selected by the staff.<SUP>956 We disagree. As discussed 
below, that contention is more properly an argument about the 
appropriate baseline to use in the FEIS. That debate has been resolved 
by the consideration of a reference case that includes a baseline which 
bounds the effects that those commenters seek to have analyzed.
---------------------------------------------------------------------------

    \956\ See Section V, Discussion, Subsection B.2.
---------------------------------------------------------------------------

4. Mitigation
    To fulfill the requirements of NEPA with regard to mitigation, an 
agency must identify and evaluate the adverse environmental effects of 
the proposed action, in this case the rule. Having identified and 
evaluated adverse environmental effects, the agency is not constrained 
from then deciding that other values outweigh the environmental costs 
of the proposal.
    The leading case interpreting this requirement is Robertson v. 
Methow Valley Citizens Council, 490 U.S. 332 (1989)(Methow Valley). 
There, the Court explained that:

Although these procedures (preparation and circulation of an EIS) 
are almost certain to affect the agency's substantive decision, it 
is now well settled that NEPA itself does not mandate particular 
results, but simply prescribes the necessary process. If the adverse 
environmental effects of the proposed action are adequately 
identified and evaluated, the agency is not constrained by NEPA from 
deciding that other values outweigh the environmental costs * * *. 
Other statutes may impose substantive environmental obligations on 
federal agencies, but NEPA merely prohibits uninformed--rather than 
unwise--agency action.<SUP>957

    \957\ Methow Valley, 490 U.S. at 350-51 (citations and footnote 
omitted) (emphasis added).
---------------------------------------------------------------------------

The Court held that ``(t)o be sure, one important ingredient of an EIS 
is the discussion of steps that can be taken to mitigate adverse 
environmental consequences.'' <SUP>958 This is so because:
---------------------------------------------------------------------------

    \958\ Id. at 351 (footnote omitted).
---------------------------------------------------------------------------

Implicit in NEPA's demand that an agency prepare a detailed 
statement on ``any adverse environmental effects which cannot be 
avoided should the proposal be implemented, 42 U.S.C. 4332(C)(ii), 
is an understanding that the EIS will discuss the extent to which 
adverse effects can be avoided. More generally, omission of a 
reasonably complete discussion of possible mitigation measures would 
undermine the ``action-forcing'' function of NEPA. Without such a 
discussion, neither the agency nor other interested groups and 
individuals can properly evaluate the severity of the adverse 
effects * * * .<SUP>959

    \959\ Id. at 351-52 (citation omitted).
---------------------------------------------------------------------------

The Court acknowledged that:

There is a fundamental distinction, however, between a requirement 
that mitigation be

[[Page 21675]]

discussed in sufficient detail to ensure that environmental 
consequences have been fairly evaluated, on the one hand, and a 
substantive requirement that a complete mitigation plan be actually 
formulated and adopted, on the other * * *. Even more significantly, 
it would be inconsistent with NEPA's reliance on procedural 
mechanisms--as opposed to substantive, result-based standards--to 
demand the presence of a fully developed plan that will mitigate 
environmental harm before an agency can act.<SUP>960.

    \960\ Id. at 352-53 (citation and footnote omitted).
---------------------------------------------------------------------------

    The Court again stressed that ``(b)ecause NEPA imposes no 
substantive requirement that mitigation measures actually be taken, it 
should not be read to require agencies to obtain an assurance that 
third parties will implement particular measures.'' <SUP>961 Thus, the 
Court held that mitigation, including mitigation that other 
governmental bodies have jurisdiction to implement, must be discussed 
in sufficient detail to ensure that environmental consequences of a 
proposed action have been fairly evaluated. However, a complete 
mitigation plan need not be actually formulated or adopted.
---------------------------------------------------------------------------

    \961\ Id. at 353 n .16.
---------------------------------------------------------------------------

    The suggestion by various commenters that the Commission is 
required to adopt and implement a plan to mitigate the impacts of the 
rule is without legal or factual basis. Even if the effects of the rule 
were greater than the FEIS shows them to be, Methow Valley clearly 
establishes that, regardless of the impacts of the proposed action, the 
Commission is required only to understand the impacts of its actions. 
This compels us to consider and discuss mitigation; it does not require 
us to adopt and implement mitigation. This FEIS thoroughly examines 
mitigation of possible adverse environmental effects and concludes that 
sufficient mechanisms exist to address the impacts of the rule, if any.
5. Role of EPA
    Section 309 of the Clean Air Act, 42 U.S.C. 7609, authorizes EPA to 
review and comment on environmental impact statements prepared by 
federal agencies. If the EPA Administrator determines that a proposed 
regulation is unsatisfactory from, among other things, the standpoint 
of environmental quality, she may refer the matter to the Council on 
Environmental Quality (CEQ).<SUP>962
---------------------------------------------------------------------------

    \962\ The process appropriate for CEQ referral of actions by an 
independent regulatory agency is not addressed here.
---------------------------------------------------------------------------

    In this case, EPA has commented extensively on the DEIS. It sought 
changes to the staff's analysis, primarily to include the use of the 
frozen efficiency assumptions. The staff has fully complied with EPA's 
study requests even though it regards such assumptions as implausible, 
contrary to the Energy Policy Act and Commission policy, and at odds 
with industry trends and practical considerations affecting the 
industry.<SUP>963
---------------------------------------------------------------------------

    \963\ For example, see the discussion on transmission 
constraints at Section V, Discussion, Subsection C.
---------------------------------------------------------------------------

    Although EPA may disagree with the environmental acceptability of 
an agency's proposal, the agency is charged with making the ultimate 
determination whether to implement a proposal; in making that decision, 
the agency is free to reject advice offered through the comment and 
referral process.<SUP>964 Objections on the part of EPA may give rise 
to a heightened obligation of the agency to explain clearly and in 
detail its reasons for proceeding in the face of those objections. This 
the Commission has done. It has thoroughly examined the impact of the 
assumptions advanced by EPA; that analysis is detailed in Chapter 6 of 
the FEIS.<SUP>965
---------------------------------------------------------------------------

    \964\ See Alaska v. Andrus, 580 F.2d 465 (D.C. Cir.), vacated in 
part on other grounds sub nom. Western Oil & Gas Ass'n v. Alaska, 
439 U.S. 922 (1978).
    \965\ The Commission bears the ultimate responsibility for 
evaluating the environmental impacts of the rule. In doing so, it 
must consider EPA's comments, but is not bound by them. See Citizens 
Against Burlington, Inc. v. Busey, 938 F.2d 190, 201 (D.C.Cir.), 
cert. denied, 502 U.S. 994 (1991). In that case the Court held that:
    Congress wants the EPA to participate when other agencies 
prepare environmental impact statements. See 42 U.S.C. 7609(a). The 
EPA participated here. But the (Federal Aviation Agency), not the 
EPA, bore the ultimate statutory responsibility for actually 
preparing the environmental impact statement, and under the rule of 
reason, a lead agency does not have to follow the EPA's comments 
slavishly--it just has to take them seriously. See Alaska v. Andrus, 
580 F.2d at 474.
---------------------------------------------------------------------------

    In summary, NEPA prescribes a process and not a result. What is 
critical is that environmental impacts of a proposed action be 
adequately identified and evaluated--an important component of this 
process is understanding the possible mitigation measures that are 
involved, including measures which may be beyond the jurisdiction of an 
agency to implement. This requirement does not translate, however, into 
a requirement that an EIS adopt a mitigation plan, particularly where, 
as here, the impacts of the rule are small and may be either positive 
or negative.

B. Analysis of Alternatives

    The FEIS evaluated three alternatives to the rule including: (1) A 
no-action alternative which assumes that the rule is not adopted, but 
that existing statutory and regulatory policies remain in place; (2) a 
Commission decision to reverse existing policies and halt 
implementation of mandatory open access; and (3) a Commission decision 
to aggressively develop competitive power markets by mandating 
corporate reorganization or divestiture.
1. The No-Action Alternative
    The principal alternative to the proposed action is for the 
Commission not to adopt the rule, but to continue its existing open 
access and stranded cost policies. In recent years, the Commission has 
required public utilities that merge or seek to acquire jurisdictional 
transmission facilities under section 203 of the FPA to file open 
access transmission tariffs. The Commission also has required public 
utilities to file open access transmission tariffs to mitigate market 
power and to ensure non-discrimination if they or their affiliates wish 
to sell power at market-based rates. In addition, the Commission 
processes case-by-case requests made by potential transmission users 
under section 211 of the Energy Policy Act for transmission service, 
and has allowed utilities to include stranded cost provisions in their 
open access transmission tariffs on a case-by-case basis.<SUP>966
---------------------------------------------------------------------------

    \966\ See Section III.
---------------------------------------------------------------------------

    Actions taken pursuant to section 211, and pursuant to sections 203 
and 205 in merger and market-based rate cases respectively, represent a 
case-by-case approach to establishing open access. By contrast, the 
rule would, in a single generic proceeding, require each jurisdictional 
public utility to file open access tariffs at the same time. The 
consumer benefits from the rule are expected to be $3.8 to $5.4 billion 
per year.<SUP>967
---------------------------------------------------------------------------

    \967\ See Section I.
---------------------------------------------------------------------------

    Absent action on the rule, the Commission would continue on a case-
by-case basis to require public utilities to file open access tariffs 
and provide case-specific service as necessary or appropriate. Sections 
205 and 206 charge the Commission with ensuring that voluntary 
transmission tariffs are not unduly discriminatory. If the rule were 
not adopted, the Commission would continue to require that voluntary 
tariffs be upgraded to offer non-discriminatory open access 
transmission services pursuant to the Commission's current standards. 
The result of continuing the Commission's policies without the rule is 
that the Commission would effectuate a more open transmission grid than 
is present today, but in a patchwork manner and at a slower pace. Over 
some extended time period, many, but not necessarily

[[Page 21676]]

all, utilities would become subject to open access requirements.
    The case-by-case approach to achieving open access now in use is 
slower and more costly, and thereby less desirable, than the generic 
approach set forth in the rule. Given the rapid changes facing the 
industry, and the opportunity for great consumer savings, the no-action 
alternative is not a reasonable alternative to the rule.
2. Abandon the Policy of Promoting Transmission Access
    A second alternative is for the Commission to abandon its current 
policy and take no action whatsoever to foster transmission access. 
Under this alternative, the Commission would no longer require open 
access transmission as a condition of mergers and asset acquisitions 
under section 203 or requests for market-based pricing under section 
205, and would no longer grant applications filed pursuant to section 
211. Offers of transmission would become strictly voluntary.
    This alternative is inconsistent with Congress' general intent in 
the Energy Policy Act to foster wholesale competition, and also with 
its specific intent in expanding section 211 to permit the Commission 
to require a transmission-owning utility to make its transmission 
system available to eligible users if to do so is in the public 
interest. This alternative is also inconsistent with the Commission's 
obligations under sections 205 and 206 to ensure that public utilities 
do not unduly discriminate in providing jurisdictional services. It is, 
therefore, not a reasonable alternative to the rule.
3. Corporate Reorganization/Divestiture Alternative
    Under this alternative, the Commission would require public 
utilities either to divest control of their transmission assets or to 
reorganize their corporate structures to perform their transmission 
functions through a separate subsidiary, thereby segregating 
transmission from the rest of the utilities' operations. However, 
corporate reorganization or divestiture would have no effect on the 
operation of power plants, which are assumed to be dispatched on the 
basis of economic efficiencies. Thus, this alternative would lead to 
the same environmental impacts as the rule. That is, the environmental 
effects would be no different from those studied in the FEIS.

C. The Scope of the FEIS

    The FEIS examines the environmental impacts that could result from 
implementing this rule. This analysis is undertaken against the 
background of the existing electric industry. The electric industry 
currently produces environmental impacts, and those impacts are certain 
to change over time as the industry responds to factors as varied as 
changes in demand for electricity, the price of fuels, changes in 
regulatory programs, technological developments, and changes in market 
structure.
    The FEIS does not examine the environmental impact of electric 
generation that is required to meet generators' existing service 
requirements. Nor does it examine the environmental effects of the 
inter-utility power exchanges that have occurred in the industry for as 
long as utilities have been interconnected. Rather, the FEIS examines 
impacts of potential increases in generation and changes in patterns of 
generation that might result from implementation of the rule.
    In creating an analytical construct to examine the impacts of the 
rule, the staff developed a set of cases that defined the framework for 
running the computer models utilized to examine the changes in types of 
power plants constructed in the future and changes in operating 
patterns of existing power plants, including changes in fuel mix.
    First, staff characterized how electric power markets might evolve 
absent adoption and implementation of the rule by establishing 
baselines (i.e., base cases) to project the future impacts of the 
industry.<SUP>968 The relative prices of coal and natural gas are 
critical in establishing what is likely to happen in the future. 
Accordingly, a range of prices was developed to project the impacts of 
these factors. In the first baseline, the Constant-Price-Differential 
Base Case, coal and natural gas prices are assumed to maintain the same 
relative position they have maintained over the past ten years. In the 
second baseline, the High-Price-Differential Base Case, natural gas is 
assumed to become substantially more expensive compared with coal than 
it has been over the past 10 years. In all other respects, the 
assumptions underlying the two base cases are the same.
---------------------------------------------------------------------------

    \968\ As discussed below, once baselines were established to 
portray what is likely to happen in the electric industry without 
the rule, the projected impacts of the rule were then determined 
against this background.
---------------------------------------------------------------------------

    Because the purpose of the base cases is to describe the impacts of 
the electric industry if the Commission takes no action over and beyond 
continued implementation of existing policies, the baselines assume 
that the Commission continues the open access and stranded cost 
policies it has instituted in recent years.
    Some commenters have challenged this aspect of the baselines used 
in the study. The gist of their argument is that the environmental 
impacts of these programs have not been evaluated and that the 
baselines therefore improperly take credit for impacts that have not 
yet occurred, thus understating the projected impacts of the rule. In 
general, these commenters argue that the second alternative considered 
by the staff represents the ``true'' no-action alternative.
    At bottom, this debate is not about what constitutes the 
appropriate no-action alternative. Rather, it is a debate about what 
aspects of the electric industry should be taken into account when 
determining future environmental impacts of the industry against which 
to measure the impacts of the rule. The commenters urge the Commission 
to consider varying baselines, but in general they oppose inclusion in 
the base cases of the Commission's ongoing open access and stranded 
cost programs.
    Some commenters not only urge that the Commission not take into 
account continued implementation of its open access and stranded cost 
programs, but that it go much farther and establish baselines (against 
which to examine the impacts of the rule) that do not reflect the 
impacts of a great many changes that are already taking place in the 
electric industry. This proposal would establish a baseline that does 
not take into account: (1) Current Commission transmission policy; (2) 
programs that states and industry players have adopted to improve 
industry efficiency; and (3) mutually beneficial transactions that 
electric companies enter into on a regular basis.
    The use of these assumptions would fly in the face of long-standing 
industry trends which move in precisely the opposite direction. 
Utilities are reducing reserve margins, improving plant availabilities, 
and reducing barriers to transmission even without Commission 
action.<SUP>969 Many states are aggressively pursuing plant efficiency 
policies.<SUP>970 These trends are long-standing and are not 
attributable to the rule, or even to a broader Commission program of 
open access. These trends, projected into the future, form the basis 
for the conditions reflected in the FEIS base cases. These trends are 
fundamentally at odds with the assumptions some commenters wish the 
Commission to use to establish baselines.
---------------------------------------------------------------------------

    \969\ FEIS Chapter 6.
    \970\ Id.

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[[Page 21677]]

    We conclude that the approach used by staff to develop the 
baselines used in the FEIS is appropriate. Abandoning current open 
access policies is unrealistic, contrary to Congressional intent, and 
at odds with pro-competition policies that are at the heart of the 
Commission's current regulatory mission. The selection of the 
appropriate methodology to establish the baselines used in the FEIS is 
clearly within the Commission's discretion and expertise.<SUP>971
---------------------------------------------------------------------------

    \971\ See, e.g., Sierra Club v. Marita, 46 F.3d 606, 621, 623 
(7th Cir. 1995).
---------------------------------------------------------------------------

    What the commenters challenging this assumption desire is 
additional study of the impacts of the rule. Specifically, they wish to 
test the rule against a different set of assumptions for the 
acknowledged purpose of attributing greater adverse environmental 
consequences to the rule. The regulations of the Council on 
Environmental Quality no longer contain a requirement to conduct a 
conjectural ``worst-case analysis.'' <SUP>972 NEPA requires an agency 
to adequately identify and evaluate the adverse environmental effects 
of a proposed action.<SUP>973 It does not require the agency to ignore 
the world as it exists.
---------------------------------------------------------------------------

    \972\ Methow Valley, 490 U.S. at 354-55. The revised 
requirement, 40 CFR 1502.22, which pertains to incomplete or 
unavailable information, is inapplicable as well. The problem here 
is not incomplete or unavailable information, but rather which 
existing policies and events should be included in the analysis.
    \973\ 42 U.S.C. 4332.
---------------------------------------------------------------------------

    Nonetheless, to respond to concerns about the baselines used in the 
DEIS with respect to key atmospheric emissions, the staff conducted 
sensitivity analyses to examine the outer boundaries of a range of 
cases requested by some commenters. This range of cases is called the 
``frozen efficiency'' case. In essence, the frozen efficiency cases 
assume that no further open access of any kind occurs during the study 
period and that efficiency in the industry (for instance, power plant 
availability) remains frozen through the same period. The assumption 
that there is substantially more inter-regional transmission capacity 
than posited in the original analysis is separately examined in the 
base and rule cases.<SUP>974
---------------------------------------------------------------------------

    \974\ Several commenters, including EPA, are concerned that 
increases in transmission capacities resulting from open access 
might increase generation levels and thus air emissions. EPA is 
especially concerned with the expansion of transmission links 
between the midwest and east coast. The FEIS examines scenarios that 
increase transmission capacity substantially beyond current levels. 
This analysis finds that postulated increases do not affect 
emissions attributable to the rule. We believe increases considered 
in the FEIS far exceed any transmission capacity increases that 
might occur as a result of the rule. This is due in part to the fact 
that state-level siting issues, the principal barrier to major 
capacity increases in the transmission grid, are unaffected by the 
rule. The issues regarding enhancement of existing lines are more 
complex. Competition under open access will lead to improved 
efficiencies in generation. Transmission, on the other hand, will 
remain a regulated monopoly function. The rule will reduce barriers 
to access, but will not open the transmission system to direct 
competition. Thus, we believe that the competitive effects of the 
rule on transmission expansion will be relatively small.
    EPA urges us to assume that transmission capacity is expanded by 
40 percent compared to our base case. We do not believe this is 
likely to occur. The experience with one proposed new transmission 
line in the very area EPA focuses on demonstrates this difficulty. 
Duquesne Light filed an application with the Pennsylvania Public 
Utilities Commission to construct a new 500 Kv line across 
Pennsylvania to supply electricity to New Jersey. Within a few days 
of the filing of the application, over 3,000 individuals and groups 
filed complaints in opposition to the proposed line. ``Electricity 
Utility Week'' (November 4, 1991). A bill was proposed in the 
Pennsylvania Legislature to prevent construction of the line. 
Another bill was introduced in Congress to halt construction of new 
transmission lines throughout the U.S. for two years. Duquesne 
ultimately decided to withdraw its proposal and the line was not 
constructed. ``The Energy Daily'' (April 4, 1994).
---------------------------------------------------------------------------

    We must reiterate that the frozen efficiency case is far more 
restrictive in its assumptions than a true no-action case in which the 
Commission simply stops all efforts to promote open access. A true no-
action case would closely resemble the FEIS base cases because much of 
the efficiency gain in that base case would occur even with no move 
toward open access.
    As detailed in Chapter 6 of the FEIS, and as discussed below, even 
the frozen efficiency case demonstrates results that are essentially 
the same as those demonstrated by the base cases used by the staff. In 
the frozen efficiency worst case, when coal prices become considerably 
more attractive compared to gas prices, national NO<INF>X emissions 
would be lower than in the base cases used by staff by only one percent 
(in 2000) to four percent (in 2010). If coal and natural gas prices 
remain at today's relative levels, the effects would be smaller--zero 
percent in 2000 to two percent lower in 2010. National CO<INF>2 
emissions would be between zero and two percent lower than in the base 
cases used by the staff over the same time frame.

D. Economic and Environmental Impacts of the Rule

    The FEIS reports a quantitative estimate of approximately $3.8 
billion to $5.4 billion in benefits per year of cost savings expected 
from competition under the rule. The FEIS also considers other, non-
quantifiable benefits that can be expected from implementing the rule. 
These benefits include better use of existing assets and institutions, 
new market mechanisms, technical innovation, and less rate distortion. 
Further, the FEIS demonstrates to our satisfaction that the rule is 
likely to have little or no adverse environmental impact and that any 
impacts are as likely to be beneficial as harmful.
    The issue most frequently raised by commenters involves air quality 
impacts, particularly the possible transport of NO<INF>X emissions from 
upwind areas to airsheds in the Northeast and the resulting impacts on 
ozone non-attainment areas.
    With regard to NO<INF>X, the FEIS demonstrates that, as a result of 
clean air regulatory programs, NO<INF>X emissions nationwide, with or 
without the rule, will decline through the year 2000, but begin to 
climb thereafter.<SUP>975 This basic trend remains the same in all 
cases examined in the FEIS. This is because the level of NO<INF>X 
emissions in any given year depends primarily on one key uncertainty 
that is not related in any way to the rule--the relative price of 
natural gas and coal.<SUP>976 Lower prices for natural gas, relative to 
coal, lead to lower levels of NO<INF>X emissions.
---------------------------------------------------------------------------

    \975\ FEIS Figure ES-1 and Table ES-2, reproduced at Appendix H.
    \976\ See, e.g., FEIS at ES-8.
---------------------------------------------------------------------------

    The FEIS also demonstrates that increases in access to transmission 
and efficiencies in electric power markets associated with the rule do 
not alter the expected trend of NO<INF>X emissions, regardless of the 
relative price of natural gas and coal. Increased transmission access 
and industry efficiency facilitated by the rule may either decrease 
total emissions somewhat or increase them somewhat, depending on 
whether competitive conditions in the electric industry favor natural 
gas or coal. When competitive conditions favor natural gas, the effect 
of the rule is beneficial, reducing emissions somewhat. When 
competitive conditions favor coal, emissions increase by a small 
amount. Nevertheless, the overall trend of expected NO<INF>X emissions 
retains its general shape.
    In assessing the projected impacts of the electric industry absent 
adoption of the rule (i.e., the base cases studied in the FEIS), the 
most important factor affecting changes in national NO<INF>X emissions 
is the relative competitive position of coal and natural gas. The most 
important factor affecting the relative competitive positions of coal 
and natural gas is price.
    National NO<INF>X emissions from the electric industry were 5,844 
thousand tons in 1993, the last year for which complete data is 
available. If relative gas

[[Page 21678]]

and coal prices remain the same, for example, we project that national 
NO<INF>X emissions will be 5,579 thousand tons in 2005 without adoption 
of the rule. If gas prices rise relative to coal prices, we project 
that NO<INF>X emissions in 2005 will be 6,053 thousand tons without 
adoption of the rule. Stated another way, favorable coal prices are 
projected to result in NO<INF>X emissions that are about three percent 
higher in 2000 to 10 percent higher in 2010 over the base case where 
gas is the favored fuel.
    The effect of adopting the rule could be to raise or lower national 
emissions slightly compared to the effects projected in the base cases. 
Nationally, in 2005, we project that the Competition-Favors-Coal 
Scenario (with rising relative gas prices) would add one percent to 
NO<INF>X emissions above the base case that favors coal. The 
Competition-Favors-Gas Scenario (with constant relative fuel prices) 
would lower emissions by two percent compared with the base case that 
favors gas.
    Regional effects are generally similar. In 2005, in the East North 
Central region (a source of potential increased NO<INF>X emissions that 
might affect the Northeast), the base cases project small increases in 
industry emissions (two percent). In that region in 2005, the rule may 
add as much as one percent to NO<INF>X emissions compared to the 
relevant base case (the Competition-Favors-Coal Scenario) or reduce 
emissions compared to the relevant base case by as much as three 
percent (the Competition-Favors-Gas Scenario).
    The EIS uses the UAM-V model to track the effects of projected 
NO<INF>X emissions on downstream ozone levels during a severe weather 
period. This detailed air quality modeling shows no real difference in 
the Northeast between the base case favoring coal (the High-Price-
Differential Base Case) and the Competition-Favors-Coal Scenario. 
Detailed local analysis shows slightly lower ozone concentrations in 
some locations and slightly higher concentrations in others. None of 
the differences adds to non-attainment levels projected in the relevant 
base case, and all fall within the noise levels of the model. That is, 
they are smaller than the uncertainties in the science underlying the 
model.
    As discussed above, the Commission believes that the base cases 
used by staff in its analysis are the most realistic and, therefore, 
the most appropriate cases to consider the potential environmental 
impacts of the rule. However, as requested by the EPA, DOE, and certain 
other commenters, sensitivity analyses were conducted to examine the 
impacts on the results of the analysis if key assumptions are changed 
as requested by commenters. Presumably, comparing the projected impacts 
of the rule to the requested ``frozen efficiency'' case provides a 
measure of the greatest impacts that could possibly (albeit 
unrealistically) be expected from implementing the rule.<SUP>977
---------------------------------------------------------------------------

    \977\ These assumptions include, and go substantially beyond, 
the ``no-action'' alternative advocated by EPA and others in 
positing a baseline that would tend to maximize the amount of 
NO<INF>X emissions attributed to the rule. This is because under a 
frozen efficiency scenario all increases in power trading (and 
resulting NO<INF>X emissions) would be attributed to the Rule. In 
fact, as described below, many of the efficiencies posited under the 
EPA assumptions are attributable to other factors and certain of the 
efficiencies (e.g., 40 percent increase in transmission capacity) 
are wholly unrealistic.
---------------------------------------------------------------------------

    As the FEIS discusses, even comparing projected NO<INF>X emissions 
under the rule to the highly implausible frozen efficiency case, 
impacts attributable to the Rule are projected to be modest or non-
existent. This holds true even when large (up to 40 percent) increases 
in transmission capacity are assumed to occur under the rule.<SUP>978 
Moreover, adding coal-favoring assumptions--which would presumably 
increase emissions--about future competitive conditions in the electric 
industry to the implausible frozen efficiency assumptions, NO<INF>X 
emissions are projected to increase very modestly until the year 2010 
(by only two percent in 2000 and three percent in 2005). Even using 
this highly unlikely alternative to the rule, the analysis projects a 
net environmental benefit (although a very small one) if gas prices 
stay constant compared to coal prices.
---------------------------------------------------------------------------

    \978\ Some commenters assume that large increases in 
transmission capacity would result in a significant expansion in 
generation and thus increased emissions. In reality, the analysis 
present in Chapter 6 of the FEIS indicates that this is not the 
case.
---------------------------------------------------------------------------

    Concern also has been expressed with regard to the need to mitigate 
CO<INF>2, mercury, and fine particulate emissions, and with the impact 
of the rule on visibility. As with NO<INF>X, the FEIS demonstrates that 
the rule is as likely to improve such emissions and visibility as it is 
to exacerbate them. In any event, the impact is expected to be small.
    In sum, the Commission adopts the FEIS findings that:

    <bullet> The relative price of coal and natural gas has a larger 
effect on NO<INF>X emissions than any impacts from the proposed 
rule. Without the proposed rule, different fuel price assumptions 
are projected to lead to a 7 percent difference between the two base 
cases in nationwide NO<INF>X emissions in 2005, with some regions 
affected more than others.
    <bullet> The rule is projected to have only slight impacts on 
NO<INF>X emissions, and the impacts are as likely to be beneficial 
as harmful. In 2005, if competitive conditions in the electric 
industry (for instance, heat rates) favor natural gas, the proposed 
rule is projected to decrease baseline NO<INF>X emissions by 2 
percent nationwide. If competitive conditions favor coal, the rule 
is projected to raise baseline NO<INF>X emissions by 1 percent. 
Regional effects in both cases are generally similar. In short, any 
negative impacts that the rule might cause are a small fraction of 
the uncertainty inherent in fuel price projections.
    <bullet> Even a substantial increase in transmission capacity 
(up to 40 percent on every transmission line in the country) would 
change emission estimates by very small amounts in all cases. In 
many cases, the changes would represent net environmental benefits.
    <bullet> Even comparing projected emissions under the proposed 
rule to the highly implausible frozen efficiency case, impacts 
attributable to the rule are projected to be modest or non-existent. 
The staff believes this is an unreasonable comparison because the 
frozen efficiency assumptions ignore industry trends that the 
Commission is generally powerless to stop. In effect, they assume 
that the alternative to the proposed rule is (1) for the Commission 
to reverse current transmission policy, an action that is 
inconsistent with Congressional policies under EPAct, (2) for states 
to cease adopting programs to improve industry efficiency, and (3) 
for electric companies to cease entering mutually beneficial 
transactions. Even after adding coal-favoring assumptions about 
future competitive conditions in the electric industry to the 
implausible frozen efficiency assumptions, NO<INF>X emissions are 
projected to increase only very modestly until 2010 (by only 2 
percent in 2000 and 3 percent in 2005). Even using this highly 
unlikely alternative to the proposed rule, the analysis projects a 
net environmental benefit (although a very small one) if gas prices 
stay constant compared to coal prices. EPA indicates that it 
considers the lower gas price assumption to be ``the more likely of 
the base cases'' (DEIS comments, p. 35).<SUP>979
---------------------------------------------------------------------------

    \979\ FEIS at ES-2.
---------------------------------------------------------------------------

E. Mitigation Analysis

    An agency is required to consider mitigation if the proposed action 
will result in adverse environmental impacts.<SUP>980 The insistence of 
commenters that the Commission adopt and implement mitigation measures 
is based on significantly overstated assumptions regarding the 
contribution of the rule to existing environmental problems. The 
analysis presented in the FEIS establishes that these assumptions about 
the impact of the Rule are wrong. As stated in the FEIS,

    \980\ See Methow Valley, 490 U.S. at 348-53.
---------------------------------------------------------------------------

    The sensitivity analyses (i.e., the frozen efficiency case 
requested by EPA, DOE and other commenters) do not support the 
argument that the proposed rule is likely to lead to large immediate 
impacts that require

[[Page 21679]]

immediate mitigation. In fact, using the more reasonable EIS base 
cases, it is clear that the proposed rule is at least as likely, if 
not more likely, to benefit the environment as it is to have adverse 
environmental impacts. As a result, we believe it is not a 
responsible course of action to undertake efforts to mitigate 
speculative adverse environmental consequences that may well not 
materialize; such action could well have the opposite effect and 
delay the clear benefits the proposed rule will produce in order to 
---------------------------------------------------------------------------
address small, highly uncertain environmental impacts.<SUP>981

    \981\ FEIS at 7-5.
---------------------------------------------------------------------------

    Even if the rule were to result in adverse environmental impacts as 
a result of competitive conditions that favor the future use of coal, 
such impacts are not likely to occur until about the end of the time 
period examined in the FEIS. EPA in its comments on the DEIS stressed, 
based on views it formed prior to knowing the results of the frozen 
efficiency case, that the Commission should develop interim mitigation 
until EPA can implement a program of controls. EPA stated in its 
comments that it has authority to address ``some'' of the impacts it 
believed would result from the rule, but stated that it would take it 
considerable time to do so--up to 10 years. The results of the 
unrealistic worst case analysis demonstrate that adverse effects would 
not be expected to occur for approximately 10 years in any event. Thus, 
interim mitigation is not required; EPA will have sufficient time to 
develop under the Clean Air Act whatever mitigation plan it may deem 
necessary.
    Although the staff concluded that mitigation was unnecessary given 
the results of its analysis, given the importance of this issue, it 
nonetheless examined in considerable detail measures, including those 
proposed by commenters, that could be taken to mitigate adverse 
environmental consequences of the rule if they were to occur. The FEIS 
focuses on NO<INF>X emissions in particular given the importance 
assigned to this issue by commenters.
1. Mitigation Measures Under the Clean Air Act
    As discussed in greater detail in the FEIS, the existence for many 
years of a significant ozone non-attainment problem in parts of the 
U.S. has led to the development of mechanisms to address this issue. In 
particular, Congress has established requirements in the Clean Air Act 
for regulating NO<INF>X emissions. These requirements establish 
specific NO<INF>X emission levels for certain types of boilers. As 
discussed below, the Commission is not authorized to alter those 
requirements as requested by certain commenters.
    In the 1990 Amendments to the Clean Air Act, Congress enacted the 
Acid Rain Program to reduce annual SO<INF>2 and NO<INF>X emissions. For 
SO<INF>2, Congress established a cap and trade program that uses a 
market-based allowance system to reduce SO<INF>2 emissions from 
utilities by approximately 50 percent. The allowance system caps 
utility emissions at 8.9 million tons a year by 2000. A pool of 8.9 
million allowances was then created, each representing the right to 
emit one ton of SO<INF>2 pollution in a specified calendar year. The 
allowances can be used to permit current emissions, sold, or held in 
reserve.
    As a result of uncertainty in the understanding of ozone formation 
and transport, Congress acted less aggressively in regulating NO<INF>X 
emissions. It chose to limit NO<INF>X emissions from utilities by means 
of allowable emission limits and to require further study of ozone 
precursors, leaving room for the EPA to abate NO<INF>X requirements 
where scientifically justified. Accordingly, in section 407 of the 
Clean Air Act, 42 U.S.C. 7651f, Congress established a NO<INF>X 
reduction program which provides that EPA shall by regulation establish 
annual allowable emissions limitations for NO<INF>X for specified types 
of utility boilers (Group 1 boilers). Section 407 also provides that, 
by not later than January 1, 1997, the Administrator shall establish 
allowable emission limitations for NO<INF>X on a lb/MMBtu, annual 
average basis for specified other types of utility boilers (Group 2 
boilers).
    On April 13, 1995, EPA promulgated a Rule setting emission 
limitations on Group 1 boilers that combust coal as a primary fuel. EPA 
reports that the April 13, 1995 regulation ``is expected, by the year 
2000, to nationally reduce NO<INF>X emissions by an estimated 1.54 
million tons per year.'' <SUP>982
---------------------------------------------------------------------------

    \982\ 61 FR 1442 (1996).
---------------------------------------------------------------------------

    On January 19, 1996, EPA published a proposed rule to implement the 
second phase of the Acid Rain Program. This rule proposes to establish 
NO<INF>X emission limitations for Group 2 boilers and to revise 
NO<INF>X emission limitations for Group 1 boilers to impose tougher 
standards. EPA states that ``[t]he proposal would, by the year 2000, 
achieve an additional reduction of 820,000 tons of NO<INF>X annually.'' 
<SUP>983
---------------------------------------------------------------------------

    \983\ Id.
---------------------------------------------------------------------------

    In addition, Congress determined to deal with the issue of the 
interstate transport of ozone by authorizing the formation of transport 
commissions. The Clean Air Act authorizes EPA to establish transport 
regions that are charged with assessing the degree of interstate 
transport of pollutants, assessing mitigation strategies, and 
recommending revisions to State Implementation Plans to correct the 
problem. The Clean Air Act specifically establishes an ozone transport 
region (OTR) for the Northeast. The jurisdictions that comprise the OTR 
have developed a coordinated approach to this problem that includes 
adopting a regional cap on NO<INF>X emissions.
    Although the OTR process is achieving its purpose, a broader 
program is clearly appropriate to address the overall problem. As a 
consequence, the Ozone Transport Assessment Group (OTAG) has been 
formed which encompasses the OTR and upwind states that contribute to 
non-attainment. OTAG is performing extensive photochemical grid 
modeling of the eastern U.S. to determine ozone transport problems and 
to evaluate the efficiency of various control strategies. OTAG is 
considering recommending a cap and trade system for NO<INF>X emissions 
from all sources in a 37-state area comprising the Northeast OTR and 
upwind states. If the cap and trading system becomes effective it 
therefore should fully mitigate NO<INF>X emission increases, if any, 
attributable to open access transmission within the 37-state area. A 
cap and trade program is also likely to mitigate CO<INF>2 and mercury 
emissions.<SUP>984 Any incremental increases in NO<INF>X, mercury, or 
CO<INF>2 emissions that may result from the rule can and should be 
addressed within this existing framework.
---------------------------------------------------------------------------

    \984\ It should be noted that the science relating to 
determining mercury emission levels and also to the environmental 
impacts of CO<INF>2 is uncertain, particularly with regard to the 
impacts of CO<INF>2 emissions. The FEIS evaluates these matters as 
best it can under the circumstances.
---------------------------------------------------------------------------

    All of these factors lead us to agree with the staff's conclusion 
in the FEIS that a cap and trading system such as that under 
consideration in the OTAG process is the preferred approach to the 
overall NO<INF>X emissions problem, including emissions associated with 
the rule, if any. This approach brings together EPA and the concerned 
states in a program that utilizes existing regulatory authority under 
the Clean Air Act.
    The OTAG process brings to the table the parties that must 
participate in making the difficult decisions necessary to fully 
resolve this problem. OTAG possesses the technical resources and 
expertise to address the difficult scientific and technical issues that 
must be resolved to remedy this problem. A cap and trading system will 
require the

[[Page 21680]]

development of emission baselines for a great many entities; 
development of such baselines is certain to require extensive modeling 
and many difficult compromises. OTAG and others have been working 
towards this end for a long time. A more limited approach--one 
undertaken by this Commission or aimed at the limited (and only 
potential) impacts of the rule--cannot render a satisfactory solution. 
A program designed to deal with the slight impacts associated with the 
rule will not contribute significantly to the overall solution and 
could, indeed, impede it if the Commission took actions that prove 
inconsistent with solutions developed by OTAG or if debate over 
Commission-sponsored mitigation were to continue to distract interested 
parties from the preferred route of developing a consensus solution 
within the framework of the Clean Air Act. We respect the expertise and 
the goals of the OTAG process and do not believe we can or should 
substitute for them in addressing this long-term national problem.
2. Mitigation Measures Proposed by Commenters
    The FEIS also analyzes NO<INF>X mitigation measures proposed by 
commenters. These include voluntary measures pursuant to which the 
Commission would support utility efforts to mitigate pollution and 
proposals under which the Commission would mandate mitigation. 
Commenters suggest a variety of Commission actions including using its 
conditioning authority to require utilities to consider environmental 
impacts; <SUP>985 sanctioning imputed charges in rates to reflect 
incurred environmental externalities; and designing specific, 
transaction-oriented mechanisms designed to address the increment of 
emissions attributable to new wholesale transactions resulting from the 
rule.<SUP>986 The FEIS discusses five proposals in some detail: Those 
presented by the Center for Clean Air Policy (CCAP), the EPA, Joint 
Commenters, the Project for Sustainable FERC Energy Policy (Sustainable 
FERC), and the DOE.<SUP>987 Of these, the FEIS recommends the proposal 
put forward by DOE:

    \985\ For example, EPA suggests that we require certain types of 
filings, such as a request to charge market-based rates, to include 
an assessment of environmental impacts and mitigation, if necessary. 
Joint Commenters suggest we require wheeling and interconnection 
applicants to demonstrate that their requests will not contribute to 
increased NO<INF>X or ozone in downwind regions, and Conservation 
Law suggests linking recovery of stranded costs to the retirement of 
unsuitable generators.
    \986\ The FEIS also discusses mitigation measures that can be 
undertaken by others. These include strategies to require some 
existing plants to meet more stringent, new NO<INF>X standards, 
relying on market forces to control inter-regional NO<INF>X 
transport, or measures that could be employed by the states to limit 
power purchases based on environmental considerations. See FEIS at 
7-26 to 7-28.
    \987\ FEIS at 7-28 to 7-43.
---------------------------------------------------------------------------

    Staff concurs (with the DOE analysis) that the best solution to 
the problem of NO<INF>X transport and ozone non-attainment lies in 
exercise of statutory authority under the Clean Air Act by EPA and 
the states. Absent Congressional action, no resolution of the 
difficult political and technical issues will represent a lasting 
solution of this problem except one that comes from a collaborative 
process such as OTAG.<SUP>988

    \988\ FEIS at 7-43.
---------------------------------------------------------------------------

    As the FEIS explains in great detail, each of the other 
recommendations suffers from serious shortcomings. In one form or 
another, they would require the Commission to implement technically 
complex emissions control regimes outside of the Commission's 
expertise. Some would require that we duplicate existing monitoring 
systems. Others would require that we implement provisions that would, 
in effect, defeat the very purpose of the rule.<SUP>989 Indeed, these 
recommendations would have the Commission embark upon an extensive 
environmental regulatory regime that appears unwarranted, unworkable 
and, as discussed below in some detail, beyond our lawful authority. 
And they would have us act in a way that may well frustrate the ongoing 
efforts to deal with these problems and would frustrate the benefits to 
be derived from the rule.
---------------------------------------------------------------------------

    \989\ The rule represents the Commission's remedy to unduly 
discriminatory practices found to exist by public utilities that own 
and/or control interstate transmission facilities. Having found an 
unlawful practice, we must remedy it. However, EPA would require 
that those seeking to enjoy the benefits of non-discriminatory open 
access transmission further agree to go beyond current environmental 
requirements specified by federal and state authorities authorized 
by Congress to regulate such matters.
---------------------------------------------------------------------------

    The CCAP asserts that FERC should establish an emissions monitoring 
program for NO<INF>X and CO<INF>2 and implement an emission neutrality 
requirement (ENR) to mitigate what it believes to be the impacts of the 
rule. The monitoring program would require generators to identify 
emissions associated with off-system sales on a kWh basis in real-time 
and integrate this information with the data to be made available on 
electronic bulletin boards (EBBs). Under the ENR aspect of CCAP's 
proposal, to be eligible for service under open access tariffs, 
companies that operate plants upwind from the Northeast OTR and the 
upper Midwest would have to certify that firm and economy off-system 
power sales using an open access tariff would have no incremental 
impact on ozone compliance in other areas. All sales for resale that 
require service under an open access tariff and originate upwind of the 
OTR would need to include NO<INF>X emissions reduction credits equal to 
the increase in emissions related to those sales. The seller could meet 
its requirement to be ``emission neutral'' under the mechanism by 
achieving the required emission reductions annually at their own 
facilities, or through purchases of credits anywhere in the airshed.
    EPA proposes two mitigation alternatives. In the first, it states 
that FERC could deny open access service unless there is a showing that 
the service will not have an adverse environmental impact. Under this 
approach, EPA, in cooperation with the states in OTAG, would recommend 
and establish a mitigation mechanism that could be entered into by a 
customer seeking open access service and used by such customer to make 
the necessary environmental demonstration supporting the provision of 
the service. The FERC would rule on whether the mitigation mechanism 
presented by the customer and the evidence on the likely effectiveness 
of the mechanism were sufficient to make the environmental 
demonstration.
    In the second proposal, EPA suggests that any fossil fuel-burning 
generating entity seeking service under open access transmission 
tariffs would be required to commit by an enforceable contractual 
undertaking that it will avoid or offset emission increases (measured 
against as yet undetermined baselines), and periodically certify its 
compliance with that commitment. Middlemen would have a similar 
obligation. The generator could meet its emission limits either by 
making verified emission reductions within its own facilities or by 
obtaining eligible emissions offsets from other entities. An important 
element of the mitigation mechanism is the emissions baseline above 
which mitigation would be required. This mitigation mechanism would 
operate until superseded by appropriate programs addressing these 
pollution problems under other authority. EPA's own comments on the 
DEIS recognize that there may be substantial practical complexities in 
implementing such mechanism.
    The Joint Commenters propose a flexible mitigation strategy 
pursuant to which FERC would require as part of open access 
transmission a demonstration that NO<INF>X emissions would not be 
increased. To qualify for open access transmission access, an electric 
generating unit would be

[[Page 21681]]

responsible for mitigating any excess NO<INF>X emissions that adversely 
affect ozone non-attainment areas. Utility systems would be able to 
comply by use of emission control technology, fuel changes, or other 
measures to reduce applicable emissions, or by buying appropriate 
emission reduction credits to offset excess emissions. To comply with 
this policy, a company would need first to calculate whether it had 
excess emissions for the ozone season. A company that failed to 
mitigate would be required to remit to a regional emissions fund all 
revenues in excess of the incremental operating cost of producing 
electricity sold under the open transmission access policy during the 
previous ozone season plus an emissions make-up penalty the following 
year patterned after the penalty for excess emissions in the Acid Rain 
Program. The proposed mitigation policy would apply generally 
throughout the OTAG region.
    The outlines of Sustainable FERC's proposal are vague, but it 
appears to request that FERC, either singly or in combination with 
other agencies, eliminate the different environmental standards that 
apply to entities participating in open access transmission. This plan 
would include the reporting of emissions data to EPA, principles to 
eliminate the adverse impacts of non-comparable environmental 
standards, and an EPA-administered emissions monitoring process 
designed to determine whether generating plant emissions of specific 
pollutants under open access exceed designated baselines.
    Finally, DOE proposes action under the Clean Air Act as the most 
effective mitigation of the inter-regional NO<INF>X transport problem. 
DOE supports the activities of OTAG and believes that a regional 
NO<INF>X cap and trading system is a particularly promising approach. 
If OTAG does not succeed in addressing the problem, EPA should consider 
exercising its authority under sections 110 and 126 of the Clean Air 
Act, 42 U.S.C. 7410 and 7426, respectively, to require states to amend 
their State Implementation Plans to reach the same result.
    The proposals advanced by CCAP, EPA, Sustainable FERC, and Joint 
Commenters suffer from practical and legal problems that render them 
unworkable. A common thread is for the Commission to ``level the 
environmental playing field.'' ``Impacts of non-comparable 
environmental standards'' are not impacts of this rule, but rather of 
the Clean Air Act regulations and statutory requirements under which 
those standards have been imposed. We have no authority to ``level'' 
the different emissions standards for different types of power plants, 
when those differences in standards are the direct result of the 
program adopted in the Clean Air Act and regulations promulgated by 
EPA. In enacting the Clean Air Act, Congress chose not to impose 
identical emission standards on all electric utility powerplants, but 
did create mechanisms for regulation of certain pollutants that can be 
used to ``level the playing field'' if that is appropriate clean air 
policy. For the Commission to presume to overturn those standards or 
seek to impose more stringent standards is something the Commission 
believes it cannot do.
    A fundamental problem that plagues several proposals is the 
difficulty in identifying causation. While it is generally accepted 
that there is a link between increased emissions in certain areas of 
the country and increases in ozone levels in other areas, that link is 
in many respects poorly understood. In particular, it is difficult to 
prove that emissions from a particular unit or particular system 
contribute to ozone noncompliance elsewhere. As a result, it is very 
difficult to establish an analysis that would support a certification 
that a particular power sale would have no incremental impact on ozone 
compliance.
    Similarly, the proposals tying ``emission neutrality'' to ``open 
access transactions'' seem to fundamentally misunderstand the operation 
of power markets and the role of open access tariffs in moving power 
from willing sellers to willing buyers. In particular, these proposals 
do not reflect the difficulty in identifying the transactions that are 
likely to result from the open access policies adopted in this rule. 
The rule does not authorize sales for resale of electric energy; 
rather, it establishes requirements for open access transmission, i.e., 
it requires utilities with monopoly control of transmission to make 
transmission service available to customers who want to buy power from 
someone other than the transmission owner. Open access will facilitate 
transactions where the transmission owner will not provide service. 
However, generators do not necessarily have to request service under a 
Commission ordered open access tariff to make specific sales. There are 
a number of ways to structure transactions where third party 
transmission service is either not necessary or is voluntarily 
available.<SUP>990 Even when open access tariffs are used, the sales 
are not always (or even often) sales from specific generators to 
specific buyers. Marketers or brokers can buy generation from any 
number of sources. They can also buy transmission service in blocks 
that may not be associated with specific sales. Service agreements can 
be executed that allow use of non-firm transmission service for 
transactions that are not even known at the time of the execution of 
the agreement.
---------------------------------------------------------------------------

    \990\ Indeed, over 100 utilities are now providing some form of 
open access on a voluntary basis.
---------------------------------------------------------------------------

    The rule envisions a world where transmission will be arranged with 
minimal transaction cost. Terms, conditions, rates, and even approvals 
often will be established far in advance of particular transactions. 
All other problems aside, requiring showings of the kind required by 
the various mitigation proposals would undermine the basic philosophy 
behind the rule, would make transactions much more difficult to engage 
in, would increase transaction costs, and would cause delays resulting 
in lost efficiencies. In addition, it would directly conflict with the 
Commission's responsibility under the FPA to remedy undue 
discrimination in jurisdictional services, which is the fundamental 
purpose of the rule.
    Another significant issue with several of the proposals is how to 
establish the baselines against which to measure emissions. 
Establishing such baselines is extremely difficult; EPA itself, for 
example, has not come to grips with these complexities. The picture is 
complicated by difficulties in identifying open access transactions 
that result from the policies implemented by this rule. For example, 
some utilities use holding company corporate structures in which 
generation assets are held in an affiliate that sells power at 
wholesale to the holding company's distribution affiliate. For these 
utilities, all retail native load service would be subject to 
environmental review under the mitigation proposals if the base were 
established by reviewing all wholesale sales. This would make the 
Commission responsible for addressing all NO<INF>X emissions from power 
plants for utilities with such corporate structures, a result that goes 
far beyond the stated goal of mitigating emissions that result from 
increased interstate trade facilitated by the rule.
    As the industry changes, new structures are emerging that will make 
any system that tries to keep track of wholesale sales even more 
difficult to administer. California is putting into place an industry 
structure that could see all generation in the state sold into a 
central pool and then sold again at wholesale to distributors. Other 
states

[[Page 21682]]

are contemplating retail market structures that are even more fluid 
than the California proposal. Differentiating between sales for resale 
that are for former retail customers and sales for resale that are for 
``new'' wholesale customers, and therefore somehow the result of open 
access policies, would be extremely difficult. In general, it is not 
easy to distinguish among growth in generation for native retail load, 
wholesale requirements customers, existing economy sales, and new sales 
that are facilitated by the rule, either for purposes of establishing a 
baseline or for tracking responsibility for emissions.<SUP>991
---------------------------------------------------------------------------

    \991\ We are also very concerned about the time and effort 
involved in developing the various programs suggested by commenters. 
The EPA and OTAG are working on the establishment of emissions 
standards, which action is an essential prerequisite to three of the 
proposals. However, developing those standards is among the 
challenges that EPA believes may take up to 10 years to complete. It 
simply makes no sense to delay the benefits of the rule (which has 
slight, if any, environmental impacts) during the period required 
for experts in the area to develop standards that, once established, 
can form the basis of a program under existing Clean Air Act 
authority.
---------------------------------------------------------------------------

    Joint Commenters proposal would have the Commission impose a 
revenue collection measure--in essence a tax on open access 
transmission. The Commission is authorized by the FPA to pass through 
costs, not to collect additional fees from entities utilizing programs 
established by the Commission. The payment of emission fees is outside 
the Commission's authority under the FPA.
    The FEIS concludes that mitigation by the Commission should not be 
undertaken in this rule because:

    <bullet> Any mitigation measures the Commission might undertake 
are not justified by the small impacts of the rule, which impacts 
are as likely to be beneficial as they are to be harmful;
    <bullet> The impacts of the proposed rule are dwarfed by the far 
larger ozone and NO<INF>X emission issues that either have nothing 
to do with the electric industry or will be unchanged by the rule or 
the larger open access program. We believe that it would be 
ineffective to address the NO<INF>X and ozone issues in a piecemeal 
way;
    <bullet> The NO<INF>X issue is part of a long-standing, 
difficult set of inter-regional environmental issues. 
Representatives of many interests have invested substantial efforts 
toward finding acceptable solutions through the OTAG process. Any 
mitigation the Commission might undertake could usurp EPA's mandate 
under the Clean Air Act and undermine progress towards comprehensive 
solutions sought by OTAG. This is not justified by impacts that are 
small and just as likely to be positive;
    <bullet> We do not agree that the frozen efficiency reference 
case should be substituted for the EIS base cases or that 
competitive forces will favor coal over the next 15 years. But even 
accepting these assumptions, emissions attributable to the rule are 
relatively small until well after the turn of the century. So, even 
accepting such assumptions, the staff believes it would be 
unreasonable for the Commission to adopt mitigation requirements as 
part of the final rule; to do so would be tantamount to assuming 
that EPA and OTAG will not implement reasonable control measures in 
the next ten to 15 years;
    <bullet> The Federal Power Act and NEPA, either singly or 
conjointly, do not authorize the Commission to adopt and implement 
the proposed mitigation measures. The Commission does not possess 
(and has no mandate to possess) expertise on the extremely difficult 
issues involved in atmospheric chemistry and transport. It is 
fundamentally an economic regulatory agency. As a result, any 
mitigation measures the Commission undertook would be based on less-
than-ideal information and analysis. It is unreasonable for the 
Commission to attempt such mitigation given the impacts found in 
this FEIS. This is especially true in light of the substantial 
additional research that EPA and OTAG are undertaking on the basic 
nature of the problem;
    <bullet> Some suggested mitigation measures that might work at 
the transaction level would undermine the purpose of the rule. There 
is no justification for endangering the substantial benefits 
projected from the rule to mitigate a problem that might not exist 
and that is, in any case, likely to be small.<SUP>992

    \992\ FEIS at 7-48.
---------------------------------------------------------------------------

    In sum, the rule is expected to have small impacts and those 
impacts are as likely to be beneficial as they are to be harmful. 
Therefore, mitigation is not required. In addition, processes are in 
place to address the pre-existing NO<INF>X problem--a problem that 
dwarfs any impacts the Rule might have. These processes are expected to 
address the underlying transport problems well before any potential 
harmful effects of the rule will develop.<SUP>993
---------------------------------------------------------------------------

    \993\ Many commenters state that the rule does not require 
mitigation and urge that a mitigation plan not be adopted. We would 
also note in light of the substantial number of comments opposing 
the proposition that we have mitigation authority, that any such 
mitigation measure we may choose to undertake would, in all 
likelihood, be subject to judicial review and the inevitable delays 
and uncertainties that accompany litigation. In the meantime, we 
would expect actions by OTAG and EPA to eclipse whatever action the 
Commission attempted to implement during this time.
---------------------------------------------------------------------------

    The mitigation measures that certain commenters urge the Commission 
to adopt are truly unwarranted in light of these facts. They also fail 
to recognize or adequately consider the Commission's limited 
jurisdiction, its lack of expertise required to assess and address the 
underlying problem, the existing mechanisms and efforts to address the 
underlying problem, and the balance that has been reached and continues 
to be defined by the many interests that have invested substantial 
efforts toward finding acceptable solutions to these problems.
3. Legal and Policy Considerations
    The FEIS concludes that the mitigation measures recommended by 
commenters are beyond our authority to implement and that strong policy 
considerations militate against their adoption. We agree.
    Several commenters contend that the Commission is authorized to use 
the rulemaking as a vehicle to impose an air emissions regulatory 
regime on the electric utility industry.<SUP>994 Others argue that, as 
a matter of law and policy, we cannot and should not impose such 
measures.<SUP>995 While the conditioning proposals vary in specifics, 
all have as their central theme that generators would be forced to 
agree to operate generation facilities in a manner to reduce air 
pollution below levels currently authorized by EPA and the 
states.<SUP>996
---------------------------------------------------------------------------

    \994\ Alliance for Affordable Energy, et al. (Alliance); EPA; 
Project for Sustainable FERC Energy Policy (Project for Sustainable 
FERC); and Northeast States For Coordinated Air Use Management 
(NESCAUM).
    \995\ See, e.g., AEP at 3; CINERGY at 8-9; Entergy at 11-13; GPU 
at 2; Midwest Ozone Group at 3; NMA at 5-8; Ohio Consumers' Counsel 
at 5; Ohio PUC at 1; TVA at 8; and WEPCO at 2. See also CCEM 
Supplemental Comments at 1-5.
    \996\ See, e.g., CCAP (FERC should establish an emissions 
monitoring program and implement an emission neutrality 
requirement); EPA (either deny open access service unless the 
customer demonstrates no adverse environmental impact or require, 
through contract terms, any generating entity seeking open access 
service to avoid or offset emission increases for the benefit of 
third parties); Joint Commenters (electric generators to qualify for 
open access must be held responsible for mitigating any excess 
NO<INF>X emissions through a revenue collection measure); Project 
for Sustainable FERC (pro forma tariffs to contain environmental 
mitigation measures imposed on generators). See generally, FEIS at 
7-28 to 7-42.
---------------------------------------------------------------------------

    The Commission's authority to regulate public utilities is set out 
in Parts II and III of the FPA. Parts II and III do not provide the 
Commission with the authority to condition either the provision of, or 
access to, jurisdictional services on the agreement to undertake 
environmental mitigation measures.<SUP>997 Section 201, which is found 
in Part II of the FPA, explicitly bars the Commission from exercising 
the jurisdiction that the proponents of the conditioning

[[Page 21683]]

proposals would have us undertake: authority over the operation of 
generating facilities. Section 201(b)(1) provides that:

    \997\ Parts II and III of the FPA originated with the Public 
Utility Act of 1935, 49 Stat. 803, 838 (Aug. 26, 1935) and stemmed 
in part from the financial abuses in the utility industry in the 
late 1920s and early 1930s. See Report of National Power Policy 
Committee on Public-Utility Holding Companies, S. Rep. No. 621, 
Appendix, 74th Cong., 1st Sess. 55-60 (1935); see also H.R. Rep. No. 
1318, 74th Cong., 1st. Sess. 1-3 (1935). The FPA has been amended 
several times, most recently by the Energy Policy Act of 1992.
---------------------------------------------------------------------------

    The Commission shall have jurisdiction over all facilities for 
(the transmission of electric energy in interstate commerce) or 
(the) sale of electric energy (at wholesale in interstate commerce), 
but shall not have jurisdiction, except as specifically provided in 
(Parts II and III), over facilities used for the generation of 
electric energy * * *. (emphasis added).

    This standard is reflected throughout Parts II and III of the FPA. 
Sections 205 and 206, which are the cornerstones of Parts II and III, 
concern the regulation of rates, terms and charges occurring in 
connection with transmission or sales subject to the Commission's 
jurisdiction. Parts II and III do not grant the Commission authority to 
regulate the environmental aspects of jurisdictional 
activities.<SUP>998 Instead, they provide authority over certain 
interconnections; <SUP>999 the rates, terms and conditions of wholesale 
sales of electric energy in interstate commerce and transmission in 
interstate commerce; the disposition and merger of facilities used for 
such sales and transmission; issuance of securities; accounting 
matters; and interlocking directorates. Thus, the Commission's 
jurisdiction over generation extends only to matters directly related 
to the economic aspects of transactions resulting from such 
facilities.<SUP>1000 We do not have jurisdiction over the physical 
aspects of generation facilities.<SUP>1001
---------------------------------------------------------------------------

    \998\ The statutory framework established by Congress in 
sections 205 and 206 is not compatible with the administration of 
environmental regulatory regimes as a precondition to authorization. 
The Commission has only 60 days to review rate filings under section 
205 before they become effective. Absent Commission action rejecting 
a rate filing or suspending its operation for up to five months 
within such period, a jurisdictional transaction (either the sale of 
energy or the transmission of energy) and the proposed rates 
accompanying the transaction go into effect by operation of law. 
Some mitigation proposals would require us to reject transactions 
within 60 days or allow them to go forward but with case-by-case 
determinations or hearings on environmental effects made within that 
time period. This could result in transaction gridlock for the trade 
of electricity in interstate commerce--a situation that is totally 
at odds with the regulatory framework established by Congress in the 
FPA and the Commission policy objectives under this rule to minimize 
regulatory impediments to fluid competitive power sales markets. 
Moreover, letting transactions go into effect subject to 
environmental hearings is not likely to produce meaningful 
environmental controls. Clearly, our processes, which contemplate 
the resolution of factual matters through hearings and the use of 
refund obligations to adjust parties' obligations on the basis of 
the record, make no provision for extensive scientific inquiry and 
are not designed to accommodate the imposition of clean air 
standards on power sellers.
    \999\ See FPA section 202(b), 16 U.S.C. 824c(b). See also 
Department of Energy Organization Act, 42 U.S.C. 7151, 7172.
    \1000\ We also note that section 731 of the Energy Policy Act 
preserves state and local authority over environmental protection 
and the siting of facilities.
    \1001\ For example, we do not have jurisdiction over the 
physical location of generation or transmission facilities, even 
though we have exclusive jurisdiction of the rates, terms and 
conditions of sales for resale or transmission of electric energy in 
interstate commerce by public utilities using such facilities, i.e., 
the economic aspects of the use of such facilities.
---------------------------------------------------------------------------

    This limitation on the Commission's jurisdiction stems from the 
historical purposes for which the Commission was established. Congress 
had two objectives in expanding the authority of the Federal Water 
Power Commission in 1935.<SUP>1002 The first was to close the gap 
created by Public Utilities Commission v. Attleboro Steam & Electric 
Co., 273 U.S. 83 (1927)(Attleboro), in which the Court found that under 
the Commerce Clause states could not regulate wholesale sales of 
electricity in interstate commerce. The result was a gap in regulation 
of such sales because there was no federal entity with authority to 
regulate them at that time. The second was to eliminate the economic 
abuses that were then rampant in the industry.<SUP>1003 In expanding 
the Commission's jurisdiction Congress made clear that such Federal 
regulation, however, was ``to extend only to those matters which are 
not subject to regulation by the States.'' <SUP>1004
---------------------------------------------------------------------------

    \1002\ The Federal Water Power Commission was established in 
1920 with jurisdiction over the licensing of hydropower projects. 41 
Stat. 1063 (June 10, 1920). In 1935, it was reconstituted as the 
Federal Power Commission, with expanded responsibilities over 
utility regulation. The jurisdiction over the licensing of 
hydropower was preserved as Part I of the Federal Power Act.
    \1003\ See Report of National Power Policy Committee on Public 
Utility Holding Companies.
    \1004\ FPA section 201(a), 16 U.S.C. 824(a). The House, Senate 
and Conference Reports concerning the Public Utility Act of 1935, 
i.e., concerning Parts II and III of the FPA, are silent with 
respect to environmental concerns.
---------------------------------------------------------------------------

    Several commenters argue nonetheless that the Commission may do 
indirectly what it is barred from doing directly. Their arguments boil 
down to the claim that the Commission's responsibility under the FPA to 
act in the ``public interest'', either alone or in conjunction with 
NEPA, provides the Commission with the authority to impose 
environmental regulation on generators to address the supposed impacts 
of the Rule.<SUP>1005 We disagree. In making this argument, the 
commenters attribute to that standard a breadth of discretion that 
vastly exceeds the traditional ambit of our authority.
---------------------------------------------------------------------------

    \1005\ See, e.g., comments by EPA, Project for Sustainable FERC, 
and Attorneys General.
---------------------------------------------------------------------------

    It is well established that NEPA merely establishes a procedural 
vehicle for assessing the impacts of a proposed action on the 
environment. It neither expands nor contracts the basic grant of 
jurisdiction made by Congress to the agency conducting the review, and 
it does not mandate particular results but simply prescribes a 
process.<SUP>1006 Commenters' arguments that NEPA somehow ``fills in 
the blanks'' of the FPA to authorize us to impose environmental 
regulatory regimes on generating facilities, or those who may purchase 
power from them, is simply incorrect. If we have such authority, it 
must be found in our substantive statute, the FPA.
---------------------------------------------------------------------------

    \1006\ See, e.g., Methow Valley, 490 U.S. at 350-53; see also, 
LaFlamme v. FERC, 852 F.2d 389, 399 (9th Cir. 1988).
---------------------------------------------------------------------------

    Courts have addressed the breadth of our public interest standard 
on several occasions. The principal case on this point is National 
Association for the Advancement of Colored People v. FPC 520 F.2d 432 
(D.C. Cir. 1975), aff'd, 425 U.S. 662 (1976) (NAACP). In NAACP, a 
number of organizations requested that the Commission promulgate 
regulations requiring equal employment opportunity and proscribing 
racial discrimination in the employment practices of public 
utilities.<SUP>1007 The Commission declined, finding that the FPA did 
not authorize it to do so. Petitioners appealed, contending that the 
Commission was authorized and required to act in the public interest:

    \1007\ NAACP, 520 F.2d at 433.
---------------------------------------------------------------------------

to order such interconnections of electric power transmission 
facilities, setting such terms and conditions for the same, as are 
``necessary or appropriate in the public interest''; to approve such 
asset sales and consolidations of interstate electric power 
companies as are ``consistent with the public interest; to approve 
such securities issuances by those companies as are ``compatible 
with the public interest'' and ``consistent with the proper 
performance * * * of service as a public utility''; to determine 
``just and reasonable'' rates for interstate sales and transmission 
of electric power; and to order that ``proper, adequate or 
sufficient'' interstate power service be rendered.<SUP>1008

    \1008\ Id. at 437-38 (footnotes omitted). The authorities listed 
cover FPA sections 202, 203, 204, 205, 206, and 207.
---------------------------------------------------------------------------

On this basis, they argued that because prohibition of discrimination 
is in the ``public interest,'' the Commission was therefore required to 
proscribe discrimination by jurisdictional entities.
    The Court rejected petitioners' argument. It observed that:

the (Federal Power) Act's preamble echoes the generality of the 
foregoing quoted

[[Page 21684]]

phrases, declaring that the sale and transmission of electric power 
are ``affected with the public interest,'' federal regulation of 
interstate aspects being ``necessary in the public interest.'' The 
statute itself nowhere defines the ``public interest,'' but instead 
leaves the precise ambit of the Commission's concern 
uncertain.<SUP>1009

    \1009\ Id. at 438 (footnote omitted).
---------------------------------------------------------------------------

The Court found from the entirety of the Act that, ``(o)f the 
Commission's primary task there is no doubt, however, and that is to 
guard the consumer from exploitation by non-competitive electric power 
companies.'' <SUP>1010 The Court reiterated that ``(t)he Supreme Court 
has stated that the words `public interest' do not constitute a `mere 
general reference to the general welfare, without any standard to guide 
determinations.' '' <SUP>1011 Significantly, the Court also found that 
``(w)ords like `public interest' * * * though of wide generality, take 
their meaning from the substantive provisions and purposes of the 
Act.'' <SUP>1012 The Court concluded that:

    \1010\ Id.
    \1011\ Id. at 440, citing New York Central Securities Co. v. 
United States, 287 U.S. 12, 24 (1932).
    \1012\ Id., quoting Alabama Electric Cooperative, Inc. v. SEC, 
353 F.2d 905, 907 (1965), cert. denied, 383 U.S. 968 (1966).
---------------------------------------------------------------------------

Congress has not charged the Commission with advancing all public 
interests, but only the public's interest in having the particular 
mandates of the Commission carried out, its interest, in other 
words, in the conservation of natural resources and the enjoyment of 
cheap and plentiful electricity and natural gas. <SUP>1013

    \1013\ Id. at 441 (emphasis in original). The Court made clear 
that ``the conservation of natural resources'' was a Commission 
interest only with regard to the regulation of hydropower resources 
under Part I of the FPA. Id. at 437.
---------------------------------------------------------------------------

    With this, the Court rejected petitioners' argument that the FPA 
``public interest'' standard requires the Commission to promulgate 
regulations prohibiting discriminatory practices by entities who are in 
some way regulated by the Commission. The Court found that the 
Commission was not empowered to promulgate anti-discrimination 
regulations because to do so would not be ``reasonably related to the 
furtherance of the Commission's proper objectives,'' which, under Part 
II of the FPA, are ``the enjoyment of cheap and plentiful 
electricity.'' <SUP>1014
---------------------------------------------------------------------------

    \1014\ Id. at 443 and 441.
---------------------------------------------------------------------------

    On review, the Supreme Court affirmed this limited reading of the 
Commission's authority to act in the public interest.<SUP>1015 In doing 
so, the Court noted that:

    \1015\ NAACP, 425 U.S. 662 (1976).
---------------------------------------------------------------------------

    The use of the words ``public interest'' in the Gas and Power 
Acts is not a directive to the Commission to seek to eradicate 
discrimination, but, rather, is a charge to promote the orderly 
production of plentiful supplies of electric energy and natural gas 
at just and reasonable rates.<SUP>1016

    \1016\ Id. at 670 (footnote omitted). Several commenters, e.g., 
Project for Sustainable FERC at 31-32 and Alliance at 53, make much 
of the Court's statement that there are undoubtedly other subsidiary 
purposes contained in the FPA and NGA, noting its reference in a 
footnote that the Commission has authority to consider 
``environmental'' questions. NAACP, 425 U.S. at 670 n.6. However, 
they neglect to mention that the section of the FPA which the Court 
identified in support of this reference to environmental questions 
is section 10 of the FPA concerning our Part I authority over 
hydroelectric licensing matters, not Parts II and III. Part I 
contains explicit authority for the Commission to consider and 
require environmental mitigation measures.
---------------------------------------------------------------------------

    The question the Supreme Court asked in NAACP is the appropriate 
question here concerning the commenters' environmental mitigation 
proposals:

    The question presented is not whether the elimination of 
discrimination from our society is an important national goal. It 
clearly is. The question is not whether Congress could authorize the 
Federal (Energy Regulatory) Commission to combat such 
discrimination. It clearly could. The question is simply whether and 
to what extent Congress did grant the Commission such 
authority.<SUP>1017

    \1017\ NAACP, 425 U.S. at 665.
---------------------------------------------------------------------------

We believe the same conclusion is true here for air pollution as the 
Court found there regarding discrimination.<SUP>1018
---------------------------------------------------------------------------

    \1018\ In analyzing the scope of the Commission's authority to 
act in the public interest, the NAACP Court found it useful to 
analogize to federal labor law. While noting that Congress had 
``unmistakably defined the national interest in free collective 
bargaining,'' Id. at 671, the Court found that it could not be 
supposed that in directing the Commission to be guided by the 
``public interest,'' Congress instructed the Commission ``to take 
original jurisdiction over the processing of charges of unfair labor 
practices on the part of its regulatees.'' Id. Yet this is exactly 
the form of what EPA and the other commenters supporting our 
authority to require environmental mitigation would have us do. 
However, just as with discriminatory employment practices, we can 
consider the consequences of air pollution practices of our 
regulatees ``only insofar as such consequences are directly related 
to the Commission's establishment of just and reasonable rates in 
the public interest.'' Id. (emphasis added).
---------------------------------------------------------------------------

    The argument by EPA and others that because the FPA authorizes the 
Commission to act in the ``public interest'' it somehow authorizes the 
Commission to impose environmental mitigation measures is virtually 
indistinguishable from petitioners' argument in NAACP.<SUP>1019 Here, 
as in NAACP, parties urge the Commission to act to achieve worthwhile 
goals. However, the question is not whether the measures proposed by 
the parties would advance important national goals. Rather, ``[t]he 
question is simply whether or to what extent Congress did grant the 
Commission such authority.'' <SUP>1020 Also here, as in NAACP, the 
parties improperly base their belief that the Commission has authority 
to act under the FPA on an incorrect, overly broad application of the 
``public interest'' standard. The goals sought to be advanced by EPA 
and others are broadly speaking ``in the public interest,'' but they 
are not goals that Congress has directed this Commission to 
pursue.<SUP>1021 Thus, just as the FPA did not authorize the Commission 
to take actions that petitioners requested in NAACP, the FPA does not 
authorize the Commission to undertake the types of environmental 
mitigation measures proposed by the commenters.<SUP>1022
---------------------------------------------------------------------------

    \1019\ We note that the standard the Commission is bound to 
apply in reviewing section 205 and section 206 transactions (which 
are the focus of the majority of commenters' mitigation proposals) 
is not a broad ``public interest'' standard, but rather a standard 
that rates, terms and conditions of such transactions be ``just, 
reasonable and not unduly discriminatory or preferential.'' 16 
U.S.C. 824d, 824e.
    \1020\ NAACP, 425 U.S. at 665.
    \1021\ The limited nature of the Commission's ability under 
NAACP to consider ``environmental'' issues is reflected in the few 
court decisions on this subject. See Public Utility Commission of 
California v. FERC, 900 F.2d 269, 281 (D.C. Cir. 1990) (The broad 
public interest standards in the Commission's enabling legislation 
are limited to ``the purposes that Congress had in mind when it 
enacted this (NGA and FPA) legislation. This rule helps confine an 
agency's authorization ``to those areas in which the agency fairly 
may be said to have expertise.''); Process Gas Consumers Group v. 
FERC, 930 F.2d 926, 935 & n.14 (D.C. Cir. 1991) (Commission 
improperly allowed in rates the costs of research intended to 
benefit ratepayers solely through a ``cleaner environment''; the 
Court found that the Commission has no particular ``expertise'' in 
determining and promoting the pollution-reducing effects of natural 
gas vehicles).
    \1022\ The Supreme Court's holding in NAACP as to the limited 
ability of administrative agencies to implement broad ``public 
interest'' mandates, and direction to refrain from straying beyond 
the specific purposes of the regulatory legislation they are 
entrusted to administer, is well established. See Community 
Television of Southern California v. Gottfried, 459 U.S. 498, 510-11 
n.17 (1983) (``[A]n agency's general duty to enforce the public 
interest does not require it to assume responsibility for enforcing 
legislation that is not directed at the agency''); Hampton v. Mow 
Sun Wong, 426 U.S. 88, 114 (1976) (``It is the business of the Civil 
Service Commission to adopt and enforce regulations which will best 
promote the efficiency of the federal civil service. That agency has 
no responsibility for foreign affairs, for treaty negotiations, for 
establishing immigration quotas or conditions of entry, or for 
naturalization policies''); McLean Trucking Company v. United 
States, 321 U.S. 67, 79 (1944) (that Congress ``has vested expert 
administrative bodies such as the Interstate Commerce Commission 
with broad discretion and has charged them with the duty to execute 
stated and specific statutory policies'' does not ``necessarily 
include either the duty or the authority to execute numerous other 
laws'' beyond enumerated statutory responsibilities); see also Bob 
Jones University v. United States, 461 U.S. 574, 611 (1983) (Powell, 
J., concurring) (``This Court often has expressed concern that the 
scope of an agency's authorization be limited to those areas in 
which the agency fairly may be said to have expertise'').
    Lower courts have repeated the Court's admonition in this regard 
on numerous occasions in finding that federal agencies improperly 
have overstepped, or properly have refrained from overstepping, the 
limitations of their ``public interest'' (or similarly worded) 
jurisdiction. See, e.g., The Business Roundtable v. Securities and 
Exchange Commission, 905 F.2d 406, 413-14 (D.C. 1990) (SEC's 
assertion of authority under ``public interest'' standard to bar 
national security exchanges and associations from listing stock of 
certain corporations invaded traditional state regulatory purview); 
Public Utility Commission of California v. FERC, 900 F.2d 269, 281 
(D.C. Cir. 1990) (FERC has no authority to consider allegations of 
copyright infringement or unfair trade practices in determining 
whether to issue certificates of public convenience and necessity); 
American Trucking Association v. United States, 642 F.2d 916 (5th 
Cir. 1981) (intention of ICC to promote competition is consistent 
with statutory standard; more generalized intention to promote 
public welfare needs, unrelated to its legislative instruction to 
attend to transportation needs of the public, is not); Natural 
Resources Defense Council, Inc. v. Securities and Exchange 
Commission, 606 F.2d 1031 (D.C. Cir. 1979) (SEC has no obligation to 
promulgate regulations requiring comprehensive disclosure of (among 
other things) corporate environmental policies unrelated to 
objectives of federal securities laws); Sunflower Electric 
Cooperative, Inc. v. Kansas Power & Light Company, 603 F.2d 791, 799 
(D.C. Cir. 1979) (FERC does not have primary jurisdiction to 
consider antitrust-related issues that do not involve rate-setting 
practices of public utilities); O-J Transport Company v. United 
States, 536 F.2d 126, 131-32 (6th Cir.), cert. denied, 429 U.S. 960 
(1976) (ICC properly did not stray beyond its congressionally-
defined role over transportation regulation by refusing to promote 
more generalized public welfare concerns); see also, e.g., In re 
Multidistrict Vehicle Air Pollution, 538 F.2d 231 (9th Cir. 1976) 
(under antitrust laws, federal district court has no authority to 
fashion an environmental remedy, intended to reduce auto emissions, 
that serves no antitrust purpose).

---------------------------------------------------------------------------

[[Page 21685]]

    The Project for Sustainable FERC argues that in Richmond Power & 
Light v. FERC, 574 F.2d 610, 616-17 n.22 (D.C. Cir. 1978) (Richmond 
Power), the Court ``suggested'' a broader agency latitude than 
described in NAACP.<SUP>1023 We disagree.
---------------------------------------------------------------------------

    \1023\ Project for Sustainable FERC at 31.
---------------------------------------------------------------------------

    Richmond Power involved a case where the Commission was challenged, 
inter alia, because it declined to adopt a particular transmission rate 
that would have permitted Richmond to shift from oil to some other 
fuel. The Court affirmed the Commission's decision, finding that:

    Although the Commission must serve the public interest in 
approving rates, we see no abuse of discretion in limiting this 
proceeding to the shortrun problem of setting just and reasonable 
rates for the service theretofore provided in response to the 1973 
oil embargo. While an administrative agency must remain faithful to 
public policies directly related to its regulatory authority, surely 
at any given moment of history it may rationally decline to 
affirmatively foster other policies in weighing the specific 
interests that it is required by the statute to consider. This is 
especially true when the forum chosen by proponents of the other 
policy is not well suited to the study of its implications.<SUP>1024

    \1024\ Richmond Power, 574 F.2d at 616-17 (footnotes omitted).
---------------------------------------------------------------------------

In dicta, in a footnote that began with the Court doubting whether 
the goal of energy independence is within the Commission's 
regulatory jurisdiction at all, the Court merely said that 
``(n)othing in NAACP v. FPC, supra, forecloses agency discretion to 
consider in given situations pervasive public policies that it is 
not required to evaluate in every decision it makes.'' <SUP>1025
---------------------------------------------------------------------------

    \1025\ Id. at 616 n.22 (emphasis added).
---------------------------------------------------------------------------

    The discretion to consider public policy matters is a far cry from 
the authority, or obligation, to regulate those matters. We have 
considered the environmental impact of the rule. Nothing in Richmond 
Power suggests that the consideration of such matters conveys an 
affirmative grant of broad new regulatory powers to develop and 
implement a comprehensive regulatory program in an area expressly 
assigned by Congress to another agency.<SUP>1026
---------------------------------------------------------------------------

    \1026\ Alliance and the Project for Sustainable FERC cite 
American Trucking Association, Inc. v. United States, 642 F.2d 916 
(5th Cir. 1981), to support an argument that, even under NAACP, the 
Commission can impose conditions under the FPA ``public interest'' 
standard because there is a ``nexus'' between the primary goals of 
the FPA and the proffered conditions. As discussed below in greater 
detail, we disagree.
    American Trucking involved review of an ICC rulemaking effort 
to, among other things, allow government agencies to tender a fair 
portion of their freight shipments to small businesses and those 
operated by disadvantaged persons. In reviewing the case, the Court 
referenced the NAACP decision to observe that under the governing 
law, the ICC's ``useful purpose'' and ``public need'' criterion 
(used here to justify the regulations) do ``not (refer) to the 
pursuit of affirmative action goals.'' Id. at 921-922. Indeed, it is 
clear that the Court read NAACP as permitting the consideration of 
``racial, ethnic and social-economic factors'' only when they relate 
to the matters within the ICC's authority, i.e., the transportation 
needs of the public, as opposed to some generalized notion of the 
general public welfare. Id. at 922 n.3.
---------------------------------------------------------------------------

    The cases rejecting commenters' broad reading of our public 
interest authority are supported by the decision in Office of 
Consumers' Counsel v. FERC, 655 F.2d 1132 (D.C. Cir. 1980) (Great 
Plains). There, the Court found that, even under the explicit ``public 
interest'' standard in section 7(a) of the Natural Gas Act, the 
Commission is not granted power to act on matters outside of its 
statutory mandate.<SUP>1027
---------------------------------------------------------------------------

    \1027\ NGA section 7(a), like, for example, FPA section 203(a), 
provides for a ``public interest'' standard of review. Section 7 of 
the NGA represents the maximum authority the Commission has over 
environmental issues under that Act. Section 7 provides the 
Commission authority to approve the siting and construction of 
facilities.
---------------------------------------------------------------------------

    In Great Plains, the Court reviewed a Commission decision to grant 
a certificate of public convenience and necessity to facilitate 
construction and operation of a coal gasification plant. Although the 
NGA does not explicitly provide the Commission with authority to 
certificate coal gasification projects, the Commission reasoned that it 
had such authority because the demonstration project was ``in the 
public interest'' and, because the Commission was authorized under 
section 7 of the NGA to ``consider'' all factors in reaching a decision 
on whether to grant the certificate, it had the requisite authority to 
act.
    The Court rejected the Commission's reasoning in that case, stating 
that:

    Any such authority to consider all factors bearing on the 
``public interest'' must take into account what the ``public 
interest'' means in the context of the Natural Gas Act. FERC's 
authority to consider all factors bearing on the public interest 
when issuing certificates means authority to look into those factors 
which reasonably relate to the purposes for which FERC was given 
certification authority.<SUP>1028
---------------------------------------------------------------------------

    \1028\ Great Plains, 655 F.2d at 1147.

The Court repeated the finding in NAACP that the Commission's authority 
to act in the public interest is limited to the furtherance of the 
purposes for which its organic statutes were adopted.<SUP>1029
---------------------------------------------------------------------------

    \1029\ Id.
---------------------------------------------------------------------------

    In concluding that the Commission was not authorized to act as it 
did, the Court looked to several factors. The Court found it persuasive 
that Congress had specifically authorized a different governmental 
entity, the Synthetic Fuels Corporation, to provide support for coal 
gasification, and that Congress had carefully crafted a special means 
for providing federal financial assistance for synfuel 
development.<SUP>1030 The Court also found it persuasive that the 
Commission possessed no expertise in making determinations regarding 
the relative merits of different synfuel processes, methods or 
technologies, and that the financing arrangements ``were certainly not 
ordered with the interests of ratepayers foremost in mind.''<SUP>1031 
The Court stated that ``by utilizing its statutory tools for a non-
statutory purpose, FERC very likely was distracted from its primary 
statutory duty to protect the interests of ratepayers.'' <SUP>1032 
Finally, the Court found that the Commission's action seemed to have 
been prompted at least in part by an attitude that, because Congress 
had not acted speedily, the Commission could act. The Court criticized 
the Commission for improperly attempting to preempt Congressional 
action and to ``fill in''

[[Page 21686]]

where the agency believed federal action was needed.<SUP>1033
---------------------------------------------------------------------------

    \1030\ Id. at 1150.
    \1031\ Id. at 1151.
    \1032\ Id.
    \1033\ Id. at 1151-52.
---------------------------------------------------------------------------

    The facts and reasoning in Great Plains are directly analogous to 
this proceeding. Congress has specifically authorized other entities--
EPA and the states--under other statutes to address air pollution. The 
Commission is being urged to regulate in an area in which, as in Great 
Plains, it possesses no special expertise (i.e., in making 
determinations regarding appropriate air pollution control mitigation 
measures) and in which it is not authorized to act.<SUP>1034 Finally, 
as in Great Plains, if the Commission were to undertake mitigation, it 
would be diverted from its primary statutory duty to protect the 
economic interests of ratepayers, i.e., by having to continually 
monitor compliance with mitigation conditions.<SUP>1035
---------------------------------------------------------------------------

    \1034\ To our knowledge the only time Congress has asked the 
Commission with respect to its regulation under Parts II and III of 
the FPA to address environmental issues was in Section 808 of the 
Clean Air Act Amendments of 1990. There, Congress directed the 
Commission, in consultation with EPA, to study the environmental 
externalities of electricity production. The Commission staff did so 
and provided the required report to Congress. While the Commission 
in compliance with the 1990 Amendments also addressed the accounting 
issues related to SO<INF>2 emissions trading, the Commission did so 
within the context of its accounting authority under the FPA.
    \1035\ EPA argues that the Commission would not be required to 
monitor compliance with the environmental mitigation measures. 
However, if environmental mitigation is within our statutory 
mandate, we could not delegate that authority to others. See EPA at 
51.
---------------------------------------------------------------------------

    As in Great Plains, the Commission is being urged to act at least 
in part because of the belief that Congress has not provided a 
sufficiently speedy process by which to regulate air pollution produced 
by electric utilities. The EPA argues that:

    Regulations under the Clean Air Act must in general be 
implemented through State Implementation Plans; the time from 
reaching a general conclusion that control is needed to adoption of 
necessary regulations by states generally takes from three to five 
years; that regulatory lag time means compliance with new rules can 
be, and usually is, more than a decade from the point at which the 
problem occurred. Ten years of bad air is ten years delay too 
many.<SUP>1036
---------------------------------------------------------------------------

    \1036\ EPA at 4-5; see also Project for Sustainable FERC 
(protections achieved by the Clean Air Act Amendments of 1990 are in 
danger of being destroyed by the Energy Policy Act's open access 
policies if those policies are implemented without environmental 
mitigation).
    We would also note that the premise upon which EPA makes this 
argument--that air emissions will rapidly increase with 
implementation of the rule--is not supported by the record. See 
Section V, Discussion, Subsection C.

That Congress has imposed upon the EPA procedures that the EPA and 
others find burdensome and overly time consuming is an issue for 
Congress and EPA to address, not the Commission.<SUP>1037
---------------------------------------------------------------------------

    \1037\ We believe that this conclusion is supported by section 
205(a) of the Public Utility Regulatory Policies Act of 1978 
(PURPA). PURPA, inter alia, amended the FPA in certain respects but 
also gave the Commission authority in certain sections, such as 
PURPA sections 205(a) and 210, that did not amend the FPA. Under 
PURPA section 205(a), the Commission in certain circumstances may 
exempt electric utilities, in whole or in part, from state laws, 
rules or regulations which prohibit or prevent voluntary 
coordination, including agreements for central dispatch. (Of course, 
the central dispatch is dispatch of generation facilities.) However, 
PURPA section 205(a)(2) provides that no exemption may be granted if 
the state law, rule or regulation is designed, among others, to 
protect public health, safety or welfare or the environment. In 
commenting on the limitation of the Commission's exemption authority 
under PURPA section 205(a), the Conferees noted that the prohibition 
includes ``regulations under the Clean Air Act.'' H.R. Conf. Rep. 
No. 1750, 95th Cong., 2d Sess. 95 (1978), reprinted in 1978 U.S. 
Code Cong. & Ad. News 7797, 7829. While the Commission's statutory 
authority has been modified in legislation enacted subsequent to 
PURPA, the provisions of PURPA section 205(a) have not been 
modified.
---------------------------------------------------------------------------

    This conclusion has particular force when, as here, we are urged to 
impose environmental restrictions on certain coal-fired generators in 
spite of Congressional actions regulating those entities. In essence, 
some commenters argue that under a very tenuous connection to the 
public interest standard of the FPA we may undertake to do more than 
the agency that Congress has authorized to act on such matters. This 
result is not a correct reading of the law and we reject it.
    Several commenters attempt to overcome the various Courts' views of 
the scope of the public interest standard under the FPA by arguing that 
there is a ``direct nexus'' between the Rule and environmental concerns 
that suffices to invoke an imputed authorization under the FPA to 
prescribe environmental requirements on generators.<SUP>1038 To this 
end, they argue that the purpose of the rule is really to facilitate 
the least-cost use and construction of generation resources and that 
the environmental consequences of these actions will impact economic 
efficiency, rates, competition, and competitive markets. Thus, they 
conclude that we have the authority to require that those who seek to 
obtain transmission access on a non-discriminatory basis must first 
mitigate air emissions under as yet undefined standards.
---------------------------------------------------------------------------

    \1038\ See, e.g., EPA at 54. See also Alliance; Project for 
Sustainable FERC; Coalition; Signatories; CCAP; Attorneys General.
---------------------------------------------------------------------------

    These commenters misstate the question. The question is not whether 
there is a nexus between the rule and environmental concerns. Clearly, 
electric utilities contribute to pollution; anything that facilitates 
the sale of power from whatever source is, under this tenuous logic, 
``related'' to environmental concerns.<SUP>1039
---------------------------------------------------------------------------

    \1039\ Under this logic, the Securities and Exchange Commission, 
for example, which facilitates utility financing for new facilities 
would be empowered to administer environmental requirements.
---------------------------------------------------------------------------

    However, as discussed below, Congress did not give us plenary 
powers over public utilities to shape their activities in response to a 
broad range of public policy concerns. The nexus that must be 
established is a nexus between the requirements sought to be imposed, 
in this case emission controls, and the statutory standards which 
authorize us to act. That is, in order to impose the environmental 
conditions sought by commenters, a direct connection must be 
established between those conditions and our duty to determine that the 
rates, terms and conditions of service under our open access tariffs 
are not unjust, unreasonable, unduly discriminatory, or preferential.
    It is on this point that commenters' arguments founder. While the 
Commission has broad latitude to interpret these standards to advance 
the interests of ratepayers, we cannot implement policy objectives that 
are not assigned to us and that are, in fact, clearly assigned to other 
entities. The Congress has assigned responsibility for environmental 
regulation of air quality to EPA and the states; it has explicitly 
charged them with dealing with such pollution from electric generating 
facilities. While, as noted earlier, we do not dispute the need to give 
appropriate weight to environmental considerations in making decisions 
within our authority, we cannot use that authority to accomplish public 
policy objectives that, by statute, are required to be implemented and 
administered by other agencies.<SUP>1040
---------------------------------------------------------------------------

    \1040\ We are also troubled by the confusion that persists as to 
the usefulness of imposing a condition on the use of open access 
tariffs as a means to accomplish environmental goals. As noted 
earlier, the Commission's decision to compel the filing of open 
access tariffs is intended to provide access to third party power 
suppliers who need access across a utility's transmission system. 
Open access will primarily benefit independent power suppliers 
offering power from new facilities, most of which under current 
market conditions are likely to be gas-fired facilities. Traditional 
utilities that own the generating plants of particular concern to 
commenters (i.e., coal-fired plants subject to less strict 
environmental controls) have extensive transmission systems that 
they can use to get power to market. Thus, the exercise of 
conditioning authority is more likely to impede sales from new, 
cleaner facilities than it is sales from older, coal-fired 
facilities. It makes no sense from an economic or environmental 
perspective to burden new transactions with this cumbersome 
condition for what will likely be little in the way of effective 
environmental controls.

---------------------------------------------------------------------------

[[Page 21687]]

    Some commenters have sought to address this issue by characterizing 
the proposed conditions as necessary to create a level competitive 
playing field among generators. For example, Alliance argues that 
unless the Commission requires environmental mitigation certain 
competitors in the bulk power market (those with ``dirty generation'') 
---------------------------------------------------------------------------
would be favored over ``clean'' competitors. It argues that:

    Mitigation of the environmental impacts resulting from the NOPR 
has a direct relationship to ensuring that open access is 
implemented under terms of economic fairness for all utilities and 
utility consumers, and not merely those with current low-cost 
regulatory advantages.<SUP>1041
---------------------------------------------------------------------------

    \1041\ Alliance at 55. See also Project for Sustainable FERC at 
37.

We note that all power generation technologies have different costs. 
For example, hydroelectric facilities which, like coal-fired 
facilities, may have environmental mitigation conditions imposed on 
them, may be quite expensive to build compared to gas or oil-fired 
generation, but their operating costs may be significantly lower. These 
cost differences may reflect the different costs of complying with 
mandated environmental requirements; the prudent costs of complying 
with such mandates may be reflected in rates.
    Indeed, sellers come to the power markets with a variety of 
advantages and disadvantages, many of which are the result of federal 
laws--for example, tax preferences, labor standards, and similar 
matters. In empowering the Commission to remedy undue discrimination 
and promote competition, Congress has not authorized the Commission to 
equalize the environmental costs of electricity production in order to 
ensure ``economic fairness.'' Such homogenization of competitors, or 
their costs, has never been a goal of the FPA.<SUP>1042
---------------------------------------------------------------------------

    \1042\ For the same reason, we do not have authority to impose 
an obligation on utilities to ``internalize'' environmental 
externalities. See generally FEIS at 7-24. In effect, such proposals 
would involve the Commission requiring a surcharge on power sales 
rates fixed at some amount equal to the environmental ``cost'' 
inflicted by the generation supporting those sales. Assuming such a 
surcharge could be calculated, imposing such a cost would be to fix 
a rate without reference to any cost incurred by the public utility. 
Indeed, we would impose in rates, and require ratepayers to pay, a 
cost that was manifestly not incurred by the utility. In reality, 
such a surcharge would require us to impose a tax or a penalty, 
neither of which we are authorized to impose.
    The SO<INF>2 program created under the 1990 Clean Air Act 
Amendments illustrates the way in which EPA and FERC authority can 
intersect to accomplish the goal of internalizing externalities. 
There, the Congress by capping emissions and providing for a market 
in emission allowances required utilities to ``pay for'' the right 
to emit SO<INF>2. These costs are legitimate costs and the 
Commission's role is to permit their recovery in rates. Similarly, a 
comparable NO<INF>X cap and trading scheme established by EPA would 
``internalize'' the external costs of NO<INF>X pollution and the 
Commission would provide for prudently incurred allowance costs in 
rates.
---------------------------------------------------------------------------

    In short, the ``economic nexus'' urged by commenters advocating 
that the Commission undertake to regulate air emissions is inconsistent 
with the ``charge to promote the orderly production of plentiful 
supplies of electric energy'' envisioned by the FPA.<SUP>1043
---------------------------------------------------------------------------

    \1043\ NAACP, 425 U.S. at 670.
---------------------------------------------------------------------------

    We have exercised conditioning authority in the past only where 
necessary to ensure that jurisdictional transactions and rates do not 
result in anti-competitive effects, or are not unjust, unreasonable or 
unduly discriminatory or preferential.<SUP>1044 Thus, the conditions we 
have imposed have involved economic regulatory matters within our 
purview under the FPA.<SUP>1045 Any exercise of conditioning authority 
must, as the Supreme Court noted in NAACP, be directly related to our 
economic regulation responsibilities; EPA and the other commenters have 
not demonstrated such a nexus.<SUP>1046
---------------------------------------------------------------------------

    \1044\ Cf. Utah Power & Light Co., Opinion No. 318, 45 FERC 
para. 61,095 at 61,280-83 (1988) (discussing the Commission's 
authority to condition a merger). Unlike the situation in Opinion 
No. 318 where the Commission had the authority under section 203 to 
disapprove a merger upon a finding of actual and potential 
anticompetitive effects, the Commission's rate authority under 
sections 205 and 206 does not permit the Commission to deny the 
proposed rates out of a concern that such action will result in an 
increase in air pollution. See Monongahela Power Co., 39 FERC para. 
61,350 at 62,096, reh'g denied, 40 FERC para. 61,256 (1987). As a 
result, we have no authority to condition the same result under 
these sections on environmental mitigation.
    \1045\ The obligation of the Commission to weigh antitrust 
considerations highlights this point. The Commission must take into 
account anticompetitive effects when setting rates. See Northern 
Natural Gas Co. v. FPC, 399 F.2d 953 (D.C. Cir. 1968). However, we 
are limited as to the remedies we may impose. We cannot go further 
and assess the range of remedies that, for example, a Court may 
exact upon finding an antitrust violation. See generally NAACP, 520 
F.2d at 441.
    \1046\ Project for Sustainable FERC, at 32-33, and Alliance, at 
41-42, have attempted to argue that NAACP actually supports the 
Commission having authority to order environmental mitigation. Their 
argument fails because they have not shown, and cannot show, the 
necessary direct nexus to our economic regulation.
---------------------------------------------------------------------------

    This distinction is more evident when one considers the way in 
which we are authorized to treat the costs of environmental compliance. 
There are legitimate costs of environmental compliance that should be 
reflected in jurisdictional rates to the extent prudently incurred, 
just as the prudent costs of complying with, for example, occupational 
health and safety requirements designed to protect utility employees 
should be reflected in jurisdictional rates. This we are authorized to 
do and we routinely review and allow such costs.<SUP>1047 However, the 
fact that the costs of providing utility workers with a safe workplace 
are properly reflected in utilities' jurisdictional rates does not mean 
that we have authority to condition sellers' rates or customers' use of 
jurisdictional services on meeting safety regulations that are in the 
public interest. The same rationale applies to environmental matters 
related to the rule.<SUP>1048
---------------------------------------------------------------------------

    \1047\ For example, our regulations permit 100 percent of any 
construction work in progress for pollution control facilities 
allocable to wholesale sales to be included in rate base. See 18 CFR 
35.25 (1995). This regulatory action, directly related to our core 
ratemaking responsibilities, removes an economic disincentive for 
public utilities to invest in structures designed to reduce the 
amount of pollution produced by a generating facility. See 18 CFR 
35.25(b) (definition of pollution control facility).
    The Commission also addressed the ratemaking consequences of 
SO<INF>2 emissions trading in response to a petition from the Edison 
Electric Institute. This is another example of the Commission's 
proper exercise of its jurisdiction, i.e., over the costs of 
environmental compliance.
    \1048\ Indeed, our regulations provide for such cost recovery.
---------------------------------------------------------------------------

    Commenters also raise several other arguments to support the claim 
that the Rule requires us to undertake environmental regulation to 
remedy supposed impacts of the rule. EPA, for example, argues that 
requiring environmental mitigation would not run afoul of the 
prescription of section 201(b)(1) of the FPA enjoining our regulation 
of generation facilities because the ``regulation of transmission 
tariffs necessarily has manifold indirect effects on generation 
sources. The proposed mitigation mechanism would influence generation 
sources in a similar, indirect manner.'' <SUP>1049
---------------------------------------------------------------------------

    \1049\ EPA at 50.
---------------------------------------------------------------------------

    EPA fundamentally misunderstands the purpose of the Rule. We act to 
remedy unduly discriminatory practices in, as here for example, the 
provision of transmission access. Since ``undue discrimination,'' is 
one of the matters ``specifically provided in this Part (II)'', i.e., 
in FPA sections 205 and 206, we are acting within the bounds of our 
statutory mandate and the effect that the Rule may have ``over 
facilities used for the generation of electric energy'' is specifically 
sanctioned. Indeed, many generators are transmission customers who we 
are obliged to protect under the FPA. That there may be indirect 
environmental consequences from our Rule does not trigger our 
jurisdiction under the FPA.

[[Page 21688]]

    EPA next argues that, even if we could not impose a specific 
mitigation mechanism for open access transmission, we could deny 
transmission service unless there is a showing that the service will 
not have an adverse environmental impact.<SUP>1050
---------------------------------------------------------------------------

    \1050\ EPA at 51. See also NESCAUM at 19; Alliance at 18, 53; 
Project for Sustainable FERC at 37.
---------------------------------------------------------------------------

    We have already discussed why we believe this approach is 
unworkable and inconsistent with sections 205 and 206 of the 
FPA.<SUP>1051 Plainly stated, EPA would have transmission customers 
assume an additional regulatory burden in order to be treated 
lawfully.<SUP>1052 Quite apart from this fundamental problem, such a 
regime is beyond our authority. Our regulation under sections 205 and 
206 is over the selling public utility's rates, terms and conditions, 
not over the buyer's agreement to undertake measures which have no 
nexus whatsoever with the seller's costs or terms of service.
---------------------------------------------------------------------------

    \1051\ CCEM argues that the tracking of documentation with 
environmental compliance requirements will stifle the very 
competitive bulk power market that EPA and others profess to 
support. CCEM notes that ``(i)t is both ironic and inexplicable why 
EPA, the agency charged with enforcing the nation's clean air and 
other environmental protection laws is so anxious to shift this 
responsibility away from itself and onto economic participants in 
the incipient, competitive power supply industry.'' CCEM 
Supplemental Comments at 4.
    \1052\ We also note that under EPA's scheme those most likely to 
benefit from denying access--transmission sellers--would be provided 
the authority to lawfully deny transmission access.
---------------------------------------------------------------------------

    EPA states that its alternative mitigation mechanism would not be a 
condition of the open access tariff, but apparently a condition on the 
ability of customers to take service under the tariff. However, our 
authority to set terms and conditions of eligibility derives from 
precisely the same authority that we use to set other tariff terms. It 
must still be based on a nexus with the subject matter of our 
jurisdiction. For buyers, open access is a right, not a privilege. We 
fail to see, given the direction of the FPA to ensure these rights, any 
basis for us to undertake the actions EPA proposes.
    Finally, EPA points to the Commission's decision to exclude certain 
diesel facilities in defining qualifying facilities (QF) under PURPA 
section 210.<SUP>1053 However, this provides no precedent for imposing 
environmental standards to prevent customers from obtaining 
nondiscriminatory open access. Whatever the merits of that 
decision,<SUP>1054 the Commission subsequently found that any facility 
that satisfies the ownership and technical requirements for QF status 
set forth in PURPA and the Commission's regulations is a QF without any 
action by the Commission.<SUP>1055 More to the point, EPA ignores the 
fact that, in issuing environmental findings with its QF Rules, the 
Commission found that environmental concerns were a local matter to be 
handled under other statutory authorities. While PURPA permitted 
certain qualifying facilities to be exempt from state and federal laws,
---------------------------------------------------------------------------

    \1053\ EPA states at 51-52 that:
    In implementing section 210 of the Public Utility Regulatory 
Policies Act, the FERC took the approach of declining to act because 
of the potential adverse environmental impacts of the action. 
Section 210 required the FERC to prescribe regulations ``to 
encourage cogeneration and small power production * * * Because of 
its concern that ``diesel and dual-fuel commercial cogeneration 
facilities in the New York City area had the potential to cause 
environmentally significant effects'' (46 FR 33025) (1981)), the 
FERC issued regulations that excluded new diesel cogeneration 
facilities from being ``qualifying facilities.'' 45 FR 17964.
    EPA maintains that the FERC similarly has authority in the 
instant case to deny open access transmission to the extent such 
transmission would have adverse environmental impacts.
    \1054\ The Commission subsequently modified this position and 
decided to treat diesel cogeneration facilities like other QFs.
    \1055\ See CMS Midland, Inc., 50 FERC para. 61,098 at 61,277-278 
(1990), reh'g denied, 56 FERC para. 61,177 (1991), aff'd mem. sub 
nom., Michigan Municipal Cooperative Group, v. FERC, 990 F.2d 1377 
(D.C. Cir.) (per curiam), cert. denied, 114 S.Ct. 546 (1993); see 
also Mesquite Lake Associates, Ltd., 63 FERC para. 61,351 (1993); 
Citizens for Clean Air and Reclaiming Our Environment v. Newbay 
Corporation, 56 FERC para. 61,428 at 62,532-33, reh'g denied, 57 
FERC para. 61,219 (1991).

it excludes exemptions from environmental laws. Thus, a qualifying 
facility may not be built or operated unless it complies with all 
applicable local, State, and Federal zoning, air, water, and other 
environmental quality laws, and unless it obtains all required 
permits.<SUP>1056
---------------------------------------------------------------------------

    \1056\ Small Power Production and Cogeneration Facilities--
Environmental Findings, 10 FERC para. 61,314 at 61,632 (1980). The 
Commission has included similar language in every order it issues 
finding qualifying facility status. See also Small Power Production 
and Cogeneration, Order No. 70-E, FERC Stats. & Regs., Regs. 
Preambles 1977-81 para. 30,274 at 31,596 (1981).

Thus, while we have noted that QFs are required to satisfy all 
environmental requirements, we have not viewed our responsibilities 
under PURPA as permitting us to enforce compliance with environmental 
laws.<SUP>1057
---------------------------------------------------------------------------

    \1057\ The important point is that the Commission has fully 
complied with its responsibilities under NEPA in both instances. 
Whatever initial decision it may have come to in 1981 with regard to 
the particular circumstances involved in adopting QF regulations 
under PURPA is irrelevant to the instant rulemaking.
---------------------------------------------------------------------------

    EPA then proposes to require any fossil fuel-burning generating 
entity seeking service under an open access tariff to (a) commit by 
contract to avoid or offset emissions increases (measured against 
certain baselines), and (b) periodically certify its compliance with 
that commitment.<SUP>1058 This proposal is neither workable nor within 
our jurisdiction.
---------------------------------------------------------------------------

    \1058\ EPA's proposal apparently would apply only for NO<INF>X, 
CO<INF>2 and mercury. See EPA at 58 n.31 and 60 (because there is 
already a nationwide cap on SO<INF>2 emissions in the Clean Air Act, 
there is no need for mitigation for that pollutant). In other words, 
EPA apparently would require us to impose environmental mitigation 
only in those instances in which Congress has not provided a 
nationwide cap for a pollutant.
---------------------------------------------------------------------------

    The deficiency with respect to (a) is that we have no authority to 
require such action. While EPA cites to FPA section 206 for the 
proposition that we may change jurisdictional contracts, we may do so 
only if the contract is, for example, unjust or unreasonable with 
respect to matters within our jurisdiction, i.e., economic regulation. 
Our standards for acting are strictly prescribed under the 
FPA.<SUP>1059 As NAACP and Great Plains teach, sections 205 and 206 do 
not provide the Commission with the means to remedy every possible 
problem that is in any fashion related to a sale for resale or 
transmission in interstate commerce by a public utility. Since we do 
not have the authority to require (a), it follows we cannot require the 
periodic certification of compliance recommended in (b).
---------------------------------------------------------------------------

    \1059\ See United Gas Pipe Line Co. v. Mobile Gas Service Corp., 
350 U.S. 332 (1956); FPC v. Sierra Pacific Power Co., 350 U.S. 348 
(1956).
---------------------------------------------------------------------------

    EPA notes that it ``could establish a procedure whereby a generator 
could voluntarily subject its facilities to emission limits that are 
enforceable by EPA and/or state environmental authorities.'' <SUP>1060 
This is a matter within EPA's province, and we support EPA in 
undertaking whatever measures it determines to be within its authority 
and appropriate to the problem.
---------------------------------------------------------------------------

    \1060\ EPA at 59 (emphasis added). See also Project for 
Sustainable FERC at 38-39 (proposing that a regulatory plan be 
developed through consultations between the Commission, EPA, DOE, 
and appropriate regional and state regulators and then presented in 
the FEIS).
---------------------------------------------------------------------------

    Alliance argues, at 47-51, that sections 211 and 212 of the FPA, as 
amended by the Energy Policy Act, authorize the Commission to impose 
environmental conditions. To the extent that Alliance's arguments rely 
on the ``public interest'' language used in section 211, we believe 
that the discussion above already addresses such arguments, with one 
exception: Alliance argues that the House Report for the Energy Policy 
Act states that the purpose of the Act is to ``increase U.S. energy 
security in cost-effective and environmentally beneficial ways

[[Page 21689]]

* * *.'' <SUP>1061 However, even if we assume that the Report language 
reflects Congressional intent for the Energy Policy Act in general, we 
note that, in Title VII of the Energy Policy Act concerning 
electricity, the only mention of the environment was, as noted above, 
in section 731 which specifically provided that nothing in the Energy 
Policy Act in any way interferes with the authority of any state or 
local government relating to, inter alia, environmental protection. 
While we do not quarrel with the proposition that Congress in the 
Energy Policy Act obviously had concerns with environmental 
matters,<SUP>1062 Congress did not provide the Commission with any 
authority to mandate environmental mitigation.
---------------------------------------------------------------------------

    \1061\ Alliance at 62, quoting H.R. Rep. No. 474 (Part I) (Vol. 
4), 103d Cong., 2d Sess. 132 (1992), reprinted in 1992 U.S. Code 
Cong. & Ad. News 1955.
    \1062\ For example, Title XVI concerned Global Climate Change.
---------------------------------------------------------------------------

    We have undertaken an extensive NEPA analysis to consider the 
environmental effects of our Rule. We cannot, however, take NEPA's 
requirement to consider environmental effects as authority to require 
the environmental mitigation proposed in the comments. Congress has 
charged other agencies, most notably the EPA, with the responsibility 
of protecting the environment and enforcing environmental 
laws.<SUP>1063 While we stand ready to work in a complementary fashion 
with these agencies, we believe that any attempt by the Commission to 
go beyond the economic regulation that Congress has delegated to us 
would be ultra vires.
---------------------------------------------------------------------------

    \1063\ See, e.g., S. Rep. No. 228 (concerning the Clean Air Act 
Amendments of 1990), 101st Cong., 2d Sess. 5 (1990), reprinted in 
1990 U.S. Code Cong. & Ad. News 3391 (``The States, together with 
EPA, are responsible for ensuring that the primary air quality 
standards are met * * *''); S. Rep. No. 228, 101st Cong., 2d Sess. 
9, reprinted in 1990 U.S. Code Cong. & Ad. News 3395 (``The 1970 and 
1977 Clean Air Act Amendments established a partnership between the 
States and Federal government. EPA sets nationally uniform air 
quality standards and States, with the Agency's assistance, are 
responsible for meeting them.''). See also, e.g., Connecticut v. 
EPA, 696 F.2d 147, 163 (2d Cir. 1982) (``One central focus of the 
Clean Air Act Amendments of 1977 was to ensure that the EPA would 
monitor and control the impact of pollution from one state on air 
quality in another.''); Ohio Environmental Council v. EPA, 593 F.2d 
24, 31 (6th Cir. 1979) (``Congress placed responsibility for 
enforcing the Clean Air Act in the U.S. EPA.'').
    We further note the following limitations on the Clean Air Act 
Amendments of 1990 with respect to the emission allowance program in 
section 403(f), which provides in pertinent part:
    Nothing in this section shall be construed as requiring a change 
of any kind in any State law regulating electric utility rates and 
charges or affecting any State law regarding such State regulation 
or as limiting State regulation (including any prudency review) 
under such a State law. Nothing in this section shall be construed 
as modifying the Federal Power Act (16 U.S.C.A. 791a et seq.) or as 
affecting the authority of the Federal Energy Regulatory Commission 
under that Act. Nothing in this subchapter shall be construed to 
interfere with or impair any program for competitive bidding for 
power supply in a State in which such program is established.
    42 U.S.C. 7651b(f). Thus, Congress expressly chose not to tie 
environmental authority under the emission allowance program to the 
Commission's and states' ratemaking authority.
---------------------------------------------------------------------------

    To summarize: The Commission's jurisdiction under Parts II and III 
of the FPA is limited to matters relating to economic regulation. 
Neither the relevant statutes nor the case law supports the expansive 
and novel reading of the Commission's authority advocated by the 
commenters that argue that we have environmental mitigation authority. 
The Commission is not explicitly given such authority in either the FPA 
or NEPA. Moreover, the FPA and the case law clearly compel the 
conclusion that we cannot impose environmental conditions that do not 
directly relate to the economic matters over which we have 
jurisdiction. To do so, in fact, would prevent the Commission from 
effectively carrying out its responsibilities under the FPA.

F. Coastal Zone Management Act Issue

    By letter dated February 22, 1996, and filed with the Commission on 
March 5, 1996, the Connecticut Department of Environmental Protection 
(Connecticut) notified the Commission that it has determined that the 
Commission's proposed action in this rulemaking proceeding is likely to 
adversely affect Connecticut's coastal resources. Connecticut reasons 
that the Rule's promotion of competition ``is likely to increase energy 
production by mid-west coal burning plants(,) which will in turn 
increase the export of nitrogen and sulphur oxides.'' Connecticut 
states that airborne nitrogen emissions are linked to adverse 
environmental impacts in Long Island Sound. It therefore asserts that, 
pursuant to section 307(c)(1) of the Coastal Zone Management Act (16 
U.S.C. 1456(c)(1)) (CZMA), and the federal regulations promulgated 
thereunder (15 CFR part 930), the Commission is required to provide it 
with a determination of the Rules' consistency with Connecticut's 
federally approved coastal management plan.
    Section 307(c)(1)(A) of the CZMA deals with the prevention or 
amelioration of adverse physical impacts on coastal zone resources 
attributable to federal activities. The legislative history indicates 
that in enacting the CZMA Congress was concerned with the adverse 
effects on coastal lands and waters of such activities as excavation, 
filling, diversion of water or sediment, clearing, and off-shore energy 
exploration and dumping.<SUP>1064
---------------------------------------------------------------------------

    \1064\ The conference report on the 1990 CZMA amendments 
expressly states that the principal objective of the 1990 revisions 
to the language of section 307(c)(1) was to overturn a Supreme Court 
decision holding that Outer Continental Shelf oil and gas lease 
sales were not subject to CZMA consistency determinations. H.R. Rep. 
No. 101-964, 101st Cong., 2d Sess. 2675 (1990).
---------------------------------------------------------------------------

    As discussed more fully above, section 201 of the FPA declares that 
the Commission shall not have jurisdiction over facilities used for the 
generation of electricity except as specifically provided. Thus, the 
Commission has no direct jurisdiction over fossil-fuel plants. Its 
jurisdiction extends only to the rates, terms, and conditions of 
wholesale sales and transmission of electric energy in interstate 
commerce from those plants. While we are aware that the legislative 
history of the CZMA indicates a Congressional intent to cover all 
federal activities, there is absolutely no indication in the CZMA or 
its legislative history that ``federal activities'' should include all 
federal regulatory decisions, including Commission orders involving 
interstate electric rates and service (or any other jurisdictional 
matter under Part II of the FPA).<SUP>1065 We are not aware of any 
judicial or agency interpretation that would cast the net of the states 
under the CZMA broadly enough to include the generic federal regulatory 
action undertaken in this Rule. Such action is clearly remote from the 
kind of activities such as leasing of land, and dredging and filling 
that either affect, or authorize specific activities that affect, the 
environment in the coastal zone.
---------------------------------------------------------------------------

    \1065\ In using the phrase ``federal activities'' Congress did 
not use the term ``federal action'' which has clear and broad 
meaning under NEPA.
---------------------------------------------------------------------------

    Connecticut's attempt to pull FPA Part II regulation into the CZMA 
federal consistency provisions by dint of the rulemaking's alleged 
adverse impact on air quality and consequent adverse impact on water 
quality in the coastal zone is untenable in view of the existence of 
the Clean Air Act, a complex, 700-page environmental law that 
constitutes a comprehensive scheme of regulation of the Nation's air 
quality, including the direct regulation of emissions by utility power 
plants. Indeed, the CZMA provides that the requirements of the Clean 
Air Act, and governmental directives pursuant to that Act, shall be 
incorporated in, and shall be the air pollution control requirements 
of, all state coastal zone

[[Page 21690]]

management programs.<SUP>1066 It therefore defies logic to assert that, 
despite the pervasive regulatory reach of the Clean Air Act and the 
clear authority of EPA to regulate NO<INF>X emissions under that 
statute, the CZMA is a separate source of authority for state 
jurisdiction over air quality impacts to coastal zones.
---------------------------------------------------------------------------

    \1066\ Section 307(f) of the CZMA, 16 U.S.C. 1456(f). A state 
may develop more stringent standards, if they can be enforced by the 
state (15 CFR 923.45(c)(2)), but more stringent state air quality 
standards would not alter the characteristics of FPA Part II 
regulation that put it beyond the federal consistency requirements 
of the CZMA.
---------------------------------------------------------------------------

     While it is clear that Connecticut's invocation of the CZMA is 
incorrect, we note that, under the Commerce Department's implementing 
regulations, Connecticut has in any event waived its right to request a 
consistency determination for the Commission's rulemaking. 
Connecticut's coastal management program's list of federal agency 
activities likely to require a consistency determination does not (for 
good reason) describe rulemakings of this kind, and the rule will not 
``result in a significant change in air or water quality within the 
management area'' (the program's catch-all category). In addition, 
Connecticut did not notify the Commission of its conclusion that the 
Rule requires a consistency determination until well after 45 days from 
receipt of several notices of the rulemaking proceeding.<SUP>1067 
Consequently, pursuant to 15 CFR 930.35(b), Connecticut has in any 
event waived its right to request a consistency determination for this 
rulemaking.
---------------------------------------------------------------------------

    \1067\ The Connecticut Department of Environmental Protection is 
on the service list for the rulemaking proceeding. The Commission 
issued a NOPR in this proceeding on March 29, 1995 (60 FR 17662, 
April 7, 1995). On July 12, 1995, it issued a notice of intent to 
prepare an EIS in this proceeding (60 FR 36752, July 18, 1995). On 
November 17, 1995, the Commission issued a Draft EIS (60 FR 58304, 
Nov. 27, 1995).
---------------------------------------------------------------------------

Conclusion

    After reviewing the record in this proceeding, including the FEIS, 
we find for the reasons discussed above that proceeding with this rule 
is the best alternative. No other alternative will accomplish the 
Commission's purposes.
    The rule is expected to slightly increase or slightly decrease 
total future NO<INF>X emissions, depending on whether competitive 
conditions in the electric industry favor the utilization of natural 
gas or coal as a fuel for the generation of electricity. Other impacts 
of the rule have also been determined to be slight. Therefore, it is 
unnecessary to adopt and implement a plan of mitigation.
    A wide range of mitigation measures have nonetheless been fully 
evaluated as discussed in Chapter 7 of the FEIS. This discussion 
concludes that the Commission does not have authority under the FPA and 
NEPA, singly or conjointly, to impose mitigation, and that existing and 
proposed mitigation strategies and efforts are the best way to deal 
with potential environmental effects that might result from 
implementing the rule. Such effects, if they indeed materialize, are 
not expected to occur for many years. In the meantime, action by 
entities such as EPA and OTAG are expected to address the underlying 
air emission problems facing parts of the Nation. Interim mitigation 
efforts to be undertaken by the Commission would address only a very 
small part of the problem, would require the exercise of technical 
expertise and authority that the Commission does not possess, and could 
well interfere with efforts by EPA and others to address this 
situation.
    For these reasons, we support the analysis in the staff's FEIS and 
adopt the conclusions in that document.<SUP>1068
---------------------------------------------------------------------------

    \1068\ A Record of Decision (ROD) will not be issued as a 
separate document; instead this rule, including the FEIS as 
incorporated into the rule by adoption, will serve as the ROD for 
the rule.
---------------------------------------------------------------------------

VI. Regulatory Flexibility Act Certification

    The Regulatory Flexibility Act (RFA) <SUP>1069 requires rulemakings 
to contain either a description and analysis of the effect that the 
proposed rule will have on small entities or a certification that the 
rule will not have a significant economic impact on a substantial 
number of small entities. In the Open Access and Stranded Cost NOPRs, 
the Commission concluded that the proposed rules would not have a 
significant economic impact upon a substantial number of small 
entities.<SUP>1070
---------------------------------------------------------------------------

    \1069\ 5 U.S.C. 601-612.
    \1070\ 60 FR 17662 at 17721 (April 7, 1995), FERC Stats. & Regs. 
para. 32,514 at 33,151.
---------------------------------------------------------------------------

    SBA questions this conclusion.<SUP>1071 It states that, 
``[a]ccording to data from the Department of Energy, the vast majority 
of utilities are small.'' <SUP>1072 SBA requests that if, upon 
reconsideration, the Commission determines that the final rule in the 
Open Access NOPR proceeding would have a significant economic impact on 
a substantial number of small entities, the Commission perform a 
Regulatory Flexibility Analysis under the requirements of the 
RFA.<SUP>1073
---------------------------------------------------------------------------

    \1071\ SBA Initial Comments at 1 and n.1.
    \1072\ SBA Initial Comments at 2 n.1. SBA ``defines a small 
electric utility as one that disposes of 4 million MWh of 
electricity in a given year.'' Id. At an average wholesale price of 
between $30 and $40 per MWh (Energy Information Administration, 
Financial Statistics of Major Investor-Owned Utilities, 1994, Table 
No. 1), utilities that dispose of 4 million MWh per year would have 
annual sales in the range of $120 million to $180 million.
    \1073\ 5 U.S.C. 601-612. SBA Initial Comments at 2 n.1.
---------------------------------------------------------------------------

A. Docket No. RM95-8-000 (Open Access Final Rule)

1. Public Utilities
    The Open Access Final Rule is applicable to public utilities that 
own, control or operate interstate transmission facilities, not to 
electric utilities per se.<SUP>1074 The total number of public 
utilities that, absent waiver, would have to have open access tariffs 
on file is 166.<SUP>1075 Of these, only 50 public utilities dispose of 
4 million MWh or less per year.<SUP>1076 Eliminating those utilities 
that are affiliates of other utilities whose sales exceed 4 million MWh 
per year, or are not independently owned,<SUP>1077 the total number of 
public utilities affected by the Open Access Final Rule that qualify 
under the SBA's definition of small electric utility is 19, or 11 
percent of the total number of public utilities that would have to have 
on file open access tariffs.<SUP>1078 We do not consider this a 
substantial number,<SUP>1079 and, in any event, these entities may seek 
waiver of the Open Access Final

[[Page 21691]]

Rule's requirements under the Rule's waiver provisions.
---------------------------------------------------------------------------

    \1074\ The Stranded Cost Final Rule is applicable to public 
utilities and to transmitting utilities (that are not also public 
utilities).
    \1075\ Over 100 of these entities have already filed some type 
of open access tariff.
    \1076\ The sources for this figure are FERC Form No. 1 and FERC 
Form No. 1-F data.
    \1077\ The RFA defines a ``small entity'' as ``one which is 
independently owned and operated and which is not dominant in its 
field of operation.'' See 5 U.S.C. 601(3) and 601(6) and 15 U.S.C. 
632(a)(1) (definition of ``small business concern'').
    \1078\ We note that five of these 19 public utilities have 
already filed open access tariffs with the Commission. While these 
five public utilities fall within SBA's definition of small electric 
utility, since they have already filed open access tariffs, the 
effect of the Open Access Final Rule on these entities should not be 
significant. The remaining 14 small public utilities constitute 
eight percent of the total number of public utilities that would 
have to have on file open access tariffs. To the extent these 14 
small public utilities consider the impact of the Final Rule to be 
significant, these entities may request a waiver of the open access 
filing requirements under the waiver provisions of the Open Access 
Final Rule.
    \1079\ In Mid-Tex Electric Coop., Inc. v. FERC, 773 F.2d 327, 
340-43 (D.C. Cir. 1985) (Mid-Tex), the court accepted the 
Commission's conclusion that, since virtually all of the public 
utilities that it regulates do not fall within the meaning of the 
term ``small entities'' as defined in the RFA, the Commission did 
not need to prepare a regulatory flexibility analysis in connection 
with its proposed rule governing the allocation of costs for 
construction work in progress (CWIP). The CWIP rules applied to all 
public utilities. The Open Access Final Rule applies to only those 
public utilities that own, control or operate interstate 
transmission facilities. These entities are a subset of the group of 
public utilities found not to require preparation of a regulatory 
flexibility analysis for the CWIP rule.
---------------------------------------------------------------------------

    Moreover, in the Open Access Final Rule, the Commission is 
specifying the non-rate terms and conditions of the tariffs that the 
public utilities must have on file. The public utilities need only 
develop and file a rate.<SUP>1080 When one considers that the 
disposition of 4 million MWhs a year translates into sales in the range 
of $120 million to $180 million per year, the cost to prepare and file 
proposed rates,<SUP>1081 which these utilities must regularly do anyway 
in the ordinary course of business, is not a significant economic 
impact.
---------------------------------------------------------------------------

    \1080\ Those public utilities that already have open access 
tariffs on file are not even required to propose rates. They may 
elect to continue service under the Open Access Final Rule's non-
rate terms and conditions at their existing rates.
    \1081\ In the Public Reporting Burden section (Section II), the 
Commission reaffirms the average reporting burden of 300 hours per 
response, which was proposed and unchallenged in the NOPR. If a cost 
of $200 per hour is used, the cost of making the required filing 
would be $60,000. On average, this is no more than one half of one 
percent of total annual sales for small electric utilities.
---------------------------------------------------------------------------

2. Non-Public Utilities
    The Open Access Final Rule will not impose any burden on non-public 
utilities, since they need not themselves file open access tariffs. 
Triggering the reciprocity provision in the Open Access Final Rule is 
optional; it is merely a condition of receiving a benefit, i.e., open 
access transmission service from a public utility. If non-public 
utilities elect not to take advantage of open access services because 
they do not want to meet the tariff reciprocity provision, they can 
still seek voluntary, bilateral transmission services from public 
utilities. Also, under the waiver provisions in the Open Access Final 
Rule, small non-public utilities may seek waiver from the reciprocity 
provision.

B. Docket No. RM94-7-001 (Stranded Cost Final Rule)

1. Public Utilities
    As with the Open Access Final Rule, there are not a substantial 
number of public utilities that qualify under the SBA's definition of 
small electric utility that are subject to the Stranded Cost Final 
Rule. The Stranded Cost Rule applies only to public utilities that seek 
stranded cost recovery in connection with a limited set of wholesale 
requirements contracts (those executed on or before July 11, 1994 that 
do not contain an exit fee or other explicit stranded cost provision). 
To the extent that public utilities seek stranded cost recovery, they 
will do so in a rate filing, where stranded cost recovery is likely to 
be one of many items considered. Accordingly, the Stranded Cost Final 
Rule will not pose a significant economic impact on a substantial 
number of public utility small entities.
2. Non-Public Utilities
    With regard to non-public utilities, the stranded cost issue would 
only arise in a proceeding under sections 211 and 212 of the FPA when, 
in directing transmission, the Commission addresses the stranded cost 
issue in determining a just and reasonable rate. As with public 
utilities, stranded costs will be just one more item to be considered 
in establishing just and reasonable rates for transmission. As a 
result, the Stranded Cost Final Rule will not impose a significant 
economic impact on a substantial number of non-public utility small 
entities.

C. Conclusion

    Accordingly, the Commission certifies that these final rules will 
not have a significant economic impact on a substantial number of small 
entities.

VII. Information Collection Statement

    The Office of Management and Budget's (OMB) regulations <SUP>1082 
require that OMB approve certain information and recordkeeping 
requirements (collections of information) imposed by an agency. Upon 
approval of a collection of information, OMB shall assign an OMB 
control number and an expiration date. Respondents subject to the 
filing requirements of this Rule shall not be penalized for failing to 
respond to this collection of information unless the collection of 
information displays a valid OMB control number.
---------------------------------------------------------------------------

    \1082\ 5 CFR 1320.11.
---------------------------------------------------------------------------

    There are now approximately 328 public utilities, including 
marketers and wholesale generation entities. The Commission estimates 
that 166 of these utilities own, control or operate facilities used for 
the transmission of electric energy in interstate commerce and would be 
subject to the filing requirements of this Rule.
    Title: FERC-516, Electric Rate Schedule Filings.
    Action: Final Rule.
    OMB Control No: 1902-0096.
    Respondents: Public Utilities that own, control or operate 
facilities used for the transmission of electric energy in interstate 
commerce.
    Frequency of Responses: On occasion.
    Necessity of information: The Final Rule requires public utilities 
that own, control or operate facilities used for the transmission of 
electric energy in interstate commerce to have on file with the 
Commission non-discriminatory open access transmission tariffs that 
contain minimum terms and conditions of service and permits public 
utilities to make filings to seek recovery of legitimate, prudent and 
verifiable stranded costs associated with providing open access and FPA 
section 211 transmission services. The Commission has a mandate under 
sections 205 and 206 of the FPA to ensure, with respect to any 
transmission in interstate commerce or any sale of electric energy for 
resale in interstate commerce by a public utility, that no entity is 
subject to undue discrimination. The Commission will use the data 
collected in this collection of information to carry out its 
responsibilities under Part II of the FPA. The Commission's Office of 
Electric Power Regulation will use the data to review electric rate and 
tariff filings.
    The Commission is submitting notification of this Final Rule to 
OMB. Interested persons may obtain information on the reporting 
requirements by contacting the Federal Energy Regulatory Commission, 
888 First Street, NE., Washington, DC. 20426 [Attention: Michael 
Miller, Information Services Division, (202) 208-1415], and to the 
Office of Management and Budget (Attention: Desk Officer for the 
Federal Energy Regulatory Commission, (202) 395-3087).

VIII. Effective Date

    This Rule will take effect on July 9, 1996. The Commission has 
determined, with the concurrence of the Administrator of the Office of 
Information and Regulatory Affairs of the Office of Management and 
Budget, that this rule is a ``major rule'' within the meaning of 
section 351 of the Small Business Regulatory Enforcement Act of 
1996.<SUP>1083 The rule will be submitted to both Houses of Congress 
and the Comptroller General prior to its publication in the Federal 
Register.
---------------------------------------------------------------------------

    \1083\ 5 U.S.C. 804(2).
---------------------------------------------------------------------------

List of Subjects

18 CFR Part 35

    Electric power rates, Electric utilities, Reporting and 
recordkeeping requirements.

18 CFR Part 385

    Administrative practice and procedure, Electric power, Penalties, 
Pipelines, Reporting and recordkeeping requirements.

    By the Commission. Commissioner Hoecker concurred in part and 
dissented in

[[Page 21692]]

part with a separate statement attached. Commissioner Massey 
dissented in part with a separate statement attached.
Lois D. Cashell,
Secretary.
    In consideration of the foregoing, the Commission amends parts 35 
and 385, chapter I, title 18 of the Code of Federal Regulations, as set 
forth below.

PART 35--FILING OF RATE SCHEDULES

    1. The authority citation for part 35 continues to read as follows:

    Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 
U.S.C. 7101-7352.

    2. Part 35 is amended by revising Sec. 35.15, by redesignating 
Sec. 35.28 as Sec. 35.29, and by adding new Secs. 35.26, 35.27, and 
35.28 to read as follows:


Sec. 35.15  Notices of cancellation or termination.

    (a) General rule. When a rate schedule or part thereof required to 
be on file with the Commission is proposed to be cancelled or is to 
terminate by its own terms and no new rate schedule or part thereof is 
to be filed in its place, each party required to file the schedule 
shall notify the Commission of the proposed cancellation or termination 
on the form indicated in Sec. 131.53 of this chapter at least sixty 
days but not more than one hundred-twenty days prior to the date such 
cancellation or termination is proposed to take effect. A copy of such 
notice to the Commission shall be duly posted. With such notice each 
filing party shall submit a statement giving the reasons for the 
proposed cancellation or termination, and a list of the affected 
purchasers to whom the notice has been mailed. For good cause shown, 
the Commission may by order provide that the notice of cancellation or 
termination shall be effective as of a date prior to the date of filing 
or prior to the date the filing would become effective in accordance 
with these rules.
    (b) Applicability. (1) The provisions of paragraph (a) of this 
section shall apply to all contracts for unbundled transmission service 
and all power sale contracts:
    (i) Executed prior to July 9, 1996; or
    (ii) If unexecuted, filed with the Commission prior to July 9, 
1996.
    (2) Any power sales contract executed on or after July 9, 1996 that 
is to terminate by its own terms shall not be subject to the provisions 
of paragraph (a) of this section.
    (c) Notice. Any public utility providing jurisdictional services 
under a power sales contract that is not subject to the provisions of 
paragraph (a) of this section shall notify the Commission of the date 
of the termination of such contract within 30 days after such 
termination takes place.


Sec. 35.26  Recovery of stranded costs by public utilities and 
transmitting utilities.

    (a) Purpose. This section establishes the standards that a public 
utility or transmitting utility must satisfy in order to recover 
stranded costs.
    (b) Definitions.
    (1) Wholesale stranded cost means any legitimate, prudent and 
verifiable cost incurred by a public utility or a transmitting utility 
to provide service to:
    (i) A wholesale requirements customer that subsequently becomes, in 
whole or in part, an unbundled wholesale transmission services customer 
of such public utility or transmitting utility; or
    (ii) A retail customer, or a newly created wholesale power sales 
customer, that subsequently becomes, in whole or in part, an unbundled 
wholesale transmission services customer of such public utility or 
transmitting utility.
    (2) Wholesale requirements customer means a customer for whom a 
public utility or transmitting utility provides by contract any portion 
of its bundled wholesale power requirements.
    (3) Wholesale transmission services has the same meaning as 
provided in section 3(24) of the Federal Power Act (FPA): The 
transmission of electric energy sold, or to be sold, at wholesale in 
interstate commerce.
    (4) Wholesale requirements contract means a contract under which a 
public utility or transmitting utility provides any portion of a 
customer's bundled wholesale power requirements.
    (5) Retail stranded cost means any legitimate, prudent and 
verifiable cost incurred by a public utility or transmitting utility to 
provide service to a retail customer that subsequently becomes, in 
whole or in part, an unbundled retail transmission services customer of 
that public utility or transmitting utility.
    (6) Retail transmission services means the transmission of electric 
energy sold, or to be sold, in interstate commerce directly to a retail 
customer.
    (7) New wholesale requirements contract means any wholesale 
requirements contract executed after July 11, 1994, or extended or 
renegotiated to be effective after July 11, 1994.
    (8) Existing wholesale requirements contract means any wholesale 
requirements contract executed on or before July 11, 1994.
    (c) Recovery of wholesale stranded costs.
    (1) General requirement. A public utility or transmitting utility 
will be allowed to seek recovery of wholesale stranded costs only as 
follows:
    (i) No public utility or transmitting utility may seek recovery of 
wholesale stranded costs if such recovery is explicitly prohibited by a 
contract or settlement agreement, or by any power sales or transmission 
rate schedule or tariff.
    (ii) No public utility or transmitting utility may seek recovery of 
stranded costs associated with a new wholesale requirements contract if 
such contract does not contain an exit fee or other explicit stranded 
cost provision.
    (iii) If wholesale stranded costs are associated with a new 
wholesale requirements contract containing an exit fee or other 
explicit stranded cost provision, and the seller under the contract is 
a public utility, the public utility may seek recovery of such costs, 
in accordance with the contract, through rates for electric energy 
under sections 205-206 of the FPA. The public utility may not seek 
recovery of such costs through any transmission rate for FPA section 
205 or 211 transmission services.
    (iv) If wholesale stranded costs are associated with a new 
wholesale requirements contract, and the seller under the contract is a 
transmitting utility but not also a public utility, the transmitting 
utility may not seek an order from the Commission allowing recovery of 
such costs.
    (v) If wholesale stranded costs are associated with an existing 
wholesale requirements contract, if the seller under such contract is a 
public utility, and if the contract does not contain an exit fee or 
other explicit stranded cost provision, the public utility may seek 
recovery of stranded costs only as follows:
    (A) If either party to the contract seeks a stranded cost amendment 
pursuant to a section 205 or section 206 filing under the FPA made 
prior to the expiration of the contract, and the Commission accepts or 
approves an amendment permitting recovery of stranded costs, the public 
utility may seek recovery of such costs through FPA section 205-206 
rates for electric energy.
    (B) If the contract is not amended to permit recovery of stranded 
costs as described in paragraph (c)(1)(v)(A) of this section, the 
public utility may file a proposal, prior to the expiration of the 
contract, to recover stranded costs through FPA section 205-206 or 
section 211-212 rates for wholesale transmission services to the 
customer.
    (vi) If wholesale stranded costs are associated with an existing 
wholesale requirements contract, if the seller under such contract is a 
transmitting

[[Page 21693]]

utility but not also a public utility, and if the contract does not 
contain an exit fee or other explicit stranded cost provision, the 
transmitting utility may seek recovery of stranded costs through FPA 
section 211-212 transmission rates.
    (vii) If a retail customer becomes a legitimate wholesale 
transmission customer of a public utility or transmitting utility, 
e.g., through municipalization, and costs are stranded as a result of 
the retail-turned-wholesale customer's access to wholesale 
transmission, the utility may seek recovery of such costs through FPA 
section 205-206 or section 211-212 rates for wholesale transmission 
services to that customer.
    (2) Evidentiary demonstration for wholesale stranded cost recovery. 
A public utility or transmitting utility seeking to recover wholesale 
stranded costs in accordance with paragraphs (c)(1)(v)-(vii) of this 
section must demonstrate that:
    (i) It incurred stranded costs on behalf of its wholesale 
requirements customer or retail customer based on a reasonable 
expectation that the utility would continue to serve the customer;
    (ii) The stranded costs are not more than the customer would have 
contributed to the utility had the customer remained a wholesale 
requirements customer of the utility, or, in the case of a retail-
turned-wholesale customer, had the customer remained a retail customer 
of utility; and
    (iii) The stranded costs are derived using the following formula: 
Stranded Cost Obligation = (Revenue Stream Estimate-Competitive Market 
Value Estimate) x Length of Obligation (reasonable expectation period).
    (3) Rebuttable presumption. If a public utility or transmitting 
utility seeks recovery of wholesale stranded costs associated with an 
existing wholesale requirements contract, as permitted in paragraph 
(c)(1) of this section, and the existing wholesale requirements 
contract contains a notice provision, there will be a rebuttable 
presumption that the utility had no reasonable expectation of 
continuing to serve the customer beyond the term of the notice 
provision.
    (4) Procedure for customer to obtain stranded cost estimate. A 
customer under an existing wholesale requirements contract with a 
public utility seller may obtain from the seller an estimate of the 
customer's stranded cost obligation if it were to leave the public 
utility's generation supply system by filing with the public utility a 
request for an estimate at any time prior to the termination date 
specified in its contract.
    (i) The public utility must provide a response within 30 days of 
receiving the request. The response must include:
    (A) An estimate of the customer's stranded cost obligation based on 
the formula in paragraph (c)(2)(iii) of this section;
    (B) Supporting detail indicating how each element in the formula 
was derived;
    (C) A detailed rationale justifying the basis for the utility's 
reasonable expectation of continuing to serve the customer beyond the 
termination date in the contract;
    (D) An estimate of the amount of released capacity and associated 
energy that would result from the customer's departure; and
    (E) The utility's proposal for any contract amendment needed to 
implement the customer's payment of stranded costs.
    (ii) If the customer disagrees with the utility's response, it must 
respond to the utility within 30 days explaining why it disagrees. If 
the parties cannot work out a mutually agreeable resolution, they may 
exercise their rights to Commission resolution under the FPA.
    (5) A customer must be given the option to market or broker a 
portion or all of the capacity and energy associated with any stranded 
costs claimed by the public utility.
    (i) To exercise the option, the customer must so notify the utility 
in writing no later than 30 days after the public utility files its 
estimate of stranded costs for the customer with the Commission.
    (A) Before marketing or brokering can begin, the utility and 
customer must execute an agreement identifying, at a minimum, the 
amount and the price of capacity and associated energy the customer is 
entitled to schedule, and the duration of the customer's marketing or 
brokering of such capacity and energy.
    (ii) If agreement over marketing or brokering cannot be reached, 
and the parties seek Commission resolution of disputed issues, upon 
issuance of a Commission order resolving the disputed issues, the 
customer may reevaluate its decision in paragraph (c)(5)(i) of this 
section to exercise the marketing or brokering option. The customer 
must notify the utility in writing within 30 days of issuance of the 
Commission's order resolving the disputed issues whether the customer 
will market or broker a portion or all of the capacity and energy 
associated with stranded costs allowed by the Commission.
    (iii) If a customer undertakes the brokering option, and the 
customer's brokering efforts fail to produce a buyer within 60 days of 
the date of the brokering agreement entered into between the customer 
and the utility, the customer shall relinquish all rights to broker the 
released capacity and associated energy and will pay stranded costs as 
determined by the formula in paragraph (c)(2)(iii) of this section.
    (d) Recovery of retail stranded costs.
     (1) General requirement. A public utility may seek to recover 
retail stranded costs through rates for retail transmission services 
only if the state regulatory authority does not have authority under 
state law to address stranded costs at the time the retail wheeling is 
required.
    (2) Evidentiary demonstration necessary for retail stranded cost 
recovery. A public utility seeking to recover retail stranded costs in 
accordance with paragraph (d)(1) of this section must demonstrate that:
    (i) It incurred stranded costs on behalf of a retail customer that 
obtains retail wheeling based on a reasonable expectation that the 
utility would continue to serve the customer; and
    (ii) The stranded costs are not more than the customer would have 
contributed to the utility had the customer remained a retail customer 
of the utility.


Sec. 35.27  Power sales at market-based rates.

    (a) Notwithstanding any other requirements, any public utility 
seeking authorization to engage in sales for resale of electric energy 
at market-based rates shall not be required to demonstrate any lack of 
market power in generation with respect to sales from capacity for 
which construction has commenced on or after July 9, 1996.
    (b) Nothing in this part
    (1) Shall be construed as preempting or affecting any jurisdiction 
a state commission or other state authority may have under applicable 
state and federal law, or
    (2) Limits the authority of a state commission in accordance with 
state and federal law to establish
    (i) Competitive procedures for the acquisition of electric energy, 
including demand-side management, purchased at wholesale, or
    (ii) Non-discriminatory fees for the distribution of such electric 
energy to retail consumers for purposes established in accordance with 
state law.


Sec. 35.28  Non-discriminatory open access transmission tariff.

    (a) Applicability. This section applies to any public utility that 
owns, controls or operates facilities used for the transmission of 
electric energy in

[[Page 21694]]

interstate commerce and to any non-public utility that seeks voluntary 
compliance with jurisdictional transmission tariff reciprocity 
conditions.
    (b) Definitions.
    (1) Requirements service agreement means a contract or rate 
schedule under which a public utility provides any portion of a 
customer's bundled wholesale power requirements.
    (2) Economy energy coordination agreement means a contract, or 
service schedule thereunder, that provides for trading of electric 
energy on an ``if, as and when available'' basis, but does not require 
either the seller or the buyer to engage in a particular transaction.
    (3) Non-economy energy coordination agreement means any non-
requirements service agreement, except an economy energy coordination 
agreement as defined in paragraph (b)(2) of this section.
    (c) Non-discriminatory open access transmission tariffs.
    (1) Every public utility that owns, controls or operates facilities 
used for the transmission of electric energy in interstate commerce 
must have on file with the Commission a tariff of general applicability 
for transmission services, including ancillary services, over such 
facilities. Such tariff must be the open access pro forma tariff 
contained in Order No. 888, FERC Stats. & Regs. para. 31,036 (Final 
Rule on Open Access and Stranded Costs) or such other open access 
tariff as may be approved by the Commission consistent with Order No. 
888, FERC Stats. & Regs. para. 31,036.
    (i) Subject to the exceptions in paragraphs (c)(1)(ii), 
(c)(1)(iii), and (c)(1)(iv) of this section, the pro forma tariff 
contained in Order No. 888, FERC Stats. & Regs. para. 31,036, and 
accompanying rates, must be filed no later than 60 days prior to the 
date on which a public utility would engage in a sale of electric 
energy at wholesale in interstate commerce or in the transmission of 
electric energy in interstate commerce.
    (ii) If a public utility owns, controls or operates facilities used 
for the transmission of electric energy in interstate commerce as of 
July 9, 1996, it must file the pro forma tariff contained in Order No. 
888, FERC Stats. & Regs. para. 31,036, pursuant to section 206 of the 
FPA and accompanying rates pursuant to section 205 of the FPA, no later 
than July 9, 1996. However, if a public utility has already filed, or 
has on file, an open access tariff and accompanying rates as of April 
24, 1996, it may, but is not required to, file new rates with its 
section 206 pro forma tariff filing.
    (iii) If a public utility owns, controls or operates transmission 
facilities used for the transmission of electric energy in interstate 
commerce as of July 9, 1996, such facilities are jointly owned with a 
non-public utility, and the joint ownership contract prohibits 
transmission service over the facilities to third parties, the public 
utility with respect to access over the public utility's share of the 
jointly owned facilities must file no later than December 31, 1996 the 
pro forma tariff contained in Order No. 888, FERC Stats. & Regs. para. 
31,036, pursuant to section 206 of the FPA and accompanying rates 
pursuant to section 205 of the FPA.
    (iv) If a public utility obtains a waiver of the tariff requirement 
pursuant to paragraph (d) of this section, it does not need to file the 
pro forma tariff required by this section.
    (v) Any public utility that seeks a deviation from the pro forma 
tariff contained in Order No. 888, FERC Stats. & Regs. para. 31,036, 
must demonstrate that the deviation is consistent with the principles 
of Order No. 888, FERC Stats. & Regs. para. 31,036.
    (2) Every public utility that owns, controls or operates facilities 
used for the transmission of electric energy in interstate commerce, 
and that uses those facilities to engage in wholesale sales and/or 
purchases of electric energy, or unbundled retail sales of electric 
energy, must take transmission service for such sales and/or purchases 
under the open access tariff filed pursuant to this section.
    (i) Subject to the exceptions in paragraphs (c)(2)(ii) and 
(c)(3)(iv) of this section, this requirement is effective on the date 
that such public utility engages in a wholesale sale or purchase of 
electric energy or any unbundled retail sale of electric energy, but no 
earlier than July 9, 1996.
    (ii) For sales of electric energy pursuant to a requirements 
service agreement executed on or before July 9, 1996, this requirement 
will not apply unless separately ordered by the Commission. For sales 
of electric energy pursuant to a bilateral economy energy coordination 
agreement executed on or before July 9, 1996, this requirement is 
effective on December 31, 1996. For sales of electric energy pursuant 
to a bilateral non-economy energy coordination agreement executed on or 
before July 9, 1996, this requirement will not apply unless separately 
ordered by the Commission.
    (3) Every public utility that owns, controls or operates facilities 
used for the transmission of electric energy in interstate commerce, 
and that is a member of a power pool, public utility holding company, 
or other multi-lateral trading arrangement or agreement that contains 
transmission rates, terms or conditions, must file a joint pool-wide or 
system-wide open access transmission pro forma tariff.
    (i) For any power pool, public utility holding company or other 
multi-lateral arrangement or agreement that contains transmission 
rates, terms or conditions and that is executed after July 9, 1996, 
this requirement is effective on the date that transactions begin under 
the arrangement or agreement.
    (ii) For any public utility holding company arrangement or 
agreement that contains transmission rates, terms or conditions and 
that is executed on or before July 9, 1996, this requirement is 
effective July 9, 1996, except for the Central and South West System, 
which must comply no later than December 31, 1996.
    (iii) For any power pool or multi-lateral arrangement or agreement 
other than a public utility holding company arrangement or agreement, 
that contains transmission rates, terms or conditions and that is 
executed prior to July 9, 1996, this requirement is effective on 
December 31, 1996.
    (iv) A public utility member of a power pool, public utility 
holding company or other multi-lateral arrangement or agreement that 
contains transmission rates, terms or conditions and that is executed 
on or before July 9, 1996 must begin to take service under a joint 
pool-wide or system-wide pro forma tariff for wholesale trades among 
the pool or system members no later than December 31, 1996.
    (d) Waivers. A public utility subject to the requirements of this 
section and Order No. 889, FERC Stats. & Regs. para. 31,037 (Final Rule 
on Open Access Same-Time Information System and Standards of Conduct) 
may file a request for waiver of all or part of the requirements of 
this section, or Part 37 (Open Access Same-Time Information System and 
Standards of Conduct for Public Utilities), for good cause shown. An 
application for waiver must be filed either:
    (i) No later than July 9, 1996 or
    (ii) No later than 60 days prior to the time the public utility 
would otherwise have to comply with the requirement.
    (e) Non-public utility procedures for tariff reciprocity 
compliance.
    (1) A non-public utility may submit a transmission tariff and a 
request for declaratory order that its voluntary transmission tariff 
meets the requirements of Order No. 888 (Final Rule on Open Access and 
Stranded Costs).

[[Page 21695]]

    (i) Any submittal and request for declaratory order submitted by a 
non-public utility will be provided an NJ (non-jurisdictional) docket 
designation.
    (ii) If the submittal is found to be an acceptable transmission 
tariff, an applicant in a Federal Power Act (FPA) section 211 case 
against the non-public utility shall have the burden of proof to show 
why service under the open access tariff is not sufficient and why a 
section 211 order should be granted.
    (2) A non-public utility may file a request for waiver of all or 
part of the reciprocity conditions contained in a public utility open 
access tariff, for good cause shown. An application for waiver may be 
filed at any time.

PART 385--RULES OF PRACTICE AND PROCEDURE

    1. The authority citation for part 385 continues to read as 
follows:

    Authority: 5 U.S.C. 551-557; 15 U.S.C. 717-717z, 3301-3432; 16 
U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-7352; 49 
U.S.C. 60502; 49 App. U.S.C. 1-85.

    2. Part 385 is amended by adding paragraph (b)(5) to Sec. 385.2011 
to read as follows:


Sec. 385.2011  Procedures for filing on electronic media (Rule 2011).

* * * * *
    (b) * * *
    (5) Non-discriminatory open access transmission tariffs filed 
pursuant to Sec. 35.28 of this chapter.
* * * * *
    Note: Appendices A through H and statements of Commissioners 
Hoecker and Massey will not be published in the Code of Federal 
Regulations.

                                        List of Section 211 Applications                                        
----------------------------------------------------------------------------------------------------------------
    No.           Docket No.               Applicant                 Transmitter            Commission action   
----------------------------------------------------------------------------------------------------------------
1           TX93-1-000             Tex-La Electric            Texas Utilities Electric  Denied, 64 FERC para.   
                                    Cooperative of Texas,      Company.                  61,162.                
                                    Inc.                                                                        
2           TX93-2-000             City of Bedford,           American Electric Power   Granted. Final order, 68
                                    Virginia, et al.           Company, Inc.             FERC para. 61,003.     
                                                                                         Reh'g denied, 73 FERC  
                                                                                         para. 61,322.          
3           TX93-3-000             Wisconsin Electric Power   Upper Peninsula Power     Withdrawn 9/10/93.      
                                    Company.                   Company.                                         
4           TX93-4-000             Florida Municipal Power    Florida Power & Light     Granted. Final order, 67
                                    Agency.                    Company.                  FERC para. 61,167.     
                                                                                         Order on reh'g, 74 FERC
                                                                                         para. 61,006.          
5           TX94-1-000             Minnesota Municipal Power  Northern States Power     Granted. Proposed order,
                                    Agency.                    Company.                  66 FERC para. 61,114.  
                                                                                         Reh'g denied, 66 FERC  
                                                                                         para. 61,323 Settlement
                                                                                         accepted by letter     
                                                                                         order, 68 FERC para.   
                                                                                         61,031.                
6           TX94-2-000             El Paso Electric Company,  Southwestern Public       Proposed order, 68 FERC 
                                    et al.                     Service Company.          para. 61,182; order on 
                                                                                         reh'g, 68 FERC para.   
                                                                                         61,399; order dismiss'g
                                                                                         proceeding, 72 FERC    
                                                                                         para. 61,292.          
7           TX94-3-000             Minnesota Municipal Power  Southern Minnesota        Granted. Proposed order,
                                    Agency.                    Municipal Power Agency.   66 FERC para. 61,223;  
                                                                                         reh'g denied, 67 FERC  
                                                                                         para. 61,075; Final    
                                                                                         order, 68 FERC para.   
                                                                                         61,060.                
8           TX94-4-000             Tex-La Electric            Texas Utilities Electric  Granted. Proposed order,
                                    Cooperative of Texas,      Company.                  67 FERC para. 61,019;  
                                    Inc.                                                 Final order, 69 FERC   
                                                                                         para. 61,269.          
9           TX94-5-000             Old Dominion Electric      Delmarva Power & Light    Granted. Proposed order,
                                    Cooperative, Inc.          Company.                  68 FERC para. 61,169.  
                                                                                         Settl'd, 69 FERC para. 
                                                                                         61,436, 70 FERC para.  
                                                                                         61,082.                
10          TX94-6-000             Reading Municipal Light    16 New England            Terminated July 10, 1995
                                    Department.                Transmitting Utilities.   by OEPR Letter Order,  
                                                                                         following notice of    
                                                                                         withdrawal filed May 8,
                                                                                         1995.                  
11          TX94-7-000             AES Power, Inc...........  Tennessee Valley          Granted. Final Order    
                                                               Authority.                issued Feb. 29, 1996,  
                                                                                         74 FERC para. 61,220,  
                                                                                         reh'g pending.         
12          TX94-8-000             Duquesne Light Company...  PJM Companies...........  Granted. Proposed order 
                                                                                         issued 5/16/95, 71 FERC
                                                                                         para. 61,155.          
13          TX94-9-000             Borough of Zelienople,     Pennsylvania Power        Granted. Proposed order 
                                    Pennsylvania.              Company.                  issued 1/25/95, 70 FERC
                                                                                         para. 61,073.          
14          TX94-10-000            Duquesne Light Company...  Allegheny Power System..  Granted. Proposed order 
                                                                                         issued 5/16/95, 71 FERC
                                                                                         para. 61,156.          
15          TX95-1-000             Enron Power Marketing,     Consolidated Edison Co.   Pending. Comments due 11/
                                    Inc.                       of New York.              3/94.                  
16          TX95-2-000             Wisconsin Public Power     WEPCO, WP&L, WPSC.......  Pending. Comments due 11/
                                    Inc. SYSTEM.                                         16/94.                 
17          TX95-3-000             Municipal Energy Agency    Nebraska Public Power     w/drawn 11-16-95        
                                    of Nebraska.               District and Tri-State                           
                                                               Generation and                                   
                                                               Transmission                                     
                                                               Association, Inc.                                
18          TX95-4-000             American Municipal Power-  Ohio Edison Company.....  Granted. Proposed Order 
                                    Ohio, Inc.                                           issued Feb. 1, 1996 74 
                                                                                         FERC para. 61,086.     
19          TX95-5-000             United States Department   Southern Company System.  Pending.                
                                    of Energy--Southeastern                                                     
                                    Power Administration.                                                       
20          TX95-6-000             Cleveland Public Power...  Centerior Energy          Rejected Without        
                                                               Corporation.              Prejudice 72 FERC para.
                                                                                         61,189.                
21          TX95-7-000             Cleveland Public Power...  Cleveland Electric        Pending.                
                                                               Illuminating Company                             
                                                               and Toledo Edison                                
                                                               Company.                                         
22          TX96-1-000             Citizens Utilities         Swanton Village, Vermont  Pending.                
                                    Company.                                                                    

[[Page 21696]]

                                                                                                                
23          TX96-2-000             City of College Station,   City of Bryan, Texas and  Pending.                
                                    Texas.                     Texas Municipal Power                            
                                                               Agency.                                          
24          TX96-3-000             Citizens Utilities         Swanton Village, Vermont  Pending.                
                                    Company.                                                                    
25          TX96-4-000             Suffolk County Electrical  Long Island Lighting      Pending.                
                                    Agency.                    Company.                                         
26          TX96-5-000             United States Department   Public Service Company    Pending.                
                                    of Energy--Western Area    of New Mexico.                                   
                                    Power Administration.                                                       
27          TX96-6-000             Montana Power Company....  Basin Electric            Pending.                
                                                               Cooperative.                                     
28          TX96-7-000             City of Palm Springs,      Southern California       Pending.                
                                    California.                Edison Company.                                  
----------------------------------------------------------------------------------------------------------------



Appendix B--List of Commenters

------------------------------------------------------------------------
           Abbreviation                           Commenter             
------------------------------------------------------------------------
1. ABATE..........................  Association of Businesses Advocating
                                     Tariff Equity.                     
2. AEC & SMEPA....................  Alabama Electric Cooperative, Inc.  
                                     and South Mississippi Electric     
                                     Power Association.                 
3. AEP............................  American Electric Power System.     
4. AGA............................  American Gas Association.           
5. Air Liquide....................  Air Liquide America Corporation.    
6. AL Com.........................  Alabama Public Service Commission.  
7. ALCOA..........................  Aluminum Company of America.        
8. Allegheny......................  Allegheny Power Service Corporation.
9. Alma...........................  City of Alma, Michigan.             
10. Aluminum......................  Aluminum Association.               
11. American Forest & Paper.......  American Forest & Paper Association.
12. American Iron & Steel.........  American Iron & Steel Institute     
                                     American Forest & Paper            
                                     Association, American Public Power 
                                     Association, Chemical Manufacturers
                                     Association, Citizen Action,       
                                     Council of Industrial Boiler       
                                     Owners, Electricity Consumers      
                                     Resource Council, Environmental    
                                     Action Foundation, City of Las     
                                     Cruces, New Mexico, City of        
                                     Westbrook, Maine, Sovereign        
                                     California Cities Joint Powers     
                                     Committee, Toward Utility Rate     
                                     Normalization.                     
13. American National Power.......  American National Power, Inc.       
14. American Wind.................  American Wind Energy Association.   
15. AMP-Ohio......................  American Municipal Power-Ohio, Inc. 
                                     and Indiana Municipal Power Agency.
16. Anaheim.......................  Cities of Anaheim, Azusa, Banning,  
                                     Colton and Riverside, California.  
17. Anchorage.....................  Anchorage Municipal Light and Power.
18. Anoka EC......................  Anoka Electric Cooperative.         
19. APPA..........................  American Public Power Association.  
20. APS Customers.................  APS Wholesale Customer Group (Aquila
                                     Irrigation District, Buckeye Water 
                                     Conservation District, Electrical  
                                     District No. 3 of Pinal County,    
                                     Electrical District No. 6 of Pinal 
                                     County, Electrical District No. 7  
                                     of Maricopa County, Electrical     
                                     District No. 8 of Maricopa County, 
                                     Harquahala Valley Power District,  
                                     Maricopa County Municipal Water    
                                     Conservation District No. 1,       
                                     McMullan Valley Water Conservation 
                                     District, Roosevelt Irrigation     
                                     District and Tonopah Irrigation    
                                     District).                         
21. Arcadia.......................  Arcadia Resources, Inc.             
22. Arizona.......................  Arizona Public Service Company.     
23. Arizona EC....................  Arizona Electric Power Cooperative. 
24. Ark Elec......................  Arkansas Electric Cooperative       
                                     Corporation.                       
25. Arkansas Cities...............  Arkansas Cities and Farmers Electric
                                     Cooperative.                       
26. Associated EC.................  Associated Electric Cooperative,    
                                     Inc.                               
27. Associated Power..............  Associated Power Services, Inc.     
28. Atlantic City.................  Atlantic City Electric Company.     
29. AZ Com........................  Arizona Corporation Commission.     
30. Baker EC......................  Baker Electric Cooperative, Inc.    
31. Baltimore Transp Bureau.......  Transportation Bureau of Baltimore, 
                                     Inc.                               
32. Basin EC......................  Basin Electric Power Cooperative.   
33. BG&E..........................  Baltimore Gas and Electric Company. 
34. Big Horn REC..................  Big Horn Rural Electric Company.    
35. Big Rivers EC.................  Big Rivers Electric Cooperative.    
36. Black Hills EC................  Black Hills Electric Cooperative.   
37. Black Mayors..................  National Conference of Black Mayors.
38. Blue Ridge....................  Blue Ridge Power Agency, Northeast  
                                     Texas Electric Cooperative, Inc.,  
                                     Sam Rayburn G&T Electric           
                                     Cooperative, Inc., and Tex-La      
                                     Electric Cooperative of Texas, Inc.
39. Bon Homme Yankton EC..........  Bon Homme Yankton Electric          
                                     Association, Inc.                  
40. Boston Edison.................  Boston Edison Company.              
41. Boulder.......................  City of Boulder, Colorado.          
42. BPA...........................  Bonneville Power Administration.    
43. Brazos........................  Brazos Electric Power Cooperative,  
                                     Inc.                               
44. Brownsville...................  Brownsville, Texas Public Utilities 
                                     Board.                             
45. Building Owners...............  Building Owners and Managers        
                                     Association International.         
46. CA Cogen......................  Cogeneration Association of         
                                     California.                        
47. CA Com........................  California Public Utilities         
                                     Commission.                        

[[Page 21697]]

                                                                        
48. CA Energy Co..................  California Energy Company, Inc.     
49. CA Energy Com.................  California Energy Commission.       
50. Cajun.........................  Cajun Electric Power Cooperative,   
                                     Inc.                               
51. California DWR................  California Department of Water      
                                     Resources.                         
52. California Water Agencies.....  Association of California Water     
                                     Agencies.                          
53. Calpine.......................  Calpine Corporation.                
54. CAMU..........................  Colorado Association of Municipal   
                                     Utilities.                         
55. Canada........................  Canadian Embassy.                   
56. Canadian Petroleum Producers..  Canadian Association of Petroleum   
                                     Producers.                         
57. Caparo........................  Caparo Steel.                       
58. Carbon Power..................  Carbon Power & Light Inc.           
59. Carolina P&L..................  Carolina Power & Light Company.     
60. CCEM..........................  Coalition for a Competitive Electric
                                     Market (consisting of Catex Vitol  
                                     Electric, Inc., Coastal Electric   
                                     Services Company, Destec Power     
                                     Services, Inc., Electric           
                                     Clearinghouse, Inc., Enron Power   
                                     Marketing, Inc., Equitable Power   
                                     Services Company, KCS Power        
                                     Marketing, Inc. and MidCon Power   
                                     Services Corp.).                   
61. Centerior.....................  Centerior Energy Corporation.       
62. Central EC....................  Central Electric Power Cooperative. 
63. Central Hudson................  Central Hudson Gas & Electric       
                                     Corporation.                       
64. Central Illinois Light........  Central Illinois Light Company.     
65. Central Illinois Public         Central Illinois Public Service     
 Service.                            Company.                           
66. Central Louisiana.............  Central Louisiana Electric Company, 
                                     Inc.                               
67. Central Montana EC............  Central Montana Electric Power      
                                     Cooperative, Inc.                  
68. Christensen...................  Laurits R. Christensen Associates   
                                     Inc.                               
69. Chugach.......................  Chugach Electric Association, Inc.  
70. CINergy.......................  CINergy Corp.                       
71. Citizens Lehman...............  Citizens Lehman Power L.P.          
72. Citizens Utilities............  Citizens Utilities Company.         
73. Clark.........................  Clark Public Utilities.             
74. Clean Air.....................  Clean Air Action Corporation.       
75. Cleveland.....................  Cleveland Public Power.             
76. CO Com........................  Colorado Public Utilities Commission
                                     Staff.                             
77. CO Consumers Counsel..........  Colorado Office of Consumer Counsel.
78. Coalition for Economic          Coalition for Economic Competition  
 Competition.                        (consisting of Central Hudson Gas &
                                     Electric Corporation, Central Maine
                                     Power Company, Consolidated Edison 
                                     Company of New York, Inc., Illinois
                                     Power Company, Long Island Lighting
                                     Company, New York State Electric & 
                                     Gas Corporation, Niagara Mohawk    
                                     Power Corporation, Orange and      
                                     Rockland Utilities, Inc., and      
                                     Rochester Gas and Electric         
                                     Corporation.                       
79. Coalition on Federal-State      Coalition on Federal-State Issues of
 Issues.                             the Power Marketing Association.   
80. Com Ed........................  Commonwealth Edison Company.        
81. Com Electric..................  Commonwealth Electric Company.      
82. Competitive Enterprise........  Competitive Enterprise Institute.   
83. Concord.......................  Concord Municipal Light Plant.      
84. ConEd.........................  Consolidated Edison Company of New  
                                     York, Inc.                         
85. Conservation Law Foundation...  Conservation Law Foundation and     
                                     Center for Efficiency and Renewable
                                     Technologies.                      
86. Consolidated Natural Gas......  Consolidated Natural Gas Company.   
87. Consumers Power...............  Consumers Power Company.            
88. Continental Power Exchange....  Continental Power Exchange, Inc.    
89. Cooperative Power.............  Cooperative Power.                  
90. CSW...........................  Central and South West Corporation. 
91. CT DPUC.......................  Connecticut Department of Public    
                                     Utility Control.                   
92. CT Munis......................  Connecticut Conference of           
                                     Municipalities.                    
93. CVPSC.........................  Central Vermont Public Service      
                                     Corporation.                       
94. Dairyland.....................  Dairyland Power Cooperative.        
95. Dayton P&L....................  Dayton Power and Light Company.     
96. DC Com........................  Public Service Commission of the    
                                     District of Columbia.              
97. DE Muni.......................  Delaware Municipal Electric         
                                     Corporation, Inc.                  
98. DE, DC, NJ and MD Coms........  Delaware Public Service Commission, 
                                     District of Columbia Public Service
                                     Commission, Maryland Public Service
                                     Commission, and New Jersey Board of
                                     Public Utilities.                  
99. Deloitte & Touche.............  Deloitte & Touche LLP.              
100. Destec.......................  Destec Energy.                      
101. Detroit Edison...............  Detroit Edison Company.             
102. Detroit Edison...............  Detroit Edison Wholesale Customers  
                                     (consisting of City of Croswell,   
                                     Michigan, and Thumb Electric       
                                     Cooperative).                      
103. Direct Service Industries....  Direct Service Industries           
                                     (consisting of ELF Atochem North   
                                     America, Inc., Columbia Columbia   
                                     Aluminum Corporation, Columbia     
                                     Falls Aluminum Co., Georgia        
                                     Pacific, Kaiser Aluminum & Chemical
                                     Corporation, Intalco Aluminum,     
                                     Northwest Aluminum Company,        
                                     Reynolds Metals Company and        
                                     Vanalco, Inc.).                    
104. DOD..........................  Department of Defense.              
105. DOE..........................  United States Department of Energy. 
106. DOJ..........................  United States Department of Justice.
107. Dominion.....................  Dominion Resources.                 
108. Douglas EC...................  Douglas Electric Cooperative, Inc.  
109. Duke.........................  Duke Power Company.                 

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110. Duquesne.....................  Duquesne Light Company.             
111. East Kentucky................  East Kentucky Power Cooperative, Big
                                     Rivers Electric Corporation, and   
                                     Hoosier Energy Rural Electric      
                                     Cooperative.                       
112. East River EC................  East River Electric Power           
                                     Cooperative.                       
113. EDS Utilities................  Electronic Data Systems Inc.,       
                                     Utilities Division (Joussef Heguzy,
                                     Clifford J. Meagh, Julius A.       
                                     Wright).                           
114. Education....................  American Council on Education and   
                                     the National Association of College
                                     and University Business Officers   
115...............................  EEI Edison Electric Institute.      
116. EGA..........................  Electric Generation Association.    
117. El Paso......................  El Paso Electric Company.           
118. ELCON........................  Electricity Consumers Resource      
                                     Council, American Iron and Steel   
                                     Institute, Chemical Manufacturers  
                                     Association and Council of         
                                     Industrial Boiler Owners.          
119. Electric Consumers Alliance..  Electric Consumers' Alliance.       
120. Electronic Data Systems......  EDS Utilities Division (James F.    
                                     Susman).                           
121. ENEREX.......................  ENEREX, Inc.                        
122. Entergy......................  Entergy Services, Inc.              
123. Entergy Retail Regulators....  Arkansas Public Service Commission, 
                                     City Council of New Orleans,       
                                     Louisiana Public Service           
                                     Commission, and Mississippi Public 
                                     Service Commission.                
124. Environmental Action.........  Environmental Action Foundation.    
125. EPA..........................  United States Environmental         
                                     Protection Agency.                 
126. Fertilizer Institute.........  The Fertilizer Institute.           
127. FL Com.......................  Florida Public Service Commission.  
128. Florida Power Corp...........  Florida Power Corporation.          
129. FPL..........................  Florida Power & Light Company.      
130. Freedom Energy Co............  Freedom Energy Company, LLC.        
131. FTC..........................  United States Federal Trade         
                                     Commission, Staff of the Bureau of 
                                     Economics.                         
132. Fuel Managers................  Fuel Managers Association.          
133. GA Com.......................  Georgia Public Service Commission.  
134. GAPP Committee...............  General Agreement of Parallel Paths 
                                     Committee (A. Garfield).           
135. Graves.......................  Graves, Frank and Ilic, Marija.     
136. Green Mountain...............  Green Mountain Power Corporation.   
137. Heartland....................  Heartland Consumers Power District. 
138. Hogan........................  Hogan, William W.                   
139. Home Builders................  National Association of Home        
                                     Builders.                          
140. Homelessness Alliance........  National Alliance to End            
                                     Homelessness, Inc.                 
141. Hoosier EC...................  Hoosier Energy Rural Electric       
                                     Cooperative.                       
142. Hopkinsville EC..............  Hopkinsville Electric System.       
143. Houston L&P..................  Houston Lighting & Power Company.   
144. Hydro-Quebec.................  Hydro-Quebec.                       
145. IA Com.......................  Iowa Utilities Board.               
146. IBM..........................  International Business Machines.    
147. ID Com.......................  Idaho Public Utilities Commission.  
148. Ida County REC...............  Ida County Rural Electric           
                                     Cooperative.                       
149. Idaho........................  Idaho Power Company.                
150. IES Utilities................  IES Utilities Inc.                  
151. IL Com.......................  Illinois Commerce Commission.       
152. IL Industrials...............  Illinois Industrial Energy          
                                     Consumers.                         
153. Illinois Municipal Electric    Illinois Municipal Electric Agency. 
 Agency.                                                                
154. Illinois Power...............  Illinois Power Company.             
155. IN Com.......................  Indiana Utility Regulatory          
                                     Commission.                        
156. IN Industrials...............  Indiana Industrial Energy Consumers,
                                     Inc.                               
157. Industrial Energy              Industrial Energy Applications.     
 Applications.                                                          
158. Inland Power Pool............  Inland Power Pool.                  
159. IPALCO.......................  IPALCO Enterprises, Inc.            
160. James Valley EC..............  James Valley Electric Cooperative,  
                                     Inc.                               
161. Jay..........................  Town of Jay, Maine and the Jay Power
                                     District.                          
162. KCPL.........................  Kansas City Power & Light Company.  
163. Knoxville....................  Knoxville Utilities Board.          
164. KS Com.......................  Kansas Corporation Commission Staff.
165. KU...........................  Kentucky Utilities Company.         
166. KY AG........................  Kentucky Attorney General.          
167. KY Com.......................  Kentucky Public Service Commission. 
168. LA DWP.......................  Department of Water and Power of the
                                     City of Los Angeles.               
169. LA Industrials...............  Louisiana Energy Users Group.       
170. La Raza......................  National Council of La Raza.        
171. Las Cruces...................  City of Las Cruces, New Mexico.     
172. Latin League.................  League of United Latin American     
                                     Citizens.                          
173. Legal Environmental            Legal Environmental Assistance      
 Assistance.                         Foundation.                        
174. LEPA.........................  Louisiana Energy and Power          
                                     Authority.                         
175. Lester Fink..................  Fink, Lester.                       
176. LG&E.........................  LG&E Energy Corp.                   
177. LILCO........................  Long Island Lighting Company.       
178. Lincoln-Union EC.............  Lincoln-Union Electric Company.     

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179. Lively.......................  Lively, Mark B.                     
180. Local Furnishing Utilities...  Local Furnishing Utilities (Long    
                                     Island Lighting Company, Nevada    
                                     Power Company, and San Diego Gas & 
                                     Electric Company).                 
181. Lower Colorado River           Lower Colorado River Authority.     
 Authority.                                                             
182. LPPC.........................  Large Public Power Council.         
183. MA DPU.......................  Massachusetts Department of Public  
                                     Utilities.                         
184. Madison G&E..................  Madison Gas & Electric Company.     
185. Maine Public Service.........  Maine Public Service Company.       
186. Maritime.....................  Maritime Electric Company.          
187. McKenzie EC..................  McKenzie Electric Cooperative, Inc. 
188. MD Com.......................  Maryland Public Service Commission. 
189. ME Consumer-Owned Utilities..  Maine Consumer-Owned Utilities      
                                     (consisting of Eastern Maine       
                                     Electric Cooperative, Inc., Fox    
                                     Islands Electric Cooperative, Inc. 
                                     Houlton Water Company, Isle au Haut
                                     Electric Power Co., Kennebunk Light
                                     & Power District, Madison Electric 
                                     Works, Swans Island Electric       
                                     Cooperative, Inc., and Van Buren   
                                     Light & Power District).           
190. ME Industrials...............  Industrial Energy Consumer Group of 
                                     Maine.                             
191. MEAG.........................  Municipal Electric Authority of     
                                     Georgia.                           
192. Memphis......................  Memphis Light, Gas and Water        
                                     Division.                          
193. Mercer.......................  Mercer, Dorothy Ph.D.               
194. MI Com.......................  Michigan Public Service Commission. 
195. MI MEA.......................  Municipal Energy Agency of          
                                     Mississippi.                       
196. Michigan Coalition...........  Consumers Power, Detroit Edison and 
                                     Michigan Public Service Commission.
197. Michigan Systems.............  Florida Municipal Power Agency,     
                                     Michigan Public Power Agency,      
                                     Michigan South Central Power       
                                     Agency, Michigan Public Power      
                                     Ratepayers Association and         
                                     Wolverine Power Supply Cooperative.
198. MidAmerican..................  MidAmerican Energy Company.         
199. Midwest Commissions..........  Arkansas, Kansas & Missouri State   
                                     Commissions.                       
200. Minnesota P&L................  Minnesota Power & Light Company.    
201. Missouri Basin Group.........  Missouri Basin Systems Group, Inc.  
202. Missouri Basin MPA...........  Missouri Basin Municipal Power      
                                     Agency.                            
203. Missouri Joint Commission....  Missouri Joint Municipal Electric   
                                     Utilities Commission.              
204. Missouri-Kansas Industrials..  Missouri-Kansas Industrial Energy   
                                     Consumers.                         
205. MMWEC........................  Massachusetts Municipal Wholesale   
                                     Electric Company.                  
206. MN DPS.......................  Minnesota Department of Public      
                                     Service.                           
207. Montana Power................  Montana Power Company.              
208. Montana-Dakota Utilities.....  Montana-Dakota Utilities Company.   
209. Montaup......................  Montaup Electric Company.           
210. Mor-Gran-Sou EC..............  Mor-Gran-Sou Electric Cooperative.  
211. Mountain States Petroleum      Independent Petroleum Association of
 Assoc.                              Mountain States and Colorado Oil   
                                     and Gas Association.               
212. MS Com.......................  Mississippi Public Service          
                                     Commission.                        
213. MT Com.......................  Montana Public Service Commission.  
214. MT Dept of Environmental       Montana Department of Environmental 
 Quality.                            Quality.                           
215. Mt. Hope Hydro...............  Mt. Hope Hydro, Inc.                
216. Municipal Energy Agency        Municipal Energy Agency of Nebraska.
 Nebraska.                                                              
217. NARUC........................  National Association of Regulatory  
                                     Utility Commissioners.             
218. NASUCA.......................  National Association of State       
                                     Utility Consumer Advocates.        
219. National Hydropower..........  National Hydropower Association.    
220. National Women's Caucus......  National Women's Political Caucus.  
221. Natural Resources Defense....  Natural Resources Defense Council   
                                     and Pacific Gas and Electric       
                                     Company.                           
222. NC Com.......................  North Carolina Utilities Commission.
223. NCMPA........................  North Carolina Municipal Power      
                                     Agency Number 1.                   
224. NCPA.........................  Northern California Power Agency.   
225. ND Com.......................  North Dakota Public Service         
                                     Commission.                        
226. NE Public Power District.....  Nebraska Public Power District.     
227. NE States Air Management.....  Northeast States for Coordinated Air
                                     Use Management.                    
228. NEPCO........................  New England Power Company.          
229. NEPOOL.......................  New England Power Pool Executive    
                                     Committee.                         
230. NEPOOL Review Committee......  New England Public Power NEPOOL     
                                     Review Committee.                  
231. NERC.........................  North American Electric Reliability 
                                     Council.                           
232. Nevada.......................  Nevada Power Company.               
233. New Brunswick................  New Brunswick Power.                
234. NGSA.........................  Natural Gas Supply Association.     
235. NH Com.......................  New Hampshire Public Utilities      
                                     Commission.                        
236. NH General Court.............  Retail Wheeling & Restructuring     
                                     Committee of the New Hampshire     
                                     General Court.                     
237. NIEP.........................  National Independent Energy         
                                     Producers.                         
238. NIMO.........................  Niagara Mohawk Power Corporation.   
239. NIPSCO.......................  Northern Indiana Public Service     
                                     Company.                           
240. NJ BPU.......................  New Jersey Board of Public          
                                     Utilities.                         
241. NJ Ratepayer Advocate........  New Jersey Division of the Ratepayer
                                     Advocate.                          
242. NM Com.......................  New Mexico Public Utility           
                                     Commission.                        
243. NM Industrials...............  New Mexico Industrial Energy        
                                     Consumers.                         
244. NorAm........................  NorAm Energy Services, Inc.         
245. Nordhaus.....................  Nordhaus, William D.                
246. North Dakota RECs............  North Dakota Association of Rural   
                                     Electric Cooperatives.             

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247. NRECA........................  National Rural Electric Cooperative 
                                     Association.                       
248. NRECA/APPA...................  National Rural Electric Cooperative 
                                     Association and APPA.              
249. NRRI.........................  National Regulatory Research        
                                     Institute.                         
250. NSP..........................  Northern States Power Company.      
251. NU...........................  Northeast Utilities System          
                                     Companies.                         
252. Nuclear Energy Institute.....  Nuclear Energy Institute.           
253. Nucor........................  Nucor Corporation.                  
254. NV Com.......................  Public Service Commission of Nevada.
255. NW Conservation Act Coalition  Northwest Conservation Act          
                                     Coalition.                         
256. NW Iowa Cooperative..........  Northwest Iowa Power Cooperative.   
257. NW Power Planning Council....  Northwest Power Planning Council.   
258. NWRTA........................  Northwest Regional Transmission     
                                     Association.                       
259. NY AG........................  New York State Attorney General.    
260. NY Com.......................  Public Service Commission of the    
                                     State of New York.                 
261. NY Consumer Protection.......  New York Consumer Protection Board. 
262. NY Energy Buyers.............  New York Energy Buyers Forum.       
263. NY Industrials...............  Multiple Industrial Intervenors of  
                                     New York.                          
264. NY IOUs......................  Long Island Lighting, New York State
                                     Electric & Gas and Rochester Gas & 
                                     Elec.                              
265. NY Mayors....................  New York State Conference of Mayors 
                                     and Municipal Officals.            
266. NYMEX........................  New York Mercantile Exchange.       
267. NYPP.........................  New York Power Pool.                
268. NYSEG........................  New York State Electric & Gas       
                                     Corporation.                       
269. Oahe EC......................  Oahe Electric Cooperative, Inc.     
270. Oak Ridge....................  Oak Ridge National Laboratory.      
271. Occidental Chemical..........  Occidental Chemical Corporation.    
272. Oglethorpe...................  Oglethorpe Power Corporation.       
273. OH Com.......................  Public Utilities Commission of Ohio.
274. OH Coops.....................  Ohio Rural Electric Cooperatives,   
                                     Inc. and Buckeye Power, Inc.       
275. OH Industrials...............  Industrial Energy Users--Ohio.      
276. Ohio Edison..................  Ohio Edison Company.                
277. Ohio Manufacturers...........  Ohio Manufacturers' Association.    
278. Ohio Valley..................  Ohio Valley Electric Corporation.   
279. OK Com.......................  Oklahoma Corporation Commission.    
280. Oklahoma G&E.................  Oklahoma Gas and Electric Company.  
281. Old Dominion EC..............  Old Dominion Electric Cooperative,  
                                     Inc.                               
282. Oliver-Mercer EC.............  Oliver-Mercer Electric Cooperative, 
                                     Inc.                               
283. Omaha PPD....................  Omaha Public Power District.        
284. Ontario Hydro................  Ontario Hydro.                      
285. Orange & Rockland............  Orange and Rockland Utilities, Inc. 
286. Oregon Trail EC..............  Oregon Trail Electric Cooperative,  
                                     Inc.                               
287. Otter Tail...................  Otter Tail Power Company.           
288. PA Com.......................  Pennsylvania Public Utility         
                                     Commission.                        
289. PA Coops.....................  Pennsylvania Rural Electric         
                                     Association and Allegheny Electric 
                                     Cooperative, Inc.                  
290. PA Industrials...............  Industrial Energy Consumers of      
                                     Pennsylvania.                      
291. PA Munis.....................  Pennsylvania Municipal Electric     
                                     Association.                       
292. Pacific Northwest Coop.......  Pacific Northwest Generating        
                                     Cooperative.                       
293. PacifiCorp...................  PacifiCorp.                         
294. Panhandle Coop...............  Panhandle Rural Electric Membership 
                                     Association.                       
295. PECO.........................  PECO Energy Company.                
296. Pennsylvania P&L.............  Pennsylvania Power & Light Company. 
297. PG&E.........................  Pacific Gas and Electric Company.   
298. Phelps Dodge.................  Phelps Dodge Corporation.           
299. Philip Morris................  Philip Morris Management Corp.      
300. PJM..........................  PJM--Pennsylvania New Jersey        
                                     Maryland Interconnection.          
301. Portland.....................  Portland General Electric Company.  
302. Power Marketing Association..  Power Marketing Association.        
303. PSE&G........................  Public Service Electric and Gas     
                                     Company.                           
304. PSNM.........................  Public Service Company of New       
                                     Mexico.                            
305. Public Generating Pool.......  Public Generating Pool.             
306. Public Power Council.........  Public Power Council.               
307. Public Service Co of CO......  Public Service Company of Colorado  
                                     and Cheyenne Light, Fuel and Power 
                                     Company.                           
308. Puget........................  Puget Sound Power & Light Company.  
309. Redding......................  Cities of Redding and Santa Clara,  
                                     California.                        
310. Reynolds.....................  Reynolds Metals Company.            
311. Rochester G&E................  Rochester Gas and Electric          
                                     Corporation.                       
312. Rocky Mountain Institute.....  Rocky Mountain Institute (Amory     
                                     Lovins).                           
313. Rosebud......................  Rosebud Enterprises, Inc.           
314. RUS..........................  Rural Utilities Service (formerly   
                                     REA).                              
315. Rushmore EC..................  Rushmore Electric Power Cooperative,
                                     Inc.                               
316. Salt River...................  Salt River Project Agriculture      
                                     Improvement and Power District.    
317. San Diego G&E................  San Diego Gas & Electric Company.   
318. San Francisco................  City and County of San Francisco.   
319. San Luis Valley REC..........  San Luis Valley Rural Electric      
                                     Cooperative.                       
320. SBA..........................  United States Small Business        
                                     Administration, Office of Advocacy.

[[Page 21701]]

                                                                        
321. SC Com.......................  South Carolina Public Service       
                                     Commission.                        
322. SCE&G........................  South Carolina Electric & Gas       
                                     Company.                           
323. SC Public Service Authority..  South Carolina Public Service       
                                     Authority.                         
324. Seattle......................  Seattle City Light Department.      
325. Seminole EC..................  Seminole Electric Cooperative, Inc. 
326. SEPA.........................  Southeastern Power Administration/  
                                     Federal Power Customers.           
327. Shelby County................  Shelby County Board of              
                                     Commissioners.                     
328. Sierra.......................  Sierra Pacific Power Company.       
329. Slope EC.....................  Slope Electric Cooperative Inc.     
330. SMUD.........................  Sacramento Municipal Utility        
                                     District.                          
331. Snohomish....................  Public Utility District No. 1 of    
                                     Snohomish County, Washington.      
332. SoCal Edison.................  Southern California Edison Company. 
333. SoCal Gas....................  Southern California Gas Company.    
334. South Jersey Gas.............  South Jersey Gas Company.           
335. Southern.....................  Southern Company Services, Inc.     
336. Southwest TDU Group..........  Southwest Transmission Dependent    
                                     Utility Group (consisting of Aguila
                                     Irrigation District, Ak-Chin Indian
                                     Community, Buckeye Irrigation      
                                     District, Central Arizona Water    
                                     Conservation District, Electrical  
                                     District No. 3, No. 4, No. 5, No.  
                                     6, No. 7, Harquahala Valley Power  
                                     District, Maricopa Water District, 
                                     McMullen Valley Water Conservation 
                                     and Drainage District, City of     
                                     Needles, Roosevelt Irrigation      
                                     District, City of Safford, Tonopah 
                                     Irrigation District, Wellton-Mohawk
                                     Irrigation and Drainage District). 
337. Southwestern.................  Southwestern Public Service Company.
338. Soyland......................  Soyland Power Cooperative.          
339. Spink EC.....................  Spink Electric, Redfield, SD.       
340. SPP..........................  Southwest Power Pool, Inc.          
341. Springfield..................  City Utilities of Springfield,      
                                     Missouri.                          
342. St. Joseph...................  St. Joseph Light & Power Company.   
343. Suffolk County...............  Suffolk County (New York) Electric  
                                     Agency.                            
344. Sunflower....................  Sunflower Electric Power            
                                     Corporation.                       
345. Supervised Housing...........  State and City Supervised Housing   
                                     for Equity in Electric Rates.      
346. Sustainable Energy Policy....  Project For Sustainable FERC Energy 
                                     Policy (on behalf of Alliance for  
                                     Affordable Energy, Citizens Action 
                                     Coalition of Indiana, Conservation 
                                     Law Foundation, Environmental      
                                     Defense Fund, Environmental Law &  
                                     Policy Center of the Midwest, Izaak
                                     Walton League of America, Land and 
                                     Water Fund of the Rockies, Legal   
                                     Environmental Assistance           
                                     Foundation, Mid-Atlantic Energy    
                                     Project, Minnesotans for an Energy-
                                     Efficient Economy, Natural         
                                     Resources Defense Council,         
                                     Northwest Conservation Act         
                                     Coalition, Pace Energy Project,    
                                     Public Citizen, Texas, RENEW       
                                     Wisconsin, Southern Environmental  
                                     Law Center, Texas Ratepayers'      
                                     Organization to Save Energy, Union 
                                     of Concerned Scientists, and       
                                     Wisconsin's Environmental Decade). 
347. Tallahassee..................  City of Tallahassee, Florida.       
348. Tampa........................  Tampa Electric Company.             
349. TANC.........................  Transmission Agency of Northern     
                                     California.                        
350. TAPS.........................  Transmission Access Policy Study    
                                     Group.                             
351. TDU Systems..................  Transmission Dependent Utility      
                                     Systems (Arkansas Electric         
                                     Cooperative Corporation,           
                                     Connecticut Municipal Electric     
                                     Energy Cooperative, Golden Spread  
                                     Electric Cooperative, Inc., Holy   
                                     Cross Electric Association, Inc.,  
                                     Kansas Electric Power Cooperative, 
                                     Inc., Magic Valley Electric        
                                     Cooperative, Inc., Mid-Tex         
                                     Generation & Transmission Electric 
                                     Cooperative, Inc., NewCorp         
                                     Resources, Inc., Old Dominion      
                                     Electric Cooperative, Inc.).       
352. Texaco.......................  Texaco Inc.                         
353. Texas Utilities..............  Texas Utilities Electric Company.   
354. Texas-New Mexico.............  Texas-New Mexico Power Company.     
355. Tonko........................  Tonko, Paul D. (NY State Assembly). 
356. Torco........................  Torco Energy Marketing, Inc.        
357. Total Petroleum..............  Total Petroleum, Inc.               
358. Traverse EC..................  Traverse Electric Cooperative, Inc. 
359. Tri-County EC................  Tri-County Electric Association,    
                                     Inc.                               
360. Tri-State G&T................  Tri-State Generation and            
                                     Transmission Association, Inc.     
361. Tucson Power.................  Tucson Electric Power Company.      
362. Turlock......................  Turlock Irrigation District.        
363. Turner-Hutchinson EC.........  Turner-Hutchinson Electric          
                                     Cooperative, Inc.                  
364. TVA..........................  Tennessee Valley Authority.         
365. TX Com.......................  Public Utility Commission of Texas. 
366. TX Industrials...............  Texas Industrial Energy Consumers.  
367. UAMPS........................  Utah Associated Municipal Power     
                                     Systems.                           
368. Union County EC..............  Union County Electric Cooperative,  
                                     Inc.                               
369. Union Electric...............  Union Electric Company.             
370. United Illuminating..........  United Illuminating Company.        
371. UNITIL.......................  UNITIL Corporation.                 
372. Urban League.................  Greater Washington Urban League,    
                                     Inc.                               
373. UT Com.......................  Utah Public Service Commission and  
                                     Utah Division of Public Utilities. 
374. UT Industrials...............  Utah Industrial Energy Consumers    
                                     (consisting of Alliant Techsystems,
                                     Inc., Amoco Oil Company, Holnam,   
                                     Inc., Kennecott Copper Corp., and  
                                     Western Zirconium.                 
375. UtiliCorp....................  UtiliCorp United Inc.               

[[Page 21702]]

                                                                        
376. Utilities For Improved         Utilities For an Improved Transition
 Transition.                         (consisting of Basin Electric      
                                     Cooperative, Black Hills           
                                     Corporation, Boston Edison Company,
                                     Central Vermont Public Service     
                                     Corporation, Montaup Electric      
                                     Company, Wisconsin Electric Power  
                                     Company, and Wisconsin Public      
                                     Service Corporation).              
377. Utility--Trade Corp. Utility--                                     
 Trade Corp..                                                           
378. Utility Investors Analysts...  Utility Investors and Analysts.     
379. Utility Shareholders.........  United Utility Shareholders         
                                     Association of America.            
380. Utility Wind Interest Group..  Utility Wind Interest Group, Inc.   
381. Utility Workers Union........  Utility Workers Union of America,   
                                     AFL-CIO.                           
382. Utility Working Group........  Utility Working Group (consisting of
                                     Atlantic City Electric Company,    
                                     Dominion Resources, Inc., Duke     
                                     Power Company, Florida Power &     
                                     Light Company, Niagara Mohawk Power
                                     Corporation, Pacific Gas and       
                                     Electric Company, Public Service   
                                     Electric and Gas Company, and San  
                                     Diego Gas & Electric Company).     
383. VA Com.......................  Staff of the Virginia State         
                                     Corporation Commission.            
384. Vann.........................  Vann, Albert (NY State Assembly).   
385. VEPCO........................  Virginia Electric and Power Company.
386. Verendrye EC.................  Verendrye Electric Cooperative, Inc.
387. Vernon.......................  City of Vernon, California.         
388. VT DPS.......................  Vermont Department of Public        
                                     Service.                           
389. WA Com.......................  Washington Utilities and            
                                     Transportation Commission.         
390. Wabash.......................  Wabash Valley Power Association,    
                                     Inc.                               
391. WAPA.........................  Western Area Power Administration   
                                     and Department of Energy.          
392. Washington and Oregon Energy   Washington State Energy Office and  
 Offices.                            Oregon Department of Energy.       
393. Washington Water Power.......  Washington Water Power Company      
                                     Energy Offices.                    
394. WEPCO........................  Wisconsin Electric Power Company.   
395. West River EC................  West River Electric Association,    
                                     Inc.                               
396. Western Resources............  Western Resources Inc.              
397. Whetstone Valley EC..........  Whetstone Valley Electric           
                                     Cooperative, Inc.                  
398. WI Com.......................  Public Service Commission of        
                                     Wisconsin.                         
399. Wing Group...................  Wing Group.                         
400. Wisconsin Coalition..........  Wisconsin Coalition (Wisconsin      
                                     Public Power Incorporated System,  
                                     Municipal Electric Utilities of    
                                     Wisconsin, Madison Gas and Electric
                                     Company, and Citizens' Utility     
                                     Board of Wisconsin).               
401. Wisconsin EC.................  Wisconsin Electric Cooperative      
                                     Association.                       
402. Wisconsin Municipals.........  Municipal Electric Utilities of     
                                     Wisconsin.                         
403. Wollenberg...................  Wollenberg, Bruce, et al.           
404. Wolverine Coop Members.......  Wolverine Power Supply Cooperative  
                                     Special Members Committee.         
405. Woodbury County REC..........  Woodbury County Rural Electric      
                                     Cooperative.                       
406. WP&L.........................  Wisconsin Power and Light Company.  
407. WSCC.........................  Western Systems Coordinating Council
                                     Board of Trustees.                 
408. WSPP.........................  Western Systems Power Pool.         
409. Yellowstone Valley EC........  Yellowstone Valley Electric         
                                     Cooperative, Inc.                  
------------------------------------------------------------------------



Environmental Impact Commenters

1. Attorneys General of Massachusetts, Connecticut, New Jersey and 
Vermont
2. Center for Clean Air Policy
3. Central Maine Power Company
4. Cincinnati Gas & Electric Company and PSI Energy, Inc.
5. Clifton Below
6. Electric Consumer's Alliance
7. Connecticut Siting Council
8. Southern Environmental Law Center
9. General Public Utilities Corporation
10. Public Advisory Committee of the Grand Canyon Visibility 
Transport Commission
11. Institute of Clean Air Companies
12. Interstate Natural Gas Association of America
13. Atlantic Electric Co. and Audubon Society of New Hampshire et 
al.
14. Maryland Department of Natural Resources and Maryland Energy 
Administration
15. Midwest Ozone Group
16. Missouri Department of Natural Resources
17. National Mining Association, Western Fuels Association, Inc. and 
the Center for Energy and Economic Efficiency
18. The Navajo Nation
19. Maine, Massachusetts, Vermont and New Hampshire Public Service 
Commissions
20. New Jersey Board of Public Utilities and the New Jersey 
Department of Environmental Protection
21. New York State Department of Public Service and the New York 
State Department of Environmental Conservation
22. Office of the Ohio Consumers' Counsel
23. Ohio Electric Utility Institute Environmental Committee
24. Ozone Transport Assessment Group
25. Ozone Transport Commission
26. Utility Air Regulatory Group (Edison Electric Institute, the 
National Rural Electric Cooperative Association and the American 
Public Power Association)
27. Wisconsin Department of Natural Resources

Other (Including Technical Conference Commenters)

1. Electric Power Research Institute
2. Electric Policy Technical Issues Group
3. Tejas Power Corporation
4. Competitive Power Coalition of New England
5. Mid-Continent Area Power Pool
6. Michigan Electric Coordinated Systems
7. Independent Energy Producers Association
8. Praxair, Inc.
9. Utility-Trade Corp.
10. Competitive Power Coalition of New England
11. Wyoming Public Service Commission
12. State of New Jersey
13. Paul Joskow
14. New England Conference of Public Utility Commissioners
15. Commonwealth of Massachusetts
16. Florida Electric Power Coordinating Group
17. Dine Power Authority
18. State of Connecticut Department of Environmental Protection
19. Commonwealth of Massachusetts Department of Environmental 
Protection
20. State of Maine Department of Environmental Protection
21. Comision Federal de Electricidad of Mexico

Appendix C--Allegations of Public Utilities Exercising Transmission 
Dominance

I. Examples From Proceedings Before Administrative Law Judges

    These are examples of allegations that various public utilities 
have refused to

[[Page 21703]]

provide comparable service, either through refusals to wheel, 
dilatory tactics that so protracted negotiations as to effectively 
deny wheeling, refusals to provide service priority equal to native 
load, or refusals to provide service flexibility equivalent to the 
utility's own use.

A. American Electric Power Service Corp. (AEP)

    In 1993, AEP filed, on behalf of its public utility associate 
companies, an open access tariff that offered only firm point-to-
point service with very limited flexibility. It did not offer 
network service, flexible point-to-point service, or non-firm 
service. Thus, it did not provide customers with the same 
flexibility that AEP itself has. Nor did it provide a service 
priority equivalent to that enjoyed by native load. The Commission 
set AEP's tariff for hearing and, on rehearing, held that in order 
not to be unduly discriminatory, the tariff had to offer comparable 
service. American Electric Power Service Corp., 64 FERC para. 61,279 
(1993), reh'g, 67 FERC para. 61,168 (1994).
    At hearing, Raj Rao of Indiana Michigan Power Agency (IMPA) (Ex. 
IMPA-1, Feb 23, 1994) and Kenneth Hegemann of American Municipal 
Power-Ohio, Inc. (AMP-Ohio) (Ex. AMPO-1, Feb 23, 1994), both senior 
management officials, testified concerning AEP's alleged 
discriminatory practices.<SUP>1 AMP-Ohio is an association of 
municipalities in Ohio, some of whose members depend on AEP for 
transmission and partial requirements service. IMPA is an 
association of municipalities in Indiana, and many of IMPA's loads 
are captive to the AEP transmission system. The witnesses alleged as 
follows:
---------------------------------------------------------------------------

    \1\ After the Rehearing Order expanding the scope of the 
proceeding, AMP-Ohio and IMPA withdrew this testimony as no longer 
necessary. This withdrawal does not change the fact that the 
testimony was sworn to under oath.
---------------------------------------------------------------------------

    1. In anticipation of high peak demands, AEP would contract for 
large blocks of available short-term power, withhold sale of short-
term power, refuse to transmit third party short-term power, and 
require purchases from AEP at the emergency rate (100 mill/kwh) when 
an emergency might not exist. Ex. AMPO-1 at 6.
    2. In December 1989, AMP-Ohio negotiated a 20 MW purchase of 
short-term power from Louisville Gas & Electric Company (LG&E). AEP 
refused to wheel because LG&E had earlier that day told AEP it had 
no power to sell to AEP. AEP then bought the power from LG&E and 
offered to resell it to AMP-Ohio. Ex. AMPO-1 at 6-7.
    3. In January 1990, AMP-Ohio solicited bids for February power 
purchases from a number of utilities including AEP. AEP was not the 
winning bid. AMP-Ohio made arrangements to purchase the power from 
four winning bidders and sought transmission through AEP. When AMP-
Ohio gave AEP the schedule for delivery, AEP refused to transmit the 
power, matched the average price of the winning bids, and made the 
sale itself. Ex. AMPO-1 at 7.
    4. In August 1993, an AMP-Ohio member (Columbus, Ohio) was 
purchasing 10 MW of hourly non-displacement power from AEP and, 
after AEP raised its price to 60 mills/kwh, sought another source 
for the next hour. Consumers Power Company and Detroit Edison 
Company both offered non-displacement power at 40 mills. AEP refused 
to transmit, saying it had a 600 MW unit out and could not resell 
power from another source.<SUP>2 Columbus cancelled the transaction 
and had to buy 10 MW of power from AEP at 100 mills/kwh. Ex. AMPO-1 
at 7-8.
---------------------------------------------------------------------------

    \2\ AEP generally limited its offer of short-term transmission 
to buy/sell transactions; that is, AEP would buy the power from the 
seller and resell it to the purchaser. Supplemental testimony of AEP 
Witness Baker (Ex. A-73) at 27-29. Often, the terms of the buy/sell 
transaction required transmission dependent utilities (TDUs) to 
maintain reserves and meet contractual commitments for at least a 
year. Id.
---------------------------------------------------------------------------

    5. In July 1993, two AMP-Ohio members (Columbus and St. Mary's) 
had been buying hourly non-displacement power from AEP when the 
price rose to 35 mills. Dayton Power & Light Company (DP&L) offered 
to sell at 23 mills and AEP agreed to transmit for one hour. But for 
the next hour, AEP said it had problems with its system, refused to 
transmit the power, kept the power from DP&L for itself and offered 
to sell power to AMP-Ohio for Columbus and St. Mary's at 100 mills. 
Columbus increased its local generation, but St. Mary's purchased 8 
MW at 100 mills. For the next hour, AMP-Ohio arranged with DP&L for 
another 8 MW, hoping AEP would transmit under the 24 hour buy-sell 
agreement. AEP did transmit this power. Seven hours later in the 
day, St. Mary's Greenup Hydro project power was available and the 8 
MW from DP&L was no longer needed. If St. Mary's had been receiving 
the hourly power that AEP had refused to transmit, St. Mary's could 
have switched to Greenup power. But because AMP-Ohio had changed to 
daily service, St. Mary's had to pay a demand charge for the entire 
day, even though it used the power only 7 hours and would have paid 
less under the hourly rate. Ex. AMPO-1 at 8-9.
    6. In January 1994, AMP-Ohio sought to transfer power from one 
member with generation to other members, which required transmission 
over AEP and Toledo Edison lines. Toledo Edison said yes, AEP said 
no. AMP-Ohio's northern members purchased emergency power from 
Toledo Edison. AMP-Ohio then reminded AEP that it had agreed not to 
deny transmission and AEP agreed to transmit. Ex. AMPO-1 at 9.
    7. IMPA arranged to buy 80 MW of short-term power from LG&E and 
have it wheeled, using buy-sell arrangements, through Public Service 
Company of Indiana (PSI) and AEP to serve IMPA's load at Richmond 
(an IMPA member). The delivered price was $.292 per kW-day plus a 1 
mill adder. At the same time AEP arranged to buy 300 MW from PSI at 
$.30 per kW day plus out-of-pocket energy costs. Hence, PSI was 
shipping a total of 380 MW to AEP with 80 MW of that amount to be 
delivered to IMPA's load at Richmond. Then, on a day when IMPA 
should have received the 80 MW, AEP told IMPA that PSI had sold 
everything to AEP and that IMPA would have to buy from AEP at $.63 
per kW day plus the cost of energy from AEP. IMPA purchased from AEP 
under protest. AEP used its control over transmission to intercept 
the 80 MW at a lower price and resell it as short-term power to 
IMPA. AEP claimed that PSI had terminated its sales to AEP on that 
day. But the 80 MW was independent of PSI's other sales to AEP and 
would not have been interrupted if AEP had not interrupted it. IMPA-
1 at 7.
    8. IMPA has combustion turbines owned by and located at one 
member, which IMPA would like to connect to the Joint Transmission 
System owned by IMPA, CINergy and Wabash Valley Power Association. 
To do so, IMPA needed a metering agreement with AEP, to which AEP 
would not agree. IMPA-1 at 6.
    9. In January 1994, IMPA had power to sell from its turbines 
when AEP and others needed power. IMPA offered power to AEP but AEP 
it said could not purchase the power without an existing contract. 
Moreover, since there was no short-term tariff, IMPA could not sell 
the power to another utility. IMPA-1 at 6.
    10. Another example of the utility engaging in dilatory tactics 
that raised the customer's transaction costs and effectively denied 
transmission is the ``sham transaction'' provision proposed by AEP. 
As filed, AEP's tariffs permitted it to deny service merely because 
a portion of the transmitted power might be used to serve a former 
retail customer of AEP. See, e.g., Ex. BR&WVP-1 (J. Bertram Solomon 
testimony, February 23, 1994). (As part of a settlement AEP filed 
the pro forma tariff and withdrew this provision.)
    11. Finally, AEP's originally filed tariff contained a 
``prodigal customer'' provision. Under this provision, transmission 
customers who sought to convert back to requirements service had to 
give AEP five years' notice, in which case AEP and the customer 
would enter into negotiations to determine whether AEP will provide 
service at all and if so under what rate, terms, and conditions. Ex. 
S-39 at 1 (Staff testimony). AEP did not require notice from all new 
customers, only from prodigal customers. Id. at 2. That a potential 
customer was previously served by AEP is not a reason to treat the 
customer differently. (AEP withdrew this provision when it filed the 
pro forma tariff.)

B. Entergy Services, Inc. (Entergy)

    Entergy filed a partial settlement largely adopting the NOPR pro 
forma tariffs except for two provisions (headroom and ancillary 
services). Because the settlement predated the filing date for 
customer testimony before the ALJ, the customers did not address the 
need for Entergy to file a tariff. However, customers did make 
allegations of discriminatory practices, as follows.
    1. Customers alleged that Entergy flat-out refused to wheel. 
Louisiana Energy and Power Authority (LEPA) witness Sylvan J. 
Richard testified that LEPA's predecessor systems could not obtain 
interconnections from Entergy. Ex. SJR-1 at 50.
    2. Customers also alleged that Entergy refused to provide 
service priority equal to native load and refused to provide service 
flexibility equivalent to the utility's own use. For example, LEPA 
witness Richard testified that even after state commissions ordered 
interconnections and other coordination

[[Page 21704]]

services, LEPA's predecessors were still not able to obtain 
coordination services because Entergy was not willing to coordinate 
and because the transmission service it did offer was inflexible, 
unidirectional point-to-point service, which prevented economic 
coordination with others. Id. at 50-51.
    3. South Mississippi Electric Power Association (SMEPA) witness 
J. Bertram Solomon testified that Entergy's original ``open access'' 
tariff was restricted to point-to-point service, proposed separate 
charges for each operating company, and required the cancellation of 
existing agreements in order to take service under the proposed 
tariff. Ex. SMEPA-10 at 28. Entergy eventually filed a network 
tariff, but proposed different local facilities charges for the 
various Entergy public utility operating subsidiaries. Id. at 29. 
Since these local facilities charges were higher than the 
transmission component of the subsidiaries' bundled rates, Entergy 
obtained a competitive advantage. Id.
    4. The Arkansas Cities and Cooperatives (ACC) is a group of 
cities and cooperatives that own or operate electric generation or 
distribution systems in Arkansas. ACC Witness Steven Merchant 
testified that Entergy has segregated the wholesale market between 
two of its subsidiaries, Arkansas Power & Light Copmpany (APL) and 
Entergy Power, Inc. (EPI). Ex. SMM-1 at 16. In marketing power and 
energy in Arkansas, EPI is subject to an Arkansas Commission order 
that bars EPI from competing with APL for wholesale loads without 
first obtaining a waiver. Id. Recently, EPI requested this waiver 
for all wholesale transactions in Arkansas except for wholesale 
customers currently served by an Entergy subsidiary; in other words, 
EPI requested the Arkansas Commission to expand competition for all 
wholesale customers except where EPI might compete with APL. Id. ACC 
witness Merchant concluded that, since EPI does not compete with 
APL, Entergy insulates APL's wholesale business from competition and 
denies those wholesale customers access to EPI as a source of power, 
thereby limiting alternative generation sources available to ACC. 
Id. at 17-19. (Entergy's witness Kenney stated that Entergy has 
recently filed a joint motion with ACC to the Arkansas Commission 
seeking to extend the waiver and permit EPI to sell to APL's 
wholesale customers. Ex. JFK-11 at 14-15.)

C. Pacific Gas & Electric Company (PG&E)

    Northern California Power Agency (NCPA) attached several 
documents to its 1988 complaint in Docket No. EL89-4. These 
documents were provided to support NCPA's claim that PG&E's 
unreasonable practices under the PG&E/NCPA Interconnection Agreement 
(IA) effectively denied NCPA access to transmission properly 
requested under the IA. Although the parties eventually settled and 
the Commission terminated the docket with a letter order dated May 
18, 1988, these documents provide allegations of PG&E using dilatory 
tactics that so protracted negotiations as to effectively equal a 
refusal to wheel.<SUP>3
---------------------------------------------------------------------------

    \3\ All of these incidents are related to and examples of PG&E's 
conduct described in the NOPR (FERC Stats. & Regs. para. 32,514 at 
33,073 n.151), that is, the history of PG&E's attempt to avoid its 
commitments made to the California owners of the California Oregon 
Transmission Project (COTP). However, these incidents are not 
exactly the same as the incidents described in the NOPR, because 
NCPA is not one of the owners of the COTP.
---------------------------------------------------------------------------

    1. PG&E stated that since transmission was not currently 
available, it was entitled to wait 72 months before providing 
transmission; that is, transmission access could not be granted 
before the passing of the 72-month notice period. NCPA 1988 
Complaint, Ex. 3. However, the IA provided that transmission be 
provided when it becomes actually available. PG&E also requested 
substantial additional information, which NCPA considered beyond 
that reasonably necessary for a study, but still provided. PG&E then 
determined that transmission was not available, reasoning that 
transmission was unavailable unless all the transmission requested 
could be provided 8760 hours per year without restrictions or 
limitations, extending through the expiration of the agreement in 
2013. NCPA 1988 Complaint at 9.
    2. On November 27, 1987, NCPA made a new transmission request to 
PG&E, seeking 50 MW of bi-directional transmission at Midway. NCPA 
1988 Complaint, Ex. 5. On January 28, 1988, PG&E filed an 
interconnection agreement with Turlock Irrigation District (TID) 
that provided TID with 50 MW of bi-directional transmission at 
Midway. Pacific Gas & Electric Company, 42 FERC para. 61,406, order 
on reh'g, 43 FERC para. 61,403 (1988). On February 22, 1988, PG&E 
advised NCPA that all firm transmission service available at Midway 
had been fully subscribed. NCPA 1988 Complaint, Ex. 6. Then, on 
March 29, 1988, PG&E filed with the Commission an interconnection 
agreement with Modesto Irrigation District (MID), that provided MID 
with 50 MW of bi-directional transmission at Midway.  Pacific Gas & 
Electric Company, 44 FERC para. 61,010 (1988). At about the same 
time (in the last week in March 1988), PG&E advised NCPA that the 
allocations of transmission to TID, MID, and others, including a not 
yet finalized allocation to Sacramento Municipality Utility 
District, had used all the transmission available at Midway. NCPA 
1988 Complaint, Exs. 7 and 8.

D. Northeast Utilities Service Company (NU)

    This is the case where Northeast Utilities acquired Public 
Service of New Hampshire (PSNH) (Docket No. EC90-10). New England 
Power Company (NEP) witness Robert Bigelow's direct testimony 
expressed concern over the ``relatively restrictive transmission 
policies of both'' NU, on behalf of Northeast Utilities' public 
utility subsidiaries, and PSNH. Bigelow Direct Testimony at 21 
(filed May 25, 1990). In his cross rebuttal testimony, Mr. Bigelow 
testified that ``NU has a poor track record as a provider of 
transmission service'' and ``PSNH also has an abhorrent track record 
as a provider of transmission services.'' Bigelow Cross Rebuttal 
Testimony, at 3 (filed June 20, 1990). Mr. Bigelow described both 
NU's and NEP's (his own company) failure to provide service 
flexibility equivalent to their own use. Except for NEP's TDUs, both 
NEP and NU historically provided only point-to-point transmission, 
which required separate scheduling for each transaction. Bigelow 
Cross Rebuttal at 4.

E. Southern California Edison Company and San Diego Gas and Electric 
Company

    The evidence in this merger proceeding (Docket No. EC89-5) 
included testimony from a number of witnesses describing instances 
of Edison's conduct. Richard Greenwalt was the power supply 
supervisor for the City of Riverside, California. He was responsible 
for scheduling all purchases of energy for Riverside and for the 
cities of Azusa, Banning and Colton, California. Greenwalt testimony 
at 1 (November 1989). (These four cities and Anaheim, California, 
are collectively referred to as the Southern Cities or Cities.) 
Joseph Hsu was the Director of Utilities for Azusa. Hsu testimony at 
1 (November 1989). Gale Drews was the electric utility director of 
Colton. Drews testimony at 1-2 (November 1989). Bill Carnahan was 
the director for Riverside. Carnahan testimony at 1 (November 1989). 
Gordon Hoyt was the general manager of the Anaheim power department. 
Hoyt testimony at 1 (November 1989). Dan McCann was the power 
coordination supervisor for Anaheim. He supervised Anaheim's load 
scheduling and is a former Edison employee, having worked for Edison 
for 20 years. McCann Testimony at 1-2 (November 1989). These 
witnesses testified that Edison refused to wheel as follows.
    1. Edison's policy was to curtail the Cities any time it could 
be justified using any of a list of acceptable reasons to deny 
interruptible transmission service. Id. at 22-23.
    2. Edison would not generally provide transmission service when 
Edison could save money by itself purchasing the economy energy that 
would be wheeled. McCann testimony at 19. The Cities called Edison 
every hour to request interruptible transmission service. Id. Edison 
often refused to sell energy available in the Western Systems Power 
Pool to the Cities and then made available higher cost contract 
energy or partial requirements service. Id. at 19-20.
    3. When Anaheim requested Edison provide firm transmission of 
power from neighboring states, Edison would often agree to provide 
non-firm service but would not integrate the capacity for many years 
in the future, saying that its control area did not need capacity at 
that time. Hoyt testimony at 9. Since the selling utility was 
interested in a sale of capacity, not just energy, the transaction 
would not occur. Id. Edison repeatedly used its control over 
transmission to deny Anaheim access to low-cost firm power. Id. at 
9-10.
    4. While Edison provided short-term firm transmission service to 
the Cities, it would only provide long-term firm service for three 
specific resources: The SONGS nuclear plant, a specific IPP, and 
Hoover Dam power. Hoyt testimony at 20. One of Edison's reasons for 
denying long-term transmission was that Edison desired to reserve 
the transmission for its own future (unspecified) needs. Id.
    5. In the 1970s, Edison refused to allow the Cities access to 
the Pacific Intertie. Hoyt testimony at 21; Drews testimony at 7-8.

[[Page 21705]]

    6. In 1988, Edison refused to provide transmission service for a 
Cities power purchase from Public Service Company of New Mexico 
(PSNM) from Palo Verde Nuclear station. Hoyt testimony at 21.
    7. Edison has refused to provide requested firm transmission 
from

--California-Oregon border to Midway Station
--Nevada-Oregon Border to Sylmar Substation
--Palo Verde Switchyard to Vista
--SONGS Switchyard to Vista.

Carahan testimony at 15.
    8. Riverside requested transmission from Palo Verde and was told 
that such service was not available. Carnahan testimony at 16. 
Edison offered Riverside only 12 MW of curtailable transmission 
entitlement to provide Riverside's share of Palo Verde. Id. This 
service was neither large enough or long enough, and Edison insisted 
on unreasonable terms and conditions. Id.
    9. Azusa, Banning and Colton had a contract with Edison that 
entitled them to use their Palo Verde firm transmission path to 
schedule energy to meet their contract energy obligation. Edison 
refused to permit the three cities to use that path. Edison did not 
contest that the contracts allowed this use, but said that the 
scheduling of such small amounts of energy for the three cities 
would be too burdensome. Greenwalt testimony at 14.
    10. Edison would not respond in a timely manner to the Cities' 
requests, routinely taking months to respond. Drews testimony at 15.
    11. During the 1980s, Edison provided Colton with some 
transmission service to allow the Cities to reach certain suppliers, 
but limited the choices available to the Cities and imposed terms 
and conditions that increased the Cities' costs and placed Colton at 
a disadvantage against Edison. Drews testimony at 9. Arranging 
alternative generation sources was difficult because the Cities 
always had to first get Edison to state whether it would provide 
transmission.
    12. During 1988 and 1989, a dispute arose between Edison and the 
Cities concerning the Hoover Uprating Project. Drews testimony at 
16. Edison argued that for the months when units were out of service 
for uprating, and Southern Cities capacity was reduced to zero, 
Southern Cities would not receive an energy credit, even though 
energy was still available and used by Edison. But the contracts 
allowed a participant who did not have capacity to still schedule 
its energy as non-firm energy on the capacity of another 
participant. Id. at 16-17.
    13. In 1986, Azusa negotiated a power purchase contract with the 
California Department of Water Resources in increments of first 5 MW 
and then 2 MW (for a total of 7 MW). Hsu testimony at 14. First 
Edison assured Azusa that the transmission for the additional 2 MW 
would not be a problem. Id. Then Edison would not agree to amend the 
transmission service agreement for the additional 2 MW. Id.
    14. In 1986, Azusa notified Edison of Special Condition 12 
<SUP>4 purchases from PG&E and requested firm transmission service. 
Id. Two months before service was to begin, Edison notified the 
Cities of a problem with the transmission lines. Id. Transmission 
was eventually granted, but only after a four-month delay and 
substantial losses to the Cities.  Id. Then Edison decided there was 
no problem with its transmission facilities. Id. at 14-15.
---------------------------------------------------------------------------

    \4\ Special Condition 12 of the Integrated Operations Agreement 
between Edison and the Southern Cities defined certain Special 
Condition 12 resources and allowed the Cities to make certain uses 
of those resources, subject to certain restrictions.
---------------------------------------------------------------------------

    15. In 1986-87, the Cities purchased 20 MW from PG&E and 80 MW 
from Deseret G&T Cooperative. Hoyt testimony at 7-8. Edison stated 
that without reinforcement of its transmission system, Edison would 
not provide the transmission. Id. There was a five-month delay 
during which the Cities were forced to purchase from Edison at a 
higher cost. Id. at 8-9. Then Edison decided that the transmission 
system did not need reinforcement.  Id. at 8.
    16. Edison also refused to provide a service priority equal to 
that of native load. It would curtail the Cities in order to 
purchase more economy energy for itself. McCann testimony at 28. If 
Edison could make the purchase, it would curtail the City and use 
the energy for itself. Id. When Edison curtailed the Cities, they 
were not able to purchase economy energy and instead purchased 
energy from Edison. Id. at 24.
    17. According to Edison, the interruptible transmission it 
provided the Cities was interruptible for any reason. Id. at 20. A 
purchase could be terminated the hour after it is begun or even 
during the hour. Id. As a result, the Cities lost opportunities to 
make advantageous economy purchases. Id. at 20-21.
    18. Edison also refused to provide customers flexibility similar 
to the flexibility Edison provided itself. Edison's refusal to 
provide bi-directional transmission service restricted the Cities' 
abilities to purchase hydroelectric energy from the Pacific 
Northwest. Hoyt testimony at 22. Because most contracts with 
Northwest utilities require a return of power, the Northwest 
utilities would not deal with the Cities without transmission to 
return energy. Id. at 22-23. Edison did provide bi-directional 
transmission to the Los Angeles Department of Water & Power (LADWP) 
to accommodate flows to and from Arizona. Id.
    19. Riverside was unable to obtain non-firm service more than 
two hours in advance of need. Carnahan testimony at 18.
    20. Riverside and Colton were both served out of Edison's Vista 
substation. Although the two cities were on the same 69 kV bus, 
Edison would not allow them to sell energy to each other. Greenwalt 
testimony at 17.
    21. Riverside's agreement with Edison allowed Riverside to 
purchase a block of energy through the WSPP and divide it up among 
the four Cities (Azusa, Banning, Colton and Riverside). Greenwalt 
testimony at 17. When Riverside had excess energy from other 
sources, Edison would not permit it to sell that energy to the other 
three cities. Id. For example, Riverside attempted to sell Deseret 
energy transmitted by LADWP to the Edison system. Id. at 17-18. 
LADWP would not break out the Cities' shares of that energy, and 
Edison would not accept the energy as a delivery for all four 
cities. Id. at 18. Edison argued that because this energy was excess 
energy that Riverside could not use, Riverside did not have 
transmission rights to bring it into the control area. Id. As a 
result, Riverside paid for the energy delivered by LADWP to the 
Edison control area, but could not sell it to the other three 
cities, and gave it to Edison itself, which consumed the energy 
without making any payment for it. Id. Riverside tried a number of 
alternative paths, including using WSPP transmission where Riverside 
paid Edison 5 mills to connect to Azusa, 5 mills to connect to 
Banning, and 5 mills to connect to Colton for each megawatthour. 
While this approach was successful for a while, eventually Edison 
refused to permit these sales.
    22. Edison claimed that the Cities only have transmission rights 
to bring in enough Special Condition 12 energy to satisfy the 
Cities' load. Greenwalt testimony at 18.
    23. Edison contended that the Cities' load requirements were 
satisfied first by integrated resources and then by Special 
Condition 12 and economy energy purchases. Id. at 19. When the 
Cities' integrated resources exceeded their load, any Special 
Condition 12 resources became excess. Under Riverside's Deseret 
contract, the Cities were required to take a minimum of 35 MW each 
hour. Id. Edison acknowledged that it was obligated to buy, or allow 
the Cities to sell, any excess energy from Riverside's integrated 
resources. Id. However, Edison refused to give the Cities credit for 
excess Special Condition 12 energy brought into the area, claiming 
that the Cities could not have brought it in because they did not 
have transmission rights. Id.

II. Other Examples of Transmission Disputes

    Disputes over transmission are not uncommon, contrary to EEI's 
suggestion. Some recent examples taken from pleadings and other 
documents and from Commission orders reveal that it has been very 
difficult for various entities in the electric power industry to 
agree on transmission rights. These examples also reveal that even 
after issuance of AEP and the Open Access NOPR with its proposed pro 
forma tariffs, there has been considerable controversy over whether 
various utilities' ``open access'' tariffs deviate from those 
tariffs. (The Commission has allowed utilities that adopt tariffs 
that match or exceed the non-rate terms and conditions in the NOPR 
pro forma tariffs to obtain certain benefits.)
    A. In a letter of February 3, 1995 to Mr. Gerald Richman of the 
Commission's Enforcement section in the Office of the General 
Counsel, Steven J. Kean, Vice President, Regulatory Affairs, Enron 
Power Marketing, Inc. (Enron) alleged that Niagara Mohawk Power 
Corporation (NiMo) refused to wheel power from Rochester Gas & 
Electric (RG&E) to Enron under RG&E's transmission contract with 
NiMo; however, when Enron revealed the buyer, NiMo did wheel power 
for RG&E to the buyer. Mr. Kean alleged that this was not an 
isolated incident. NiMo argued that the contract did not require it 
to

[[Page 21706]]

provide RG&E with transmission to Enron. It also said that the 
principle of comparability does not require the service. Letter of 
November 21, 1994 from NiMo representative A. Karen Hill to Gerald 
Richman.
    B. The Commission's Task Force Hot Line (Hot Line) received a 
complaint that a member of the New York Power Pool (NYPP) refused to 
transmit power that another member bought from a power marketer. In 
a letter of November 17, 1994, from Chair Moler to Mr. William J. 
Balet, Executive Director of NYPP, Chair Moler explained that the 
Commission's enforcement staff had investigated and found the 
allegation to be true.
    C. In Southern Minnesota Municipal Power Agency v. Northern 
States Power Company (Minnesota), 73 FERC para. 61,350 (1995), NSP 
and SMMPA had a contract under which NSP agreed to provide 
transmission service. However, the parties had numerous disputes 
over the service. The Commission found that NSP had misinterpreted 
the contract in several ways. For, example, SMMPA argued that it 
should be able to directly schedule its deliveries of energy out of 
the NSP control area and that it should not be limited to particular 
points of delivery. NSP argued that only it was entitled to control 
the physical operation of scheduling. The Commission found that the 
clear language of the contracts gave SMMPA the authority to schedule 
its own power.
    D. Mid-Continent Area Power Pool, 72 FERC para. 61,223 (1995), 
involved MAPP's membership criteria, which made it impossible for a 
power marketer to join MAPP and obtain the benefits of certain 
transmission services available only to MAPP members. The Commission 
found that the membership criteria may be unreasonable, particularly 
since there may be less burdensome ways of setting up membership 
criteria for non-traditional entities.

 Appendix D--Pro Forma Open Access Transmission Tariff

Table of Contents

I. Common Service Provisions

1  Definitions
    1.1  Ancillary Services
    1.2  Annual Transmission Costs
    1.3  Application
    1.4  Commission
    1.5  Completed Application
    1.6  Control Area
    1.7  Curtailment
    1.8  Delivering Party
    1.9  Designated Agent
    1.10  Direct Assignment Facilities
    1.11  Eligible Customer
    1.12  Facilities Study
    1.13  Firm Point-To-Point Transmission Service
    1.14  Good Utility Practice
    1.15  Interruption
    1.16  Load Ratio Share
    1.17  Load Shedding
    1.18  Long-Term Firm Point-To-Point Transmission Service
    1.19  Native Load Customers
    1.20  Network Customer
    1.21  Network Integration Transmission Service
    1.22  Network Load
    1.23  Network Operating Agreement
    1.24  Network Operating Committee
    1.25  Network Resource
    1.26  Network Upgrades
    1.27  Non-Firm Point-To-Point Transmission Service
    1.28  Open Access Same-Time Information System (OASIS)
    1.29  Part I
    1.30  Part II
    1.31  Part III
    1.32  Parties
    1.33  Point(s) of Delivery
    1.34  Point(s) of Receipt
    1.35  Point-To-Point Transmission Service
    1.36  Power Purchaser
    1.37  Receiving Party
    1.38  Regional Transmission Group (RTG)
    1.39  Reserved Capacity
    1.40  Service Agreement
    1.41  Service Commencement Date
    1.42  Short-Term Firm Point-To-Point Transmission Service
    1.43  System Impact Study
    1.44  Third-Party Sale
    1.45  Transmission Customer
    1.46  Transmission Provider
    1.47  Transmission Provider's Monthly Transmission System Peak
    1.48  Transmission Service
    1.49  Transmission System
2  Initial Allocation and Renewal Procedures
    2.1  Initial Allocation of Available Transmission Capability
    2.2  Reservation Priority For Existing Firm Service Customers
3  Ancillary Services
    3.1  Scheduling, System Control and Dispatch Service
    3.2  Reactive Supply and Voltage Control from Generation Sources 
Service
    3.3  Regulation and Frequency Response Service
    3.4  Energy Imbalance Service
    3.5  Operating Reserve--Spinning Reserve Service
    3.6  Operating Reserve--Supplemental Reserve Service
4  Open Access Same-Time Information System (OASIS)
5  Local Furnishing Bonds
    5.1  Transmission Providers That Own Facilities Financed by 
Local Furnishing Bonds
    5.2  Alternative Procedures for Requesting Transmission Service
6  Reciprocity
7  Billing and Payment
    7.1  Billing Procedure
    7.2  Interest on Unpaid Balances
    7.3  Customer Default
8  Accounting for the Transmission Provider's Use of the Tariff
    8.1  Transmission Revenues
    8.2  Study Costs and Revenues
9  Regulatory Filings
10  Force Majeure and Indemnification
    10.1   Force Majeure
    10.2  Indemnification
11  Creditworthiness
12   Dispute Resolution Procedures
    12.1  Internal Dispute Resolution Procedures
    12.2  External Arbitration Procedures
    12.3  Arbitration Decisions
    12.4  Costs
    12.5  Rights Under The Federal Power Act

II. Point-to-Point Transmission Service

Preamble

13  Nature of Firm Point-To-Point Transmission Service
    13.1  Term
    13.2  Reservation Priority
    13.3  Use of Firm Transmission Service by the Transmission 
Provider
    13.4  Service Agreements
    13.5  Transmission Customer Obligations for Facility Additions 
or Redispatch Costs
    13.6  Curtailment of Firm Transmission Service
    13.7  Classification of Firm Transmission Service
    13.8  Scheduling of Firm Point-To-Point Transmission Service
14  Nature of Non-Firm Point-To-Point Transmission Service
    14.1  Term
    14.2  Reservation Priority
    14.3  Use of Non-Firm Point-To-Point Transmission Service by the 
Transmission Provider
    14.4  Service Agreements
    14.5  Classification of Non-Firm Point-To-Point Transmission 
Service
    14.6  Scheduling of Non-Firm Point-To-Point Transmission Service
    14.7  Curtailment or Interruption of Service
15  Service Availability
    15.1  General Conditions
    15.2  Determination of Available Transmission Capability
    15.3  Initiating Service in the Absence of an Executed Service 
Agreement
    15.4  Obligation to Provide Transmission Service that Requires 
Expansion or Modification of the Transmission System
    15.5  Deferral of Service
    15.6  Other Transmission Service Schedules
    15.7  Real Power Losses
16  Transmission Customer Responsibilities
    16.1  Conditions Required of Transmission Customers
    16.2  Transmission Customer Responsibility for Third-Party 
Arrangements
17  Procedures for Arranging Firm Point-To-Point Transmission 
Service
    17.1  Application
    17.2  Completed Application
    17.3  Deposit
    17.4  Notice of Deficient Application
    17.5  Response to a Completed Application
    17.6  Execution of Service Agreement
    17.7  Extensions for Commencement of Service
18  Procedures for Arranging Non-Firm Point-To-Point Transmission 
Service
    18.1  Application
    18.2  Completed Application
    18.3  Reservation of Non-Firm Point-To-Point Transmission 
Service

[[Page 21707]]

    18.4  Determination of Available Transmission Capability
19  Additional Study Procedures For Firm Point-To-Point Transmission 
Service Requests
    19.1  Notice of Need for System Impact Study
    19.2  System Impact Study Agreement and Cost Reimbursement
    19.3  System Impact Study Procedures
    19.4  Facilities Study Procedures
    19.5  Facilities Study Modifications
    19.6  Due Diligence in Completing New Facilities
    19.7  Partial Interim Service
    19.8  Expedited Procedures for New Facilities
20  Procedures if The Transmission Provider is Unable to Complete 
New Transmission Facilities for Firm Point-To-Point Transmission 
Service
    20.1  Delays in Construction of New Facilities
    20.2  Alternatives to the Original Facility Additions
    20.3  Refund Obligation for Unfinished Facility Additions
21  Provisions Relating to Transmission Construction and Services on 
the Systems of Other Utilities
    21.1  Responsibility for Third-Party System Additions
    21.2  Coordination of Third-Party System Additions
22  Changes in Service Specifications
    22.1  Modifications On a Non-Firm Basis
    22.2  Modification On a Firm Basis
23  Sale or Assignment of Transmission Service
    23.1  Procedures for Assignment or Transfer of Service
    23.2  Limitations on Assignment or Transfer of Service
    23.3  Information on Assignment or Transfer of Service
24  Metering and Power Factor Correction at Receipt and Delivery 
Points(s)
    24.1  Transmission Customer Obligations
    24.2  Transmission Provider Access to Metering Data
    24.3  Power Factor
25  Compensation for Transmission Service
26  Stranded Cost Recovery
27  Compensation for New Facilities and Redispatch Costs

III. Network Integration Transmission Service

Preamble

28  Nature of Network Integration Transmission Service
    28.1  Scope of Service
    28.2  Transmission Provider Responsibilities
    28.3  Network Integration Transmission Service
    28.4  Secondary Service
    28.5  Real Power Losses
    28.6  Restrictions on Use of Service
29  Initiating Service
    29.1  Condition Precedent for Receiving Service
    29.2  Application Procedures
    29.3  Technical Arrangements to be Completed Prior to 
Commencement of Service
    29.4  Network Customer Facilities
    29.5  Filing of Service Agreement
30  Network Resources
    30.1  Designation of Network Resources
    30.2  Designation of New Network Resources
    30.3  Termination of Network Resources
    30.4  Operation of Network Resources
    30.5  Network Customer Redispatch Obligation
    30.6  Transmission Arrangements for Network Resources Not 
Physically Interconnected With The Transmission Provider
    30.7  Limitation on Designation of Network Resources
    30.8  Use of Interface Capacity by the Network Customer
    30.9  Network Customer Owned Transmission Facilities
31  Designation of Network Load
    31.1  Network Load
    31.2  New Network Loads Connected With the Transmission Provider
    31.3  Network Load Not Physically Interconnected with the 
Transmission Provider
    31.4  New Interconnection Points
    31.5  Changes in Service Requests
    31.6  Annual Load and Resource Information Updates
32  Additional Study Procedures For Network Integration Transmission 
Service Requests
    32.1  Notice of Need for System Impact Study
    32.2  System Impact Study Agreement and Cost Reimbursement
    32.3  System Impact Study Procedures
    32.4  Facilities Study Procedures
33  Load Shedding and Curtailments
    33.1  Procedures
    33.2  Transmission Constraints
    33.3  Cost Responsibility for Relieving Transmission Constraints
    33.4  Curtailments of Scheduled Deliveries
    33.5  Allocation of Curtailments
    33.6  Load Shedding
    33.7  System Reliability
34  Rates and Charges
    34.1  Monthly Demand Charge
    34.2  Determination of Network Customer's Monthly Network Load
    34.3  Determination of Transmission Provider's Monthly 
Transmission System Load
    34.4  Redispatch Charge
    34.5  Stranded Cost Recovery
35  Operating Arrangements
    35.1  Operation under The Network Operating Agreement
    35.2  Network Operating Agreement
    35.3  Network Operating Committee
Schedule 1
    Scheduling, System Control and Dispatch Service
Schedule 2
    Reactive Supply and Voltage Control from Generation Sources 
Service
Schedule 3
    Regulation and Frequency Response Service
Schedule 4
    Energy Imbalance Service
Schedule 5
    Operating Reserve--Spinning Reserve Service
Schedule 6
    Operating Reserve--Supplemental Reserve Service
Schedule 7
    Long-Term Firm and Short-Term Firm Point-To-Point Transmission 
Service
Schedule 8
    Non-Firm Point-To-Point Transmission Service
Attachment A
    Form of Service Agreement for Firm Point-To-Point Transmission 
Service
Attachment B
    Form Of Service Agreement For Non-Firm Point-To-Point 
Transmission Service
Attachment C
    Methodology To Assess Available Transmission Capability
Attachment D
    Methodology for Completing a System Impact Study
Attachment E
    Index Of Point-To-Point Transmission Service Customers
Attachment F
    Service Agreement For Network Integration Transmission Service
Attachment G
    Network Operating Agreement
Attachment H
    Annual Transmission Revenue Requirement For Network Integration 
Transmission Service
Attachment I
    Index Of Network Integration Transmission Service Customers

I. Common Service Provisions

1.  Definitions

    1.1  Ancillary Services: Those services that are necessary to 
support the transmission of capacity and energy from resources to 
loads while maintaining reliable operation of the Transmission 
Provider's Transmission System in accordance with Good Utility 
Practice.
    1.2  Annual Transmission Costs: The total annual cost of the 
Transmission System for purposes of Network Integration Transmission 
Service shall be the amount specified in Attachment H until amended 
by the Transmission Provider or modified by the Commission.
    1.3  Application: A request by an Eligible Customer for 
transmission service pursuant to the provisions of the Tariff.
    1.4  Commission: The Federal Energy Regulatory Commission.
    1.5  Completed Application: An Application that satisfies all of 
the information and other requirements of the Tariff, including any 
required deposit.
    1.6  Control Area: An electric power system or combination of 
electric power systems to which a common automatic generation 
control scheme is applied in order to:
    (1) Match, at all times, the power output of the generators 
within the electric power system(s) and capacity and energy 
purchased from entities outside the electric power system(s), with 
the load within the electric power system(s);

[[Page 21708]]

    (2) maintain scheduled interchange with other Control Areas, 
within the limits of Good Utility Practice;
    (3) maintain the frequency of the electric power system(s) 
within reasonable limits in accordance with Good Utility Practice; 
and
    (4) provide sufficient generating capacity to maintain operating 
reserves in accordance with Good Utility Practice.
    1.7  Curtailment: A reduction in firm or non-firm transmission 
service in response to a transmission capacity shortage as a result 
of system reliability conditions.
    1.8  Delivering Party: The entity supplying capacity and energy 
to be transmitted at Point(s) of Receipt.
    1.9  Designated Agent: Any entity that performs actions or 
functions on behalf of the Transmission Provider, an Eligible 
Customer, or the Transmission Customer required under the Tariff.
    1.10  Direct Assignment Facilities: Facilities or portions of 
facilities that are constructed by the Transmission Provider for the 
sole use/benefit of a particular Transmission Customer requesting 
service under the Tariff. Direct Assignment Facilities shall be 
specified in the Service Agreement that governs service to the 
Transmission Customer and shall be subject to Commission approval.
    1.11  Eligible Customer: (i) Any electric utility (including the 
Transmission Provider and any power marketer), Federal power 
marketing agency, or any person generating electric energy for sale 
for resale; electric energy sold or produced by such entity may be 
electric energy produced in the United States, Canada or Mexico; 
however, such entity is not eligible for transmission service that 
would be prohibited by Section 212(h)(2) of the Federal Power Act; 
and (ii) any retail customer taking unbundled Transmission Service 
pursuant to a state retail access program or pursuant to a voluntary 
offer of unbundled retail transmission service by the Transmission 
Provider.
    1.12  Facilities Study: An engineering study conducted by the 
Transmission Provider to determine the required modifications to the 
Transmission Provider's Transmission System, including the cost and 
scheduled completion date for such modifications, that will be 
required to provide the requested transmission service.
    1.13  Firm Point-To-Point Transmission Service: Transmission 
Service under this Tariff that is reserved and/or scheduled between 
specified Points of Receipt and Delivery pursuant to Part II of this 
Tariff.
    1.14  Good Utility Practice: Any of the practices, methods and 
acts engaged in or approved by a significant portion of the electric 
utility industry during the relevant time period, or any of the 
practices, methods and acts which, in the exercise of reasonable 
judgment in light of the facts known at the time the decision was 
made, could have been expected to accomplish the desired result at a 
reasonable cost consistent with good business practices, 
reliability, safety and expedition. Good Utility Practice is not 
intended to be limited to the optimum practice, method, or act to 
the exclusion of all others, but rather to be acceptable practices, 
methods, or acts generally accepted in the region.
    1.15  Interruption: A reduction in non-firm transmission service 
due to economic reasons pursuant to Section 14.7.
    1.16  Load Ratio Share: Ratio of a Transmission Customer's 
Network Load to the Transmission Provider's total load computed in 
accordance with Sections 34.2 and 34.3 of the Network Integration 
Transmission Service under Part III the Tariff and calculated on a 
rolling twelve month basis.
    1.17  Load Shedding: The systematic reduction of system demand 
by temporarily decreasing load in response to transmission system or 
area capacity shortages, system instability, or voltage control 
considerations under Part III of the Tariff.
    1.18  Long-Term Firm Point-To-Point Transmission Service: Firm 
Point-To-Point Transmission Service under Part II of the Tariff with 
a term of one year or more.
    1.19  Native Load Customers: The wholesale and retail power 
customers of the Transmission Provider on whose behalf the 
Transmission Provider, by statute, franchise, regulatory 
requirement, or contract, has undertaken an obligation to construct 
and operate the Transmission Provider's system to meet the reliable 
electric needs of such customers.
    1.20  Network Customer: An entity receiving transmission service 
pursuant to the terms of the Transmission Provider's Network 
Integration Transmission Service under Part III of the Tariff.
    1.21  Network Integration Transmission Service: The transmission 
service provided under Part III of the Tariff.
    1.22  Network Load: The load that a Network Customer designates 
for Network Integration Transmission Service under Part III of the 
Tariff. The Network Customer's Network Load shall include all load 
served by the output of any Network Resources designated by the 
Network Customer. A Network Customer may elect to designate less 
than its total load as Network Load but may not designate only part 
of the load at a discrete Point of Delivery. Where an Eligible 
Customer has elected not to designate a particular load at discrete 
points of delivery as Network Load, the Eligible Customer is 
responsible for making separate arrangements under Part II of the 
Tariff for any Point-To-Point Transmission Service that may be 
necessary for such non-designated load.
    1.23  Network Operating Agreement: An executed agreement that 
contains the terms and conditions under which the Network Customer 
shall operate its facilities and the technical and operational 
matters associated with the implementation of Network Integration 
Transmission Service under Part III of the Tariff.
    1.24  Network Operating Committee: A group made up of 
representatives from the Network Customer(s) and the Transmission 
Provider established to coordinate operating criteria and other 
technical considerations required for implementation of Network 
Integration Transmission Service under Part III of this Tariff.
    1.25  Network Resource: Any designated generating resource owned 
or purchased by a Network Customer under the Network Integration 
Transmission Service Tariff. Network Resources do not include any 
resource, or any portion thereof, that is committed for sale to 
third parties or otherwise cannot be called upon to meet the Network 
Customer's Network Load on a non-interruptible basis.
    1.26  Network Upgrades: Modifications or additions to 
transmission-related facilities that are integrated with and support 
the Transmission Provider's overall Transmission System for the 
general benefit of all users of such Transmission System.
    1.27  Non-Firm Point-To-Point Transmission Service: Point-To-
Point Transmission Service under the Tariff that is reserved and 
scheduled on an as-available basis and is subject to Curtailment or 
Interruption as set forth in Section 14.7 under Part II of this 
Tariff. Non-Firm Point-To-Point Transmission Service is available on 
a stand-alone basis for periods ranging from one hour to one month.
    1.28  Open Access Same-Time Information System (OASIS): The 
information system and standards of conduct contained in Part 37 of 
the Commission's regulations.
    1.29  Part I: Tariff Definitions and Common Service Provisions 
contained in Sections 2 through 12.
    1.30  Part II: Tariff Sections 13 through 27 pertaining to 
Point-To-Point Transmission Service in conjunction with the 
applicable Common Service Provisions of Part I and appropriate 
Schedules and Attachments.
    1.31  Part III: Tariff Sections 28 through 35 pertaining to 
Network Integration Transmission Service in conjunction with the 
applicable Common Service Provisions of Part I and appropriate 
Schedules and Attachments.
    1.32  Parties: The Transmission Provider and the Transmission 
Customer receiving service under the Tariff.
    1.33  Point(s) of Delivery: Point(s) on the Transmission 
Provider's Transmission System where capacity and energy transmitted 
by the Transmission Provider will be made available to the Receiving 
Party under Part II of the Tariff. The Point(s) of Delivery shall be 
specified in the Service Agreement.
    1.34  Point(s) of Receipt: Point(s) of interconnection on the 
Transmission Provider's Transmission System where capacity and 
energy will be made available to the Transmission Provider by the 
Delivering Party under Part II of the Tariff. The Point(s) of 
Receipt shall be specified in the Service Agreement.
    1.35  Point-To-Point Transmission Service: The reservation and 
transmission of capacity and energy on either a firm or non-firm 
basis from the Point(s) of Receipt to the Point(s) of Delivery under 
Part II of the Tariff.
    1.36  Power Purchaser: The entity that is purchasing the 
capacity and energy to be transmitted under the Tariff.
    1.37  Receiving Party: The entity receiving the capacity and 
energy transmitted by the Transmission Provider to Point(s) of 
Delivery.
    1.38  Regional Transmission Group (RTG): A voluntary 
organization of transmission owners, transmission users and other 
entities approved by the Commission to efficiently

[[Page 21709]]

coordinate transmission planning (and expansion), operation and use 
on a regional (and interregional) basis.
    1.39  Reserved Capacity: The maximum amount of capacity and 
energy that the Transmission Provider agrees to transmit for the 
Transmission Customer over the Transmission Provider's Transmission 
System between the Point(s) of Receipt and the Point(s) of Delivery 
under Part II of the Tariff. Reserved Capacity shall be expressed in 
terms of whole megawatts on a sixty (60) minute interval (commencing 
on the clock hour) basis.
    1.40  Service Agreement: The initial agreement and any 
amendments or supplements thereto entered into by the Transmission 
Customer and the Transmission Provider for service under the Tariff.
    1.41  Service Commencement Date: The date the Transmission 
Provider begins to provide service pursuant to the terms of an 
executed Service Agreement, or the date the Transmission Provider 
begins to provide service in accordance with Section 15.3 or Section 
29.1 under the Tariff.
    1.42  Short-Term Firm Point-To-Point Transmission Service: Firm 
Point-To-Point Transmission Service under Part II of the Tariff with 
a term of less than one year.
    1.43  System Impact Study: An assessment by the Transmission 
Provider of (i) the adequacy of the Transmission System to 
accommodate a request for either Firm Point-To-Point Transmission 
Service or Network Integration Transmission Service and (ii) whether 
any additional costs may be incurred in order to provide 
transmission service.
    1.44  Third-Party Sale: Any sale for resale in interstate 
commerce to a Power Purchaser that is not designated as part of 
Network Load under the Network Integration Transmission Service.
    1.45  Transmission Customer: Any Eligible Customer (or its 
Designated Agent) that (i) executes a Service Agreement, or (ii) 
requests in writing that the Transmission Provider file with the 
Commission, a proposed unexecuted Service Agreement to receive 
transmission service under Part II of the Tariff. This term is used 
in the Part I Common Service Provisions to include customers 
receiving transmission service under Part II and Part III of this 
Tariff.
    1.46  Transmission Provider: The public utility (or its 
Designated Agent) that owns, controls, or operates facilities used 
for the transmission of electric energy in interstate commerce and 
provides transmission service under the Tariff.
    1.47  Transmission Provider's Monthly Transmission System Peak: 
The maximum firm usage of the Transmission Provider's Transmission 
System in a calendar month.
    1.48  Transmission Service: Point-To-Point Transmission Service 
provided under Part II of the Tariff on a firm and non-firm basis.
    1.49  Transmission System: The facilities owned, controlled or 
operated by the Transmission Provider that are used to provide 
transmission service under Part II and Part III of the Tariff.

2  Initial Allocation and Renewal Procedures

    2.1  Initial Allocation of Available Transmission Capability: 
For purposes of determining whether existing capability on the 
Transmission Provider's Transmission System is adequate to 
accommodate a request for firm service under this Tariff, all 
Completed Applications for new firm transmission service received 
during the initial sixty (60) day period commencing with the 
effective date of the Tariff will be deemed to have been filed 
simultaneously. A lottery system conducted by an independent party 
shall be used to assign priorities for Completed Applications filed 
simultaneously. All Completed Applications for firm transmission 
service received after the initial sixty (60) day period shall be 
assigned a priority pursuant to Section 13.2.
    2.2  Reservation Priority For Existing Firm Service Customers: 
Existing firm service customers (wholesale requirements and 
transmission-only, with a contract term of one-year or more), have 
the right to continue to take transmission service from the 
Transmission Provider when the contract expires, rolls over or is 
renewed. This transmission reservation priority is independent of 
whether the existing customer continues to purchase capacity and 
energy from the Transmission Provider or elects to purchase capacity 
and energy from another supplier. If at the end of the contract 
term, the Transmission Provider's Transmission System cannot 
accommodate all of the requests for transmission service the 
existing firm service customer must agree to accept a contract term 
at least equal to a competing request by any new Eligible Customer 
and to pay the current just and reasonable rate, as approved by the 
Commission, for such service. This transmission reservation priority 
for existing firm service customers is an ongoing right that may be 
exercised at the end of all firm contract terms of one-year or 
longer.

3  Ancillary Services

    Ancillary Services are needed with transmission service to 
maintain reliability within and among the Control Areas affected by 
the transmission service. The Transmission Provider is required to 
provide (or offer to arrange with the local Control Area operator as 
discussed below), and the Transmission Customer is required to 
purchase, the following Ancillary Services (i) Scheduling, System 
Control and Dispatch, and (ii) Reactive Supply and Voltage Control 
from Generation Sources.
    The Transmission Provider is required to offer to provide (or 
offer to arrange with the local Control Area operator as discussed 
below) the following Ancillary Services only to the Transmission 
Customer serving load within the Transmission Provider's Control 
Area (i) Regulation and Frequency Response, (ii) Energy Imbalance, 
(iii) Operating Reserve--Spinning, and (iv) Operating Reserve--
Supplemental. The Transmission Customer serving load within the 
Transmission Provider's Control Area is required to acquire these 
Ancillary Services, whether from the Transmission Provider, from a 
third party, or by self-supply. The Transmission Customer may not 
decline the Transmission Provider's offer of Ancillary Services 
unless it demonstrates that it has acquired the Ancillary Services 
from another source. The Transmission Customer must list in its 
Application which Ancillary Services it will purchase from the 
Transmission Provider.
    If the Transmission Provider is a public utility providing 
transmission service but is not a Control Area operator, it may be 
unable to provide some or all of the Ancillary Services. In this 
case, the Transmission Provider can fulfill its obligation to 
provide Ancillary Services by acting as the Transmission Customer's 
agent to secure these Ancillary Services from the Control Area 
operator. The Transmission Customer may elect to (i) have the 
Transmission Provider act as its agent, (ii) secure the Ancillary 
Services directly from the Control Area operator, or (iii) secure 
the Ancillary Services (discussed in Schedules 3, 4, 5 and 6) from a 
third party or by self-supply when technically feasible.
    The Transmission Provider shall specify the rate treatment and 
all related terms and conditions in the event of an unauthorized use 
of Ancillary Services by the Transmission Customer.
    The specific Ancillary Services, prices and/or compensation 
methods are described on the Schedules that are attached to and made 
a part of the Tariff. If the Transmission Provider offers an 
affiliate a rate discount, or attributes a discounted Ancillary 
Service rate to its own transactions, the Transmission Provider must 
offer at the same time the same discounted Ancillary Service rate to 
all Eligible Customers. Information regarding any discounted 
Ancillary Service rates must be posted on the OASIS pursuant to Part 
37 of the Commission's regulations. In addition, discounts to non-
affiliates must be offered in a not unduly discriminatory manner. 
Sections 3.1 through 3.6 below list the six Ancillary Services.
    3.1  Scheduling, System Control and Dispatch Service: The rates 
and/or methodology are described in Schedule 1.
    3.2  Reactive Supply and Voltage Control from Generation Sources 
Service: The rates and/or methodology are described in Schedule 2.
    3.3  Regulation and Frequency Response Service: Where applicable 
the rates and/or methodology are described in Schedule 3.
    3.4  Energy Imbalance Service: Where applicable the rates and/or 
methodology are described in Schedule 4.
    3.5  Operating Reserve--Spinning Reserve Service: Where 
applicable the rates and/or methodology are described in Schedule 5.
    3.6  Operating Reserve--Supplemental Reserve Service: Where 
applicable the rates and/or methodology are described in Schedule 6.

4  Open Access Same-Time Information System (OASIS)

    Terms and conditions regarding Open Access Same-Time Information 
System and standards of conduct are set forth in 18 CFR part 37 of 
the Commission's regulations (Open Access Same-Time Information 
System and Standards of Conduct for Public

[[Page 21710]]

Utilities). In the event available transmission capability as posted 
on the OASIS is insufficient to accommodate a request for firm 
transmission service, additional studies may be required as provided 
by this Tariff pursuant to Sections 19 and 32.

5  Local Furnishing Bonds

    5.1  Transmission Providers That Own Facilities Financed by 
Local Furnishing Bonds: This provision is applicable only to 
Transmission Providers that have financed facilities for the local 
furnishing of electric energy with tax-exempt bonds, as described in 
Section 142(f) of the Internal Revenue Code (``local furnishing 
bonds''). Notwithstanding any other provision of this Tariff, the 
Transmission Provider shall not be required to provide Transmission 
Service to any Eligible Customer pursuant to this Tariff if the 
provision of such Transmission Service would jeopardize the tax-
exempt status of any local furnishing bond(s) used to finance the 
Transmission Provider's facilities that would be used in providing 
such Transmission Service.
    5.2  Alternative Procedures for Requesting Transmission Service:
    (i) If the Transmission Provider determines that the provision 
of transmission service requested by an Eligible Customer would 
jeopardize the tax-exempt status of any local furnishing bond(s) 
used to finance its facilities that would be used in providing such 
transmission service, it shall advise the Eligible Customer within 
thirty (30) days of receipt of the Completed Application.
    (ii) If the Eligible Customer thereafter renews its request for 
the same transmission service referred to in (i) by tendering an 
application under Section 211 of the Federal Power Act, the 
Transmission Provider, within ten (10) days of receiving a copy of 
the Section 211 application, will waive its rights to a request for 
service under Section 213(a) of the Federal Power Act and to the 
issuance of a proposed order under Section 212(c) of the Federal 
Power Act and shall provide the requested transmission service in 
accordance with the terms and conditions of this Tariff.

6  Reciprocity

    A Transmission Customer receiving transmission service under 
this Tariff agrees to provide comparable transmission service to the 
Transmission Provider on similar terms and conditions over 
facilities used for the transmission of electric energy in 
interstate commerce owned, controlled or operated by the 
Transmission Customer and over facilities used for the transmission 
of electric energy in interstate commerce owned, controlled or 
operated by the Transmission Customer's corporate affiliates. A 
Transmission Customer that is a member of a power pool or Regional 
Transmission Group also agrees to provide comparable transmission 
service to the members of such power pool and Regional Transmission 
Group on similar terms and conditions over facilities used for the 
transmission of electric energy in interstate commerce owned, 
controlled or operated by the Transmission Customer and over 
facilities used for the transmission of electric energy in 
interstate commerce owned, controlled or operated by the 
Transmission Customer's corporate affiliates. This reciprocity 
requirement also applies to any Eligible Customer that owns, 
controls or operates transmission facilities that uses an 
intermediary, such as a power marketer, to request transmission 
service under the Tariff. If the Transmission Customer does not own, 
control or operate transmission facilities, it must include in its 
Application a sworn statement of one of its duly authorized officers 
or other representatives that the purpose of its Application is not 
to assist an Eligible Customer to avoid the requirements of this 
provision.

7  Billing and Payment

    7.1  Billing Procedure: Within a reasonable time after the first 
day of each month, the Transmission Provider shall submit an invoice 
to the Transmission Customer for the charges for all services 
furnished under the Tariff during the preceding month. The invoice 
shall be paid by the Transmission Customer within twenty (20) days 
of receipt. All payments shall be made in immediately available 
funds payable to the Transmission Provider, or by wire transfer to a 
bank named by the Transmission Provider.
    7.2  Interest on Unpaid Balances: Interest on any unpaid amounts 
(including amounts placed in escrow) shall be calculated in 
accordance with the methodology specified for interest on refunds in 
the Commission's regulations at 18 CFR 35.19a(a)(2)(iii). Interest 
on delinquent amounts shall be calculated from the due date of the 
bill to the date of payment. When payments are made by mail, bills 
shall be considered as having been paid on the date of receipt by 
the Transmission Provider.
    7.3  Customer Default: In the event the Transmission Customer 
fails, for any reason other than a billing dispute as described 
below, to make payment to the Transmission Provider on or before the 
due date as described above, and such failure of payment is not 
corrected within thirty (30) calendar days after the Transmission 
Provider notifies the Transmission Customer to cure such failure, a 
default by the Transmission Customer shall be deemed to exist. Upon 
the occurrence of a default, the Transmission Provider may initiate 
a proceeding with the Commission to terminate service but shall not 
terminate service until the Commission so approves any such request. 
In the event of a billing dispute between the Transmission Provider 
and the Transmission Customer, the Transmission Provider will 
continue to provide service under the Service Agreement as long as 
the Transmission Customer (i) continues to make all payments not in 
dispute, and (ii) pays into an independent escrow account the 
portion of the invoice in dispute, pending resolution of such 
dispute. If the Transmission Customer fails to meet these two 
requirements for continuation of service, then the Transmission 
Provider may provide notice to the Transmission Customer of its 
intention to suspend service in sixty (60) days, in accordance with 
Commission policy.

8  Accounting for the Transmission Provider's Use of the Tariff

    The Transmission Provider shall record the following amounts, as 
outlined below.
    8.1  Transmission Revenues: Include in a separate operating 
revenue account or subaccount the revenues it receives from 
Transmission Service when making Third-Party Sales under Part II of 
the Tariff.
    8.2  Study Costs and Revenues: Include in a separate 
transmission operating expense account or subaccount, costs properly 
chargeable to expense that are incurred to perform any System Impact 
Studies or Facilities Studies which the Transmission Provider 
conducts to determine if it must construct new transmission 
facilities or upgrades necessary for its own uses, including making 
Third-Party Sales under the Tariff; and include in a separate 
operating revenue account or subaccount the revenues received for 
System Impact Studies or Facilities Studies performed when such 
amounts are separately stated and identified in the Transmission 
Customer's billing under the Tariff.

9  Regulatory Filings

    Nothing contained in the Tariff or any Service Agreement shall 
be construed as affecting in any way the right of the Transmission 
Provider to unilaterally make application to the Commission for a 
change in rates, terms and conditions, charges, classification of 
service, Service Agreement, rule or regulation under Section 205 of 
the Federal Power Act and pursuant to the Commission's rules and 
regulations promulgated thereunder.
    Nothing contained in the Tariff or any Service Agreement shall 
be construed as affecting in any way the ability of any Party 
receiving service under the Tariff to exercise its rights under the 
Federal Power Act and pursuant to the Commission's rules and 
regulations promulgated thereunder.

10  Force Majeure and Indemnification

    10.1  Force Majeure: An event of Force Majeure means any act of 
God, labor disturbance, act of the public enemy, war, insurrection, 
riot, fire, storm or flood, explosion, breakage or accident to 
machinery or equipment, any Curtailment, order, regulation or 
restriction imposed by governmental military or lawfully established 
civilian authorities, or any other cause beyond a Party's control. 
Neither the Transmission Provider nor the Transmission Customer will 
be considered in default as to any obligation under this Tariff if 
prevented from fulfilling the obligation due to an event of Force 
Majeure. However, a Party whose performance under this Tariff is 
hindered by an event of Force Majeure shall make all reasonable 
efforts to perform its obligations under this Tariff.
    10.2  Indemnification: The Transmission Customer shall at all 
times indemnify, defend, and save the Transmission Provider harmless 
from, any and all damages, losses, claims, including claims and 
actions relating to injury to or death of any person or damage to 
property, demands, suits, recoveries, costs and expenses, court 
costs, attorney fees, and all other obligations by or to third 
parties,

[[Page 21711]]

arising out of or resulting from the Transmission Provider's 
performance of its obligations under this Tariff on behalf of the 
Transmission Customer, except in cases of negligence or intentional 
wrongdoing by the Transmission Provider.

11  Creditworthiness

    For the purpose of determining the ability of the Transmission 
Customer to meet its obligations related to service hereunder, the 
Transmission Provider may require reasonable credit review 
procedures. This review shall be made in accordance with standard 
commercial practices. In addition, the Transmission Provider may 
require the Transmission Customer to provide and maintain in effect 
during the term of the Service Agreement, an unconditional and 
irrevocable letter of credit as security to meet its 
responsibilities and obligations under the Tariff, or an alternative 
form of security proposed by the Transmission Customer and 
acceptable to the Transmission Provider and consistent with 
commercial practices established by the Uniform Commercial Code that 
protects the Transmission Provider against the risk of non-payment.

12  Dispute Resolution Procedures

    12.1  Internal Dispute Resolution Procedures: Any dispute 
between a Transmission Customer and the Transmission Provider 
involving Transmission Service under the Tariff (excluding 
applications for rate changes or other changes to the Tariff, or to 
any Service Agreement entered into under the Tariff, which shall be 
presented directly to the Commission for resolution) shall be 
referred to a designated senior representative of the Transmission 
Provider and a senior representative of the Transmission Customer 
for resolution on an informal basis as promptly as practicable. In 
the event the designated representatives are unable to resolve the 
dispute within thirty (30) days [or such other period as the Parties 
may agree upon] by mutual agreement, such dispute may be submitted 
to arbitration and resolved in accordance with the arbitration 
procedures set forth below.
    12.2  External Arbitration Procedures: Any arbitration initiated 
under the Tariff shall be conducted before a single neutral 
arbitrator appointed by the Parties. If the Parties fail to agree 
upon a single arbitrator within ten (10) days of the referral of the 
dispute to arbitration, each Party shall choose one arbitrator who 
shall sit on a three-member arbitration panel. The two arbitrators 
so chosen shall within twenty (20) days select a third arbitrator to 
chair the arbitration panel. In either case, the arbitrators shall 
be knowledgeable in electric utility matters, including electric 
transmission and bulk power issues, and shall not have any current 
or past substantial business or financial relationships with any 
party to the arbitration (except prior arbitration). The 
arbitrator(s) shall provide each of the Parties an opportunity to be 
heard and, except as otherwise provided herein, shall generally 
conduct the arbitration in accordance with the Commercial 
Arbitration Rules of the American Arbitration Association and any 
applicable Commission regulations or Regional Transmission Group 
rules.
    12.3  Arbitration Decisions: Unless otherwise agreed, the 
arbitrator(s) shall render a decision within ninety (90) days of 
appointment and shall notify the Parties in writing of such decision 
and the reasons therefor. The arbitrator(s) shall be authorized only 
to interpret and apply the provisions of the Tariff and any Service 
Agreement entered into under the Tariff and shall have no power to 
modify or change any of the above in any manner. The decision of the 
arbitrator(s) shall be final and binding upon the Parties, and 
judgment on the award may be entered in any court having 
jurisdiction. The decision of the arbitrator(s) may be appealed 
solely on the grounds that the conduct of the arbitrator(s), or the 
decision itself, violated the standards set forth in the Federal 
Arbitration Act and/or the Administrative Dispute Resolution Act. 
The final decision of the arbitrator must also be filed with the 
Commission if it affects jurisdictional rates, terms and conditions 
of service or facilities.
    12.4  Costs: Each Party shall be responsible for its own costs 
incurred during the arbitration process and for the following costs, 
if applicable:
    (A) The cost of the arbitrator chosen by the Party to sit on the 
three member panel and one half of the cost of the third arbitrator 
chosen; or
    (B) One half the cost of the single arbitrator jointly chosen by 
the Parties.
    12.5  Rights Under the Federal Power Act: Nothing in this 
section shall restrict the rights of any party to file a Complaint 
with the Commission under relevant provisions of the Federal Power 
Act.

II. Point-To-Point Transmission Service

Preamble

    The Transmission Provider will provide Firm and Non-Firm Point-
To-Point Transmission Service pursuant to the applicable terms and 
conditions of this Tariff. Point-To-Point Transmission Service is 
for the receipt of capacity and energy at designated Point(s) of 
Receipt and the transmission of such capacity and energy to 
designated Point(s) of Delivery.

13  Nature of Firm Point-To-Point Transmission Service

    13.1  Term: The minimum term of Firm Point-To-Point Transmission 
Service shall be one day and the maximum term shall be specified in 
the Service Agreement.
    13.2  Reservation Priority: Long-Term Firm Point-To-Point 
Transmission Service shall be available on a first-come, first-
served basis i.e., in the chronological sequence in which each 
Transmission Customer has reserved service. Reservations for Short-
Term Firm Point-To-Point Transmission Service will be conditional 
based upon the length of the requested transaction. If the 
Transmission System becomes oversubscribed, requests for longer term 
service may preempt requests for shorter term service up to the 
following deadlines: one day before the commencement of daily 
service, one week before the commencement of weekly service, and one 
month before the commencement of monthly service. Before the 
deadline, if available transmission capability is insufficient to 
satisfy all Applications, an Eligible Customer with a reservation 
for shorter term service has the right of first refusal to match any 
longer term reservation before losing its reservation priority. 
After the deadline, service will commence pursuant to the terms of 
Part II of the Tariff. Firm Point-To-Point Transmission Service will 
always have a reservation priority over Non-Firm Point-To-Point 
Transmission Service under the Tariff. All Long-Term Firm Point-To-
Point Transmission Service will have equal reservation priority with 
Native Load Customers and Network Customers. Reservation priorities 
for existing firm service customers are provided in Section 2.2.
    13.3  Use of Firm Transmission Service by the Transmission 
Provider: The Transmission Provider will be subject to the rates, 
terms and conditions of Part II of the Tariff when making Third-
Party Sales under (i) agreements executed on or after July 9, 1996, 
or (ii) agreements executed prior to the aforementioned date that 
the Commission requires to be unbundled, by the date specified by 
the Commission. The Transmission Provider will maintain separate 
accounting, pursuant to Section 8, for any use of the Point-To-Point 
Transmission Service to make Third-Party Sales.
    13.4  Service Agreements: The Transmission Provider shall offer 
a standard form Firm Point-To-Point Transmission Service Agreement 
(Attachment A) to an Eligible Customer when it submits a Completed 
Application for Firm Point-To-Point Transmission Service. Executed 
Service Agreements that contain the information required under the 
Tariff shall be filed with the Commission in compliance with 
applicable Commission regulations.
    13.5  Transmission Customer Obligations for Facility Additions 
or Redispatch Costs: In cases where the Transmission Provider 
determines that the Transmission System is not capable of providing 
Firm Point-To-Point Transmission Service without (1) degrading or 
impairing the reliability of service to Native Load Customers, 
Network Customers and other Transmission Customers taking Firm 
Point-To-Point Transmission Service, or (2) interfering with the 
Transmission Provider's ability to meet prior firm contractual 
commitments to others, the Transmission Provider will be obligated 
to expand or upgrade its Transmission System pursuant to the terms 
of Section 15.4. The Transmission Customer must agree to compensate 
the Transmission Provider for any necessary transmission facility 
additions pursuant to the terms of Section 27. To the extent the 
Transmission Provider can relieve any system constraint more 
economically by redispatching the Transmission Provider's resources 
than through constructing Network Upgrades, it shall do so, provided 
that the Eligible Customer agrees to compensate the Transmission 
Provider pursuant to the terms of Section 27. Any redispatch, 
Network Upgrade or Direct Assignment Facilities costs to be charged 
to the Transmission Customer under the Tariff will be specified in 
the Service Agreement prior to initiating service.

[[Page 21712]]

    13.6  Curtailment of Firm Transmission Service: In the event 
that a Curtailment on the Transmission Provider's Transmission 
System, or a portion thereof, is required to maintain reliable 
operation of such system, Curtailments will be made on a non-
discriminatory basis to the transaction(s) that effectively relieve 
the constraint. If multiple transactions require Curtailment, to the 
extent practicable and consistent with Good Utility Practice, 
Curtailments will be proportionally allocated among the Transmission 
Provider's Native Load Customers, Network Customers, and 
Transmission Customers taking Firm Point-To-Point Transmission 
Service. All Curtailments will be made on a non-discriminatory 
basis, however, Non-Firm Point-To-Point Transmission Service shall 
be subordinate to Firm Transmission Service. When the Transmission 
Provider determines that an electrical emergency exists on its 
Transmission System and implements emergency procedures to Curtail 
Firm Transmission Service, the Transmission Customer shall make the 
required reductions upon request of the Transmission Provider. 
However, the Transmission Provider reserves the right to Curtail, in 
whole or in part, any Firm Transmission Service provided under the 
Tariff when, in the Transmission Provider's sole discretion, an 
emergency or other unforeseen condition impairs or degrades the 
reliability of its Transmission System. The Transmission Provider 
will notify all affected Transmission Customers in a timely manner 
of any scheduled Curtailments.
    13.7  Classification of Firm Transmission Service:
    (a) The Transmission Customer taking Firm Point-To-Point 
Transmission Service may (1) change its Receipt and Delivery Points 
to obtain service on a non-firm basis consistent with the terms of 
Section 22.1 or (2) request a modification of the Points of Receipt 
or Delivery on a firm basis pursuant to the terms of Section 22.2.
    (b) The Transmission Customer may purchase transmission service 
to make sales of capacity and energy from multiple generating units 
that are on the Transmission Provider's Transmission System. For 
such a purchase of transmission service, the resources will be 
designated as multiple Points of Receipt, unless the multiple 
generating units are at the same generating plant in which case the 
units would be treated as a single Point of Receipt.
    (c) The Transmission Provider shall provide firm deliveries of 
capacity and energy from the Point(s) of Receipt to the Point(s) of 
Delivery. Each Point of Receipt at which firm transmission capacity 
is reserved by the Transmission Customer shall be set forth in the 
Firm Point-To-Point Service Agreement along with a corresponding 
capacity reservation associated with each Point of Receipt. Each 
Point of Delivery at which firm transmission capacity is reserved by 
the Transmission Customer shall be set forth in the Firm Point-To-
Point Service Agreement along with a corresponding capacity 
reservation associated with each Point of Delivery. The greater of 
either (1) the sum of the capacity reservations at the Point(s) of 
Receipt, or (2) the sum of the capacity reservations at the Point(s) 
of Delivery shall be the Transmission Customer's Reserved Capacity. 
The Transmission Customer will be billed for its Reserved Capacity 
under the terms of Schedule 7. The Transmission Customer may not 
exceed its firm capacity reserved at each Point of Receipt and each 
Point of Delivery except as otherwise specified in Section 22. The 
Transmission Provider shall specify the rate treatment and all 
related terms and conditions applicable in the event that a 
Transmission Customer (including Third-Party Sales by the 
Transmission Provider) exceeds its firm reserved capacity at any 
Point of Receipt or Point of Delivery.
    13.8  Scheduling of Firm Point-To-Point Transmission Service: 
Schedules for the Transmission Customer's Firm Point-To-Point 
Transmission Service must be submitted to the Transmission Provider 
no later than 10:00 a.m. [or a reasonable time that is generally 
accepted in the region and is consistently adhered to by the 
Transmission Provider] of the day prior to commencement of such 
service. Schedules submitted after 10:00 a.m. will be accommodated, 
if practicable. Hour-to-hour schedules of any capacity and energy 
that is to be delivered must be stated in increments of 1,000 kW per 
hour (or a reasonable increment that is generally accepted in the 
region and is consistently adhered to by the Transmission Provider). 
Transmission Customers within the Transmission Provider's service 
area with multiple requests for Transmission Service at a Point of 
Receipt, each of which is under 1,000 kW per hour, may consolidate 
their service requests at a common point of receipt into units of 
1,000 kW per hour for scheduling and billing purposes. Scheduling 
changes will be permitted up to twenty (20) minutes (or a reasonable 
time that is generally accepted in the region and is consistently 
adhered to by the Transmission Provider) before the start of the 
next clock hour provided that the Delivering Party and Receiving 
Party also agree to the schedule modification. The Transmission 
Provider will furnish to the Delivering Party's system operator, 
hour-to-hour schedules equal to those furnished by the Receiving 
Party (unless reduced for losses) and shall deliver the capacity and 
energy provided by such schedules. Should the Transmission Customer, 
Delivering Party or Receiving Party revise or terminate any 
schedule, such party shall immediately notify the Transmission 
Provider, and the Transmission Provider shall have the right to 
adjust accordingly the schedule for capacity and energy to be 
received and to be delivered.

14  Nature of Non-Firm Point-To-Point Transmission Service

    14.1  Term: Non-Firm Point-To-Point Transmission Service will be 
available for periods ranging from one (1) hour to one (1) month. 
However, a Purchaser of Non-Firm Point-To-Point Transmission Service 
will be entitled to reserve a sequential term of service (such as a 
sequential monthly term without having to wait for the initial term 
to expire before requesting another monthly term) so that the total 
time period for which the reservation applies is greater than one 
month, subject to the requirements of Section 18.3.
    14.2  Reservation Priority: Non-Firm Point-To-Point Transmission 
Service shall be available from transmission capability in excess of 
that needed for reliable service to Native Load Customers, Network 
Customers and other Transmission Customers taking Long-Term and 
Short-Term Firm Point-To-Point Transmission Service. A higher 
priority will be assigned to reservations with a longer duration of 
service. In the event the Transmission System is constrained, 
competing requests of equal duration will be prioritized based on 
the highest price offered by the Eligible Customer for the 
Transmission Service. Eligible Customers that have already reserved 
shorter term service have the right of first refusal to match any 
longer term reservation before being preempted. Transmission service 
for Network Customers from resources other than designated Network 
Resources will have a higher priority than any Non-Firm Point-To-
Point Transmission Service. Non-Firm Point-To-Point Transmission 
Service over secondary Point(s) of Receipt and Point(s) of Delivery 
will have the lowest reservation priority under the Tariff.
    14.3  Use of Non-Firm Point-To-Point Transmission Service by the 
Transmission Provider: The Transmission Provider will be subject to 
the rates, terms and conditions of Part II of the Tariff when making 
Third-Party Sales under (i) agreements executed on or after July 9, 
1996 or (ii) agreements executed prior to the aforementioned date 
that the Commission requires to be unbundled, by the date specified 
by the Commission. The Transmission Provider will maintain separate 
accounting, pursuant to Section 8, for any use of Non-Firm Point-To-
Point Transmission Service to make Third-Party Sales.
    14.4  Service Agreements: The Transmission Provider shall offer 
a standard form Non-Firm Point-To-Point Transmission Service 
Agreement (Attachment B) to an Eligible Customer when it first 
submits a Completed Application for Non-Firm Point-To-Point 
Transmission Service pursuant to the Tariff. Executed Service 
Agreements that contain the information required under the Tariff 
shall be filed with the Commission in compliance with applicable 
Commission regulations.
    14.5  Classification of Non-Firm Point-To-Point Transmission 
Service: Non-Firm Point-To-Point Transmission Service shall be 
offered under terms and conditions contained in Part II of the 
Tariff. The Transmission Provider undertakes no obligation under the 
Tariff to plan its Transmission System in order to have sufficient 
capacity for Non-Firm Point-To-Point Transmission Service. Parties 
requesting Non-Firm Point-To-Point Transmission Service for the 
transmission of firm power do so with the full realization that such 
service is subject to availability and to Curtailment or 
Interruption under the terms of the Tariff. The Transmission 
Provider shall specify the rate treatment and all related terms and 
conditions applicable in

[[Page 21713]]

the event that a Transmission Customer (including Third-Party Sales 
by the Transmission Provider) exceeds its non-firm capacity 
reservation. Non-Firm Point-To-Point Transmission Service shall 
include transmission of energy on an hourly basis and transmission 
of scheduled short-term capacity and energy on a daily, weekly or 
monthly basis, but not to exceed one month's reservation for any one 
Application, under Schedule 8.
    14.6 Scheduling of Non-Firm Point-To-Point Transmission Service: 
Schedules for Non-Firm Point-To-Point Transmission Service must be 
submitted to the Transmission Provider no later than 2:00 p.m. [or a 
reasonable time that is generally accepted in the region and is 
consistently adhered to by the Transmission Provider] of the day 
prior to commencement of such service. Schedules submitted after 
2:00 p.m. will be accommodated, if practicable. Hour-to-hour 
schedules of energy that is to be delivered must be stated in 
increments of 1,000 kW per hour [or a reasonable increment that is 
generally accepted in the region and is consistently adhered to by 
the Transmission Provider]. Transmission Customers within the 
Transmission Provider's service area with multiple requests for 
Transmission Service at a Point of Receipt, each of which is under 
1,000 kW per hour, may consolidate their schedules at a common Point 
of Receipt into units of 1,000 kW per hour. Scheduling changes will 
be permitted up to twenty (20) minutes [or a reasonable time that is 
generally accepted in the region and is consistently adhered to by 
the Transmission Provider] before the start of the next clock hour 
provided that the Delivering Party and Receiving Party also agree to 
the schedule modification. The Transmission Provider will furnish to 
the Delivering Party's system operator, hour-to-hour schedules equal 
to those furnished by the Receiving Party (unless reduced for 
losses) and shall deliver the capacity and energy provided by such 
schedules. Should the Transmission Customer, Delivering Party or 
Receiving Party revise or terminate any schedule, such party shall 
immediately notify the Transmission Provider, and the Transmission 
Provider shall have the right to adjust accordingly the schedule for 
capacity and energy to be received and to be delivered.
    14.7  Curtailment or Interruption of Service: The Transmission 
Provider reserves the right to Curtail, in whole or in part, Non-
Firm Point-To-Point Transmission Service provided under the Tariff 
for reliability reasons when, an emergency or other unforeseen 
condition threatens to impair or degrade the reliability of its 
Transmission System. The Transmission Provider reserves the right to 
Interrupt, in whole or in part, Non-Firm Point-To-Point Transmission 
Service provided under the Tariff for economic reasons in order to 
accommodate (1) a request for Firm Transmission Service, (2) a 
request for Non-Firm Point-To-Point Transmission Service of greater 
duration, (3) a request for Non-Firm Point-To-Point Transmission 
Service of equal duration with a higher price, or (4) transmission 
service for Network Customers from non-designated resources. The 
Transmission Provider also will discontinue or reduce service to the 
Transmission Customer to the extent that deliveries for transmission 
are discontinued or reduced at the Point(s) of Receipt. Where 
required, Curtailments or Interruptions will be made on a non-
discriminatory basis to the transaction(s) that effectively relieve 
the constraint, however, Non-Firm Point-To-Point Transmission 
Service shall be subordinate to Firm Transmission Service. If 
multiple transactions require Curtailment or Interruption, to the 
extent practicable and consistent with Good Utility Practice, 
Curtailments or Interruptions will be made to transactions of the 
shortest term (e.g., hourly non-firm transactions will be Curtailed 
or Interrupted before daily non-firm transactions and daily non-firm 
transactions will be Curtailed or Interrupted before weekly non-firm 
transactions). Transmission service for Network Customers from 
resources other than designated Network Resources will have a higher 
priority than any Non-Firm Point-To-Point Transmission Service under 
the Tariff. Non-Firm Point-To-Point Transmission Service over 
secondary Point(s) of Receipt and Point(s) of Delivery will have a 
lower priority than any Non-Firm Point-To-Point Transmission Service 
under the Tariff. The Transmission Provider will provide advance 
notice of Curtailment or Interruption where such notice can be 
provided consistent with Good Utility Practice.

15  Service Availability

    15.1  General Conditions: The Transmission Provider will provide 
Firm and Non-Firm Point-To-Point Transmission Service over, on or 
across its Transmission System to any Transmission Customer that has 
met the requirements of Section 16.
    15.2  Determination of Available Transmission Capability: A 
description of the Transmission Provider's specific methodology for 
assessing available transmission capability posted on the 
Transmission Provider's OASIS (Section 4) is contained in Attachment 
C of the Tariff. In the event sufficient transmission capability may 
not exist to accommodate a service request, the Transmission 
Provider will respond by performing a System Impact Study.
    15.3  Initiating Service in the Absence of an Executed Service 
Agreement: If the Transmission Provider and the Transmission 
Customer requesting Firm or Non-Firm Point-To-Point Transmission 
Service cannot agree on all the terms and conditions of the Point-
To-Point Service Agreement, the Transmission Provider shall file 
with the Commission, within thirty (30) days after the date the 
Transmission Customer provides written notification directing the 
Transmission Provider to file, an unexecuted Point-To-Point Service 
Agreement containing terms and conditions deemed appropriate by the 
Transmission Provider for such requested Transmission Service. The 
Transmission Provider shall commence providing Transmission Service 
subject to the Transmission Customer agreeing to (i) compensate the 
Transmission Provider at whatever rate the Commission ultimately 
determines to be just and reasonable, and (ii) comply with the terms 
and conditions of the Tariff including posting appropriate security 
deposits in accordance with the terms of Section 17.3.
    15.4  Obligation to Provide Transmission Service that Requires 
Expansion or Modification of the Transmission System: If the 
Transmission Provider determines that it cannot accommodate a 
Completed Application for Firm Point-To-Point Transmission Service 
because of insufficient capability on its Transmission System, the 
Transmission Provider will use due diligence to expand or modify its 
Transmission System to provide the requested Firm Transmission 
Service, provided the Transmission Customer agrees to compensate the 
Transmission Provider for such costs pursuant to the terms of 
Section 27. The Transmission Provider will conform to Good Utility 
Practice in determining the need for new facilities and in the 
design and construction of such facilities. The obligation applies 
only to those facilities that the Transmission Provider has the 
right to expand or modify.
    15.5  Deferral of Service: The Transmission Provider may defer 
providing service until it completes construction of new 
transmission facilities or upgrades needed to provide Firm Point-To-
Point Transmission Service whenever the Transmission Provider 
determines that providing the requested service would, without such 
new facilities or upgrades, impair or degrade reliability to any 
existing firm services.
    15.6  Other Transmission Service Schedules: Eligible Customers 
receiving transmission service under other agreements on file with 
the Commission may continue to receive transmission service under 
those agreements until such time as those agreements may be modified 
by the Commission.
    15.7  Real Power Losses: Real Power Losses are associated with 
all transmission service. The Transmission Provider is not obligated 
to provide Real Power Losses. The Transmission Customer is 
responsible for replacing losses associated with all transmission 
service as calculated by the Transmission Provider. The applicable 
Real Power Loss factors are as follows: [To be completed by the 
Transmission Provider].

16  Transmission Customer Responsibilities

    16.1  Conditions Required of Transmission Customers: Point-To-
Point Transmission Service shall be provided by the Transmission 
Provider only if the following conditions are satisfied by the 
Transmission Customer:
    a. The Transmission Customer has pending a Completed Application 
for service;
    b. The Transmission Customer meets the creditworthiness criteria 
set forth in Section 11;
    c. The Transmission Customer will have arrangements in place for 
any other transmission service necessary to effect the delivery from 
the generating source to the Transmission Provider prior to the time 
service under Part II of the Tariff commences;
    d. The Transmission Customer agrees to pay for any facilities 
constructed and

[[Page 21714]]

chargeable to such Transmission Customer under Part II of the 
Tariff, whether or not the Transmission Customer takes service for 
the full term of its reservation; and
    e. The Transmission Customer has executed a Point-To-Point 
Service Agreement or has agreed to receive service pursuant to 
Section 15.3.
    16.2  Transmission Customer Responsibility for Third-Party 
Arrangements: Any scheduling arrangements that may be required by 
other electric systems shall be the responsibility of the 
Transmission Customer requesting service. The Transmission Customer 
shall provide, unless waived by the Transmission Provider, 
notification to the Transmission Provider identifying such systems 
and authorizing them to schedule the capacity and energy to be 
transmitted by the Transmission Provider pursuant to Part II of the 
Tariff on behalf of the Receiving Party at the Point of Delivery or 
the Delivering Party at the Point of Receipt. However, the 
Transmission Provider will undertake reasonable efforts to assist 
the Transmission Customer in making such arrangements, including 
without limitation, providing any information or data required by 
such other electric system pursuant to Good Utility Practice.

17  Procedures for Arranging Firm Point-To-Point Transmission 
Service

    17.1  Application: A request for Firm Point-To-Point 
Transmission Service for periods of one year or longer must contain 
a written Application to: [Transmission Provider Name and Address], 
at least sixty (60) days in advance of the calendar month in which 
service is to commence. The Transmission Provider will consider 
requests for such firm service on shorter notice when feasible. 
Requests for firm service for periods of less than one year shall be 
subject to expedited procedures that shall be negotiated between the 
Parties within the time constraints provided in Section 17.5. All 
Firm Point-To-Point Transmission Service requests should be 
submitted by entering the information listed below on the 
Transmission Provider's OASIS. Prior to implementation of the 
Transmission Provider's OASIS, a Completed Application may be 
submitted by (i) transmitting the required information to the 
Transmission Provider by telefax, or (ii) providing the information 
by telephone over the Transmission Provider's time recorded 
telephone line. Each of these methods will provide a time-stamped 
record for establishing the priority of the Application.
    17.2  Completed Application: A Completed Application shall 
provide all of the information included in 18 CFR Sec. 2.20 
including but not limited to the following:
    (i) The identity, address, telephone number and facsimile number 
of the entity requesting service;
    (ii) A statement that the entity requesting service is, or will 
be upon commencement of service, an Eligible Customer under the 
Tariff;
    (iii) The location of the Point(s) of Receipt and Point(s) of 
Delivery and the identities of the Delivering Parties and the 
Receiving Parties;
    (iv) The location of the generating facility(ies) supplying the 
capacity and energy and the location of the load ultimately served 
by the capacity and energy transmitted. The Transmission Provider 
will treat this information as confidential except to the extent 
that disclosure of this information is required by this Tariff, by 
regulatory or judicial order, for reliability purposes pursuant to 
Good Utility Practice or pursuant to RTG transmission information 
sharing agreements. The Transmission Provider shall treat this 
information consistent with the standards of conduct contained in 
Part 37 of the Commission's regulations;
    (v) A description of the supply characteristics of the capacity 
and energy to be delivered;
    (vi) An estimate of the capacity and energy expected to be 
delivered to the Receiving Party;
    (vii) The Service Commencement Date and the term of the 
requested Transmission Service; and
    (viii) The transmission capacity requested for each Point of 
Receipt and each Point of Delivery on the Transmission Provider's 
Transmission System; customers may combine their requests for 
service in order to satisfy the minimum transmission capacity 
requirement.
    The Transmission Provider shall treat this information 
consistent with the standards of conduct contained in Part 37 of the 
Commission's regulations.
    17.3  Deposit: A Completed Application for Firm Point-To-Point 
Transmission Service also shall include a deposit of either one 
month's charge for Reserved Capacity or the full charge for Reserved 
Capacity for service requests of less than one month. If the 
Application is rejected by the Transmission Provider because it does 
not meet the conditions for service as set forth herein, or in the 
case of requests for service arising in connection with losing 
bidders in a Request For Proposals (RFP), said deposit shall be 
returned with interest less any reasonable costs incurred by the 
Transmission Provider in connection with the review of the losing 
bidder's Application. The deposit also will be returned with 
interest less any reasonable costs incurred by the Transmission 
Provider if the Transmission Provider is unable to complete new 
facilities needed to provide the service. If an Application is 
withdrawn or the Eligible Customer decides not to enter into a 
Service Agreement for Firm Point-To-Point Transmission Service, the 
deposit shall be refunded in full, with interest, less reasonable 
costs incurred by the Transmission Provider to the extent such costs 
have not already been recovered by the Transmission Provider from 
the Eligible Customer. The Transmission Provider will provide to the 
Eligible Customer a complete accounting of all costs deducted from 
the refunded deposit, which the Eligible Customer may contest if 
there is a dispute concerning the deducted costs. Deposits 
associated with construction of new facilities are subject to the 
provisions of Section 19. If a Service Agreement for Firm Point-To-
Point Transmission Service is executed, the deposit, with interest, 
will be returned to the Transmission Customer upon expiration of the 
Service Agreement for Firm Point-To-Point Transmission Service. 
Applicable interest shall be computed in accordance with the 
Commission's regulations at 18 CFR Sec. 35.19a(a)(2)(iii), and shall 
be calculated from the day the deposit check is credited to the 
Transmission Provider's account.
    17.4  Notice of Deficient Application: If an Application fails 
to meet the requirements of the Tariff, the Transmission Provider 
shall notify the entity requesting service within fifteen (15) days 
of receipt of the reasons for such failure. The Transmission 
Provider will attempt to remedy minor deficiencies in the 
Application through informal communications with the Eligible 
Customer. If such efforts are unsuccessful, the Transmission 
Provider shall return the Application, along with any deposit, with 
interest. Upon receipt of a new or revised Application that fully 
complies with the requirements of Part II of the Tariff, the 
Eligible Customer shall be assigned a new priority consistent with 
the date of the new or revised Application.
    17.5  Response to a Completed Application: Following receipt of 
a Completed Application for Firm Point-To-Point Transmission 
Service, the Transmission Provider shall make a determination of 
available transmission capability as required in Section 15.2. The 
Transmission Provider shall notify the Eligible Customer as soon as 
practicable, but not later than thirty (30) days after the date of 
receipt of a Completed Application either (i) if it will be able to 
provide service without performing a System Impact Study or (ii) if 
such a study is needed to evaluate the impact of the Application 
pursuant to Section 19.1.
    17.6  Execution of Service Agreement: Whenever the Transmission 
Provider determines that a System Impact Study is not required and 
that the service can be provided, it shall notify the Eligible 
Customer as soon as practicable but no later than thirty (30) days 
after receipt of the Completed Application. Where a System Impact 
Study is required, the provisions of Section 19 will govern the 
execution of a Service Agreement. Failure of an Eligible Customer to 
execute and return the Service Agreement or request the filing of an 
unexecuted service agreement pursuant to Section 15.3, within 
fifteen (15) days after it is tendered by the Transmission Provider 
will be deemed a withdrawal and termination of the Application and 
any deposit submitted shall be refunded with interest. Nothing 
herein limits the right of an Eligible Customer to file another 
Application after such withdrawal and termination.
    17.7  Extensions for Commencement of Service: The Transmission 
Customer can obtain up to five (5) one-year extensions for the 
commencement of service. The Transmission Customer may postpone 
service by paying a non-refundable annual reservation fee equal to 
one-month's charge for Firm Transmission Service for each year or 
fraction thereof. If during any extension for the commencement of 
service an Eligible Customer submits a Completed Application for 
Firm Transmission Service, and such request can be satisfied only by 
releasing all or part of the Transmission Customer's Reserved 
Capacity, the original Reserved

[[Page 21715]]

Capacity will be released unless the following condition is 
satisfied. Within thirty (30) days, the original Transmission 
Customer agrees to pay the Firm Point-To-Point transmission rate for 
its Reserved Capacity concurrent with the new Service Commencement 
Date. In the event the Transmission Customer elects to release the 
Reserved Capacity, the reservation fees or portions thereof 
previously paid will be forfeited.

18  Procedures for Arranging Non-Firm Point-To-Point Transmission 
Service

    18.1  Application: Eligible Customers seeking Non-Firm Point-To-
Point Transmission Service must submit a Completed Application to 
the Transmission Provider. Applications should be submitted by 
entering the information listed below on the Transmission Provider's 
OASIS. Prior to implementation of the Transmission Provider's OASIS, 
a Completed Application may be submitted by (i) transmitting the 
required information to the Transmission Provider by telefax, or 
(ii) providing the information by telephone over the Transmission 
Provider's time recorded telephone line. Each of these methods will 
provide a time-stamped record for establishing the service priority 
of the Application.
    18.2  Completed Application: A Completed Application shall 
provide all of the information included in 18 CFR Sec. 2.20 
including but not limited to the following:
     (i) The identity, address, telephone number and facsimile 
number of the entity requesting service;
    (ii) A statement that the entity requesting service is, or will 
be upon commencement of service, an Eligible Customer under the 
Tariff;
     (iii) The Point(s) of Receipt and the Point(s) of Delivery;
     (iv) The maximum amount of capacity requested at each Point of 
Receipt and Point of Delivery; and
     (v) The proposed dates and hours for initiating and terminating 
transmission service hereunder.
     In addition to the information specified above, when required 
to properly evaluate system conditions, the Transmission Provider 
also may ask the Transmission Customer to provide the following:
     (vi) The electrical location of the initial source of the power 
to be transmitted pursuant to the Transmission Customer's request 
for service; and
     (vii) The electrical location of the ultimate load.
     The Transmission Provider will treat this information in (vi) 
and (vii) as confidential at the request of the Transmission 
Customer except to the extent that disclosure of this information is 
required by this Tariff, by regulatory or judicial order, for 
reliability purposes pursuant to Good Utility Practice, or pursuant 
to RTG transmission information sharing agreements. The Transmission 
Provider shall treat this information consistent with the standards 
of conduct contained in Part 37 of the Commission's regulations.
    18.3  Reservation of Non-Firm Point-To-Point Transmission 
Service: Requests for monthly service shall be submitted no earlier 
than sixty (60) days before service is to commence; requests for 
weekly service shall be submitted no earlier than fourteen (14) days 
before service is to commence, requests for daily service shall be 
submitted no earlier than two (2) days before service is to 
commence, and requests for hourly service shall be submitted no 
earlier than noon the day before service is to commence. Requests 
for service received later than 2:00 p.m. prior to the day service 
is scheduled to commence will be accommodated if practicable [or 
such reasonable times that are generally accepted in the region and 
are consistently adhered to by the Transmission Provider].
    18.4  Determination of Available Transmission Capability: 
Following receipt of a tendered schedule the Transmission Provider 
will make a determination on a non-discriminatory basis of available 
transmission capability pursuant to Section 15.2. Such determination 
shall be made as soon as reasonably practicable after receipt, but 
not later than the following time periods for the following terms of 
service (i) thirty (30) minutes for hourly service, (ii) thirty (30) 
minutes for daily service, (iii) four (4) hours for weekly service, 
and (iv) two (2) days for monthly service. [Or such reasonable times 
that are generally accepted in the region and are consistently 
adhered to by the Transmission Provider].

19  Additional Study Procedures for Firm Point-To-Point 
Transmission Service Requests

    19.1  Notice of Need for System Impact Study: After receiving a 
request for service, the Transmission Provider shall determine on a 
non-discriminatory basis whether a System Impact Study is needed. A 
description of the Transmission Provider's methodology for 
completing a System Impact Study is provided in Attachment D. If the 
Transmission Provider determines that a System Impact Study is 
necessary to accommodate the requested service, it shall so inform 
the Eligible Customer, as soon as practicable. In such cases, the 
Transmission Provider shall within thirty (30) days of receipt of a 
Completed Application, tender a System Impact Study Agreement 
pursuant to which the Eligible Customer shall agree to reimburse the 
Transmission Provider for performing the required System Impact 
Study. For a service request to remain a Completed Application, the 
Eligible Customer shall execute the System Impact Study Agreement 
and return it to the Transmission Provider within fifteen (15) days. 
If the Eligible Customer elects not to execute the System Impact 
Study Agreement, its application shall be deemed withdrawn and its 
deposit, pursuant to Section 17.3, shall be returned with interest.
    19.2  System Impact Study Agreement and Cost Reimbursement:
     (i) The System Impact Study Agreement will clearly specify the 
maximum charge, based on the Transmission Provider's estimate of the 
actual cost, and time for completion of the System Impact Study. The 
charge shall not exceed the actual cost of the study. In performing 
the System Impact Study, the Transmission Provider shall rely, to 
the extent reasonably practicable, on existing transmission planning 
studies. The Eligible Customer will not be assessed a charge for 
such existing studies; however, the Eligible Customer will be 
responsible for charges associated with any modifications to 
existing planning studies that are reasonably necessary to evaluate 
the impact of the Eligible Customer's request for service on the 
Transmission System.
     (ii) If in response to multiple Eligible Customers requesting 
service in relation to the same competitive solicitation, a single 
System Impact Study is sufficient for the Transmission Provider to 
accommodate the requests for service, the costs of that study shall 
be pro-rated among the Eligible Customers.
     (iii) For System Impact Studies that the Transmission Provider 
conducts on its own behalf, the Transmission Provider shall record 
the cost of the System Impact Studies pursuant to Section 20.
    19.3  System Impact Study Procedures: Upon receipt of an 
executed System Impact Study Agreement, the Transmission Provider 
will use due diligence to complete the required System Impact Study 
within a sixty (60) day period. The System Impact Study shall 
identify any system constraints and redispatch options, additional 
Direct Assignment Facilities or Network Upgrades required to provide 
the requested service. In the event that the Transmission Provider 
is unable to complete the required System Impact Study within such 
time period, it shall so notify the Eligible Customer and provide an 
estimated completion date along with an explanation of the reasons 
why additional time is required to complete the required studies. A 
copy of the completed System Impact Study and related work papers 
shall be made available to the Eligible Customer. The Transmission 
Provider will use the same due diligence in completing the System 
Impact Study for an Eligible Customer as it uses when completing 
studies for itself. The Transmission Provider shall notify the 
Eligible Customer immediately upon completion of the System Impact 
Study if the Transmission System will be adequate to accommodate all 
or part of a request for service or that no costs are likely to be 
incurred for new transmission facilities or upgrades. In order for a 
request to remain a Completed Application, within fifteen (15) days 
of completion of the System Impact Study the Eligible Customer must 
execute a Service Agreement or request the filing of an unexecuted 
Service Agreement pursuant to Section 15.3, or the Application shall 
be deemed terminated and withdrawn.
    19.4  Facilities Study Procedures: If a System Impact Study 
indicates that additions or upgrades to the Transmission System are 
needed to supply the Eligible Customer's service request, the 
Transmission Provider, within thirty (30) days of the completion of 
the System Impact Study, shall tender to the Eligible Customer a 
Facilities Study Agreement pursuant to which the Eligible Customer 
shall agree to reimburse the Transmission Provider for performing 
the required Facilities Study. For a service request to remain a 
Completed Application, the Eligible Customer shall execute the

[[Page 21716]]

Facilities Study Agreement and return it to the Transmission 
Provider within fifteen (15) days. If the Eligible Customer elects 
not to execute the Facilities Study Agreement, its application shall 
be deemed withdrawn and its deposit, pursuant to Section 17.3, shall 
be returned with interest. Upon receipt of an executed Facilities 
Study Agreement, the Transmission Provider will use due diligence to 
complete the required Facilities Study within a sixty (60) day 
period. If the Transmission Provider is unable to complete the 
Facilities Study in the allotted time period, the Transmission 
Provider shall notify the Transmission Customer and provide an 
estimate of the time needed to reach a final determination along 
with an explanation of the reasons that additional time is required 
to complete the study. When completed, the Facilities Study will 
include a good faith estimate of (i) the cost of Direct Assignment 
Facilities to be charged to the Transmission Customer, (ii) the 
Transmission Customer's appropriate share of the cost of any 
required Network Upgrades as determined pursuant to the provisions 
of Part II of the Tariff, and (iii) the time required to complete 
such construction and initiate the requested service. The 
Transmission Customer shall provide the Transmission Provider with a 
letter of credit or other reasonable form of security acceptable to 
the Transmission Provider equivalent to the costs of new facilities 
or upgrades consistent with commercial practices as established by 
the Uniform Commercial Code. The Transmission Customer shall have 
thirty (30) days to execute a Service Agreement or request the 
filing of an unexecuted Service Agreement and provide the required 
letter of credit or other form of security or the request will no 
longer be a Completed Application and shall be deemed terminated and 
withdrawn.
    19.5  Facilities Study Modifications: Any change in design 
arising from inability to site or construct facilities as proposed 
will require development of a revised good faith estimate. New good 
faith estimates also will be required in the event of new statutory 
or regulatory requirements that are effective before the completion 
of construction or other circumstances beyond the control of the 
Transmission Provider that significantly affect the final cost of 
new facilities or upgrades to be charged to the Transmission 
Customer pursuant to the provisions of Part II of the Tariff.
    19.6  Due Diligence in Completing New Facilities: The 
Transmission Provider shall use due diligence to add necessary 
facilities or upgrade its Transmission System within a reasonable 
time. The Transmission Provider will not upgrade its existing or 
planned Transmission System in order to provide the requested Firm 
Point-To-Point Transmission Service if doing so would impair system 
reliability or otherwise impair or degrade existing firm service.
    19.7  Partial Interim Service: If the Transmission Provider 
determines that it will not have adequate transmission capability to 
satisfy the full amount of a Completed Application for Firm Point-
To-Point Transmission Service, the Transmission Provider nonetheless 
shall be obligated to offer and provide the portion of the requested 
Firm Point-To-Point Transmission Service that can be accommodated 
without addition of any facilities and through redispatch. However, 
the Transmission Provider shall not be obligated to provide the 
incremental amount of requested Firm Point-To-Point Transmission 
Service that requires the addition of facilities or upgrades to the 
Transmission System until such facilities or upgrades have been 
placed in service.
    19.8  Expedited Procedures for New Facilities: In lieu of the 
procedures set forth above, the Eligible Customer shall have the 
option to expedite the process by requesting the Transmission 
Provider to tender at one time, together with the results of 
required studies, an ``Expedited Service Agreement'' pursuant to 
which the Eligible Customer would agree to compensate the 
Transmission Provider for all costs incurred pursuant to the terms 
of the Tariff. In order to exercise this option, the Eligible 
Customer shall request in writing an expedited Service Agreement 
covering all of the above-specified items within thirty (30) days of 
receiving the results of the System Impact Study identifying needed 
facility additions or upgrades or costs incurred in providing the 
requested service. While the Transmission Provider agrees to provide 
the Eligible Customer with its best estimate of the new facility 
costs and other charges that may be incurred, such estimate shall 
not be binding and the Eligible Customer must agree in writing to 
compensate the Transmission Provider for all costs incurred pursuant 
to the provisions of the Tariff. The Eligible Customer shall execute 
and return such an Expedited Service Agreement within fifteen (15) 
days of its receipt or the Eligible Customer's request for service 
will cease to be a Completed Application and will be deemed 
terminated and withdrawn.

20  Procedures if the Transmission Provider is Unable to Complete 
New Transmission Facilities for Firm Point-To-Point Transmission 
Service

    20.1  Delays in Construction of New Facilities: If any event 
occurs that will materially affect the time for completion of new 
facilities, or the ability to complete them, the Transmission 
Provider shall promptly notify the Transmission Customer. In such 
circumstances, the Transmission Provider shall within thirty (30) 
days of notifying the Transmission Customer of such delays, convene 
a technical meeting with the Transmission Customer to evaluate the 
alternatives available to the Transmission Customer. The 
Transmission Provider also shall make available to the Transmission 
Customer studies and work papers related to the delay, including all 
information that is in the possession of the Transmission Provider 
that is reasonably needed by the Transmission Customer to evaluate 
any alternatives.
    20.2  Alternatives to the Original Facility Additions: When the 
review process of Section determines that one or more alternatives 
exist to the originally planned construction project, the 
Transmission Provider shall present such alternatives for 
consideration by the Transmission Customer. If, upon review of any 
alternatives, the Transmission Customer desires to maintain its 
Completed Application subject to construction of the alternative 
facilities, it may request the Transmission Provider to submit a 
revised Service Agreement for Firm Point-To-Point Transmission 
Service. If the alternative approach solely involves Non-Firm Point-
To-Point Transmission Service, the Transmission Provider shall 
promptly tender a Service Agreement for Non-Firm Point-To-Point 
Transmission Service providing for the service. In the event the 
Transmission Provider concludes that no reasonable alternative 
exists and the Transmission Customer disagrees, the Transmission 
Customer may seek relief under the dispute resolution procedures 
pursuant to Section 12 or it may refer the dispute to the Commission 
for resolution.
    20.3  Refund Obligation for Unfinished Facility Additions: If 
the Transmission Provider and the Transmission Customer mutually 
agree that no other reasonable alternatives exist and the requested 
service cannot be provided out of existing capability under the 
conditions of Part II of the Tariff, the obligation to provide the 
requested Firm Point-To-Point Transmission Service shall terminate 
and any deposit made by the Transmission Customer shall be returned 
with interest pursuant to Commission regulations 35.19a(a)(2)(iii). 
However, the Transmission Customer shall be responsible for all 
prudently incurred costs by the Transmission Provider through the 
time construction was suspended.

21  Provisions Relating to Transmission Construction and Services 
on the Systems of Other Utilities

    21.1  Responsibility for Third-Party System Additions: The 
Transmission Provider shall not be responsible for making 
arrangements for any necessary engineering, permitting, and 
construction of transmission or distribution facilities on the 
system(s) of any other entity or for obtaining any regulatory 
approval for such facilities. The Transmission Provider will 
undertake reasonable efforts to assist the Transmission Customer in 
obtaining such arrangements, including without limitation, providing 
any information or data required by such other electric system 
pursuant to Good Utility Practice.
    21.2  Coordination of Third-Party System Additions: In 
circumstances where the need for transmission facilities or upgrades 
is identified pursuant to the provisions of Part II of the Tariff, 
and if such upgrades further require the addition of transmission 
facilities on other systems, the Transmission Provider shall have 
the right to coordinate construction on its own system with the 
construction required by others. The Transmission Provider, after 
consultation with the Transmission Customer and representatives of 
such other systems, may defer construction of its new transmission 
facilities, if the new transmission facilities on another system 
cannot be completed in a timely manner. The Transmission Provider 
shall notify the Transmission Customer in writing of the basis for 
any decision to defer construction and the specific problems

[[Page 21717]]

which must be resolved before it will initiate or resume 
construction of new facilities. Within sixty (60) days of receiving 
written notification by the Transmission Provider of its intent to 
defer construction pursuant to this section, the Transmission 
Customer may challenge the decision in accordance with the dispute 
resolution procedures pursuant to Section 12 or it may refer the 
dispute to the Commission for resolution.

22  Changes in Service Specifications

    22.1  Modifications On a Non-Firm Basis: The Transmission 
Customer taking Firm Point-To-Point Transmission Service may request 
the Transmission Provider to provide transmission service on a non-
firm basis over Receipt and Delivery Points other than those 
specified in the Service Agreement (``Secondary Receipt and Delivery 
Points''), in amounts not to exceed its firm capacity reservation, 
without incurring an additional Non-Firm Point-To-Point Transmission 
Service charge or executing a new Service Agreement, subject to the 
following conditions.
    (a) Service provided over Secondary Receipt and Delivery Points 
will be non-firm only, on an as-available basis and will not 
displace any firm or non-firm service reserved or scheduled by 
third-parties under the Tariff or by the Transmission Provider on 
behalf of its Native Load Customers.
    (b) The sum of all Firm and non-firm Point-To-Point Transmission 
Service provided to the Transmission Customer at any time pursuant 
to this section shall not exceed the Reserved Capacity in the 
relevant Service Agreement under which such services are provided.
    (c) The Transmission Customer shall retain its right to schedule 
Firm Point-To-Point Transmission Service at the Receipt and Delivery 
Points specified in the relevant Service Agreement in the amount of 
its original capacity reservation.
    (d) Service over Secondary Receipt and Delivery Points on a non-
firm basis shall not require the filing of an Application for Non-
Firm Point-To-Point Transmission Service under the Tariff. However, 
all other requirements of Part II of the Tariff (except as to 
transmission rates) shall apply to transmission service on a non-
firm basis over Secondary Receipt and Delivery Points.
    22.2  Modification On a Firm Basis: Any request by a 
Transmission Customer to modify Receipt and Delivery Points on a 
firm basis shall be treated as a new request for service in 
accordance with Section 17 hereof, except that such Transmission 
Customer shall not be obligated to pay any additional deposit if the 
capacity reservation does not exceed the amount reserved in the 
existing Service Agreement. While such new request is pending, the 
Transmission Customer shall retain its priority for service at the 
existing firm Receipt and Delivery Points specified in its Service 
Agreement.

23  Sale or Assignment of Transmission Service

    23.1  Procedures for Assignment or Transfer of Service: Subject 
to Commission approval of any necessary filings, a Transmission 
Customer may sell, assign, or transfer all or a portion of its 
rights under its Service Agreement, but only to another Eligible 
Customer (the Assignee). The Transmission Customer that sells, 
assigns or transfers its rights under its Service Agreement is 
hereafter referred to as the Reseller. Compensation to the Reseller 
shall not exceed the higher of (i) the original rate paid by the 
Reseller, (ii) the Transmission Provider's maximum rate on file at 
the time of the assignment, or (iii) the Reseller's opportunity 
cost. If the Assignee does not request any change in the Point(s) of 
Receipt or the Point(s) of Delivery, or a change in any other term 
or condition set forth in the original Service Agreement, the 
Assignee will receive the same services as did the Reseller and the 
priority of service for the Assignee will be the same as that of the 
Reseller. A Reseller should notify the Transmission Provider as soon 
as possible after any assignment or transfer of service occurs but 
in any event, notification must be provided prior to any provision 
of service to the Assignee. The Assignee will be subject to all 
terms and conditions of this Tariff. If the Assignee requests a 
change in service, the reservation priority of service will be 
determined by the Transmission Provider pursuant to Section 13.2.
    23.2  Limitations on Assignment or Transfer of Service: If the 
Assignee requests a change in the Point(s) of Receipt or Point(s) of 
Delivery, or a change in any other specifications set forth in the 
original Service Agreement, the Transmission Provider will consent 
to such change subject to the provisions of the Tariff, provided 
that the change will not impair the operation and reliability of the 
Transmission Provider's generation, transmission, or distribution 
systems. The Assignee shall compensate the Transmission Provider for 
performing any System Impact Study needed to evaluate the capability 
of the Transmission System to accommodate the proposed change and 
any additional costs resulting from such change. The Reseller shall 
remain liable for the performance of all obligations under the 
Service Agreement, except as specifically agreed to by the Parties 
through an amendment to the Service Agreement.
    23.3  Information on Assignment or Transfer of Service: In 
accordance with Section 4, Resellers may use the Transmission 
Provider's OASIS to post transmission capacity available for resale.

24  Metering and Power Factor Correction at Receipt and Delivery 
Points(s)

    24.1  Transmission Customer Obligations: Unless otherwise 
agreed, the Transmission Customer shall be responsible for 
installing and maintaining compatible metering and communications 
equipment to accurately account for the capacity and energy being 
transmitted under Part II of the Tariff and to communicate the 
information to the Transmission Provider. Such equipment shall 
remain the property of the Transmission Customer.
    24.2  Transmission Provider Access to Metering Data: The 
Transmission Provider shall have access to metering data, which may 
reasonably be required to facilitate measurements and billing under 
the Service Agreement.
    24.3  Power Factor: Unless otherwise agreed, the Transmission 
Customer is required to maintain a power factor within the same 
range as the Transmission Provider pursuant to Good Utility 
Practices. The power factor requirements are specified in the 
Service Agreement where applicable.

25  Compensation for Transmission Service

    Rates for Firm and Non-Firm Point-To-Point Transmission Service 
are provided in the Schedules appended to the Tariff: Firm Point-To-
Point Transmission Service (Schedule 7); and Non-Firm Point-To-Point 
Transmission Service (Schedule 8). The Transmission Provider shall 
use Part II of the Tariff to make its Third-Party Sales. The 
Transmission Provider shall account for such use at the applicable 
Tariff rates, pursuant to Section 8.

26  Stranded Cost Recovery

    The Transmission Provider may seek to recover stranded costs 
from the Transmission Customer pursuant to this Tariff in accordance 
with the terms, conditions and procedures set forth in FERC Order 
No. 888. However, the Transmission Provider must separately file any 
specific proposed stranded cost charge under Section 205 of the 
Federal Power Act.

27  Compensation for New Facilities and Redispatch Costs

    Whenever a System Impact Study performed by the Transmission 
Provider in connection with the provision of Firm Point-To-Point 
Transmission Service identifies the need for new facilities, the 
Transmission Customer shall be responsible for such costs to the 
extent consistent with Commission policy. Whenever a System Impact 
Study performed by the Transmission Provider identifies capacity 
constraints that may be relieved more economically by redispatching 
the Transmission Provider's resources than by building new 
facilities or upgrading existing facilities to eliminate such 
constraints, the Transmission Customer shall be responsible for the 
redispatch costs to the extent consistent with Commission policy.

III. Network Integration Transmission Service

Preamble

    The Transmission Provider will provide Network Integration 
Transmission Service pursuant to the applicable terms and conditions 
contained in the Tariff and Service Agreement. Network Integration 
Transmission Service allows the Network Customer to integrate, 
economically dispatch and regulate its current and planned Network 
Resources to serve its Network Load in a manner comparable to that 
in which the Transmission Provider utilizes its Transmission System 
to serve its Native Load Customers. Network Integration Transmission 
Service also may be used by the Network Customer to deliver economy 
energy purchases to its Network Load from non-designated resources 
on an as-available basis without additional charge. Transmission 
service for sales to non-designated loads will be provided pursuant 
to the applicable terms and conditions of Part II of the Tariff.

[[Page 21718]]

28  Nature of Network Integration Transmission Service

    28.1  Scope of Service: Network Integration Transmission Service 
is a transmission service that allows Network Customers to 
efficiently and economically utilize their Network Resources (as 
well as other non-designated generation resources) to serve their 
Network Load located in the Transmission Provider's Control Area and 
any additional load that may be designated pursuant to Section 31.3 
of the Tariff. The Network Customer taking Network Integration 
Transmission Service must obtain or provide Ancillary Services 
pursuant to Section 3.
    28.2  Transmission Provider Responsibilities: The Transmission 
Provider will plan, construct, operate and maintain its Transmission 
System in accordance with Good Utility Practice in order to provide 
the Network Customer with Network Integration Transmission Service 
over the Transmission Provider's Transmission System. The 
Transmission Provider, on behalf of its Native Load Customers, shall 
be required to designate resources and loads in the same manner as 
any Network Customer under Part III of this Tariff. This information 
must be consistent with the information used by the Transmission 
Provider to calculate available transmission capability. The 
Transmission Provider shall include the Network Customer's Network 
Load in its Transmission System planning and shall, consistent with 
Good Utility Practice, endeavor to construct and place into service 
sufficient transmission capacity to deliver the Network Customer's 
Network Resources to serve its Network Load on a basis comparable to 
the Transmission Provider's delivery of its own generating and 
purchased resources to its Native Load Customers.
    28.3  Network Integration Transmission Service: The Transmission 
Provider will provide firm transmission service over its 
Transmission System to the Network Customer for the delivery of 
capacity and energy from its designated Network Resources to service 
its Network Loads on a basis that is comparable to the Transmission 
Provider's use of the Transmission System to reliably serve its 
Native Load Customers.
    28.4  Secondary Service: The Network Customer may use the 
Transmission Provider's Transmission System to deliver energy to its 
Network Loads from resources that have not been designated as 
Network Resources. Such energy shall be transmitted, on an as-
available basis, at no additional charge. Deliveries from resources 
other than Network Resources will have a higher priority than any 
Non-Firm Point-To-Point Transmission Service under Part II of the 
Tariff.
    28.5  Real Power Losses: Real Power Losses are associated with 
all transmission service. The Transmission Provider is not obligated 
to provide Real Power Losses. The Network Customer is responsible 
for replacing losses associated with all transmission service as 
calculated by the Transmission Provider. The applicable Real Power 
Loss factors are as follows: [To be completed by the Transmission 
Provider].
    28.6  Restrictions on Use of Service: The Network Customer shall 
not use Network Integration Transmission Service for (i) sales of 
capacity and energy to non-designated loads, or (ii) direct or 
indirect provision of transmission service by the Network Customer 
to third parties. All Network Customers taking Network Integration 
Transmission Service shall use Point-To-Point Transmission Service 
under Part II of the Tariff for any Third-Party Sale which requires 
use of the Transmission Provider's Transmission System.

29  Initiating Service

    29.1  Condition Precedent for Receiving Service: Subject to the 
terms and conditions of Part III of the Tariff, the Transmission 
Provider will provide Network Integration Transmission Service to 
any Eligible Customer, provided that (i) the Eligible Customer 
completes an Application for service as provided under Part III of 
the Tariff, (ii) the Eligible Customer and the Transmission Provider 
complete the technical arrangements set forth in Sections 29.3 and 
29.4, (iii) the Eligible Customer executes a Service Agreement 
pursuant to Attachment F for service under Part III of the Tariff or 
requests in writing that the Transmission Provider file a proposed 
unexecuted Service Agreement with the Commission, and (iv) the 
Eligible Customer executes a Network Operating Agreement with the 
Transmission Provider pursuant to Attachment G.
    29.2  Application Procedures: An Eligible Customer requesting 
service under Part III of the Tariff must submit an Application, 
with a deposit approximating the charge for one month of service, to 
the Transmission Provider as far as possible in advance of the month 
in which service is to commence. Unless subject to the procedures in 
Section 2, Completed Applications for Network Integration 
Transmission Service will be assigned a priority according to the 
date and time the Application is received, with the earliest 
Application receiving the highest priority. Applications should be 
submitted by entering the information listed below on the 
Transmission Provider's OASIS. Prior to implementation of the 
Transmission Provider's OASIS, a Completed Application may be 
submitted by (i) transmitting the required information to the 
Transmission Provider by telefax, or (ii) providing the information 
by telephone over the Transmission Provider's time recorded 
telephone line. Each of these methods will provide a time-stamped 
record for establishing the service priority of the Application. A 
Completed Application shall provide all of the information included 
in 18 CFR Sec. 2.20 including but not limited to the following:
    (i) The identity, address, telephone number and facsimile number 
of the party requesting service;
    (ii) A statement that the party requesting service is, or will 
be upon commencement of service, an Eligible Customer under the 
Tariff;
    (iii) A description of the Network Load at each delivery point. 
This description should separately identify and provide the Eligible 
Customer's best estimate of the total loads to be served at each 
transmission voltage level, and the loads to be served from each 
Transmission Provider substation at the same transmission voltage 
level. The description should include a ten (10) year forecast of 
summer and winter load and resource requirements beginning with the 
first year after the service is scheduled to commence;
    (iv) The amount and location of any interruptible loads included 
in the Network Load. This shall include the summer and winter 
capacity requirements for each interruptible load (had such load not 
been interruptible), that portion of the load subject to 
interruption, the conditions under which an interruption can be 
implemented and any limitations on the amount and frequency of 
interruptions. An Eligible Customer should identify the amount of 
interruptible customer load (if any) included in the 10 year load 
forecast provided in response to (iii) above;
    (v) A description of Network Resources (current and 10-year 
projection), which shall include, for each Network Resource:

--Unit size and amount of capacity from that unit to be designated 
as Network Resource
--VAR capability (both leading and lagging) of all generators
--Operating restrictions
--Any periods of restricted operations throughout the year
--Maintenance schedules
--Minimum loading level of unit
--Normal operating level of unit
--Any must-run unit designations required for system reliability or 
contract reasons
--Approximate variable generating cost ($/MWH) for redispatch 
computations
--Arrangements governing sale and delivery of power to third parties 
from generating facilities located in the Transmission Provider 
Control Area, where only a portion of unit output is designated as a 
Network Resource
--Description of purchased power designated as a Network Resource 
including source of supply, Control Area location, transmission 
arrangements and delivery point(s) to the Transmission Provider's 
Transmission System;

    (vi) Description of Eligible Customer's transmission system:

--Load flow and stability data, such as real and reactive parts of 
the load, lines, transformers, reactive devices and load type, 
including normal and emergency ratings of all transmission equipment 
in a load flow format compatible with that used by the Transmission 
Provider
--Operating restrictions needed for reliability
--Operating guides employed by system operators
--Contractual restrictions or committed uses of the Eligible 
Customer's transmission system, other than the Eligible Customer's 
Network Loads and Resources
--Location of Network Resources described in subsection (v) above
--10 year projection of system expansions or upgrades
--Transmission System maps that include any proposed expansions or 
upgrades
--Thermal ratings of Eligible Customer's Control Area ties with 
other Control Areas; and

    (vii) Service Commencement Date and the term of the requested 
Network Integration

[[Page 21719]]

Transmission Service. The minimum term for Network Integration 
Transmission Service is one year.
    Unless the Parties agree to a different time frame, the 
Transmission Provider must acknowledge the request within ten (10) 
days of receipt. The acknowledgement must include a date by which a 
response, including a Service Agreement, will be sent to the 
Eligible Customer. If an Application fails to meet the requirements 
of this section, the Transmission Provider shall notify the Eligible 
Customer requesting service within fifteen (15) days of receipt and 
specify the reasons for such failure. Wherever possible, the 
Transmission Provider will attempt to remedy deficiencies in the 
Application through informal communications with the Eligible 
Customer. If such efforts are unsuccessful, the Transmission 
Provider shall return the Application without prejudice to the 
Eligible Customer filing a new or revised Application that fully 
complies with the requirements of this section. The Eligible 
Customer will be assigned a new priority consistent with the date of 
the new or revised Application. The Transmission Provider shall 
treat this information consistent with the standards of conduct 
contained in Part 37 of the Commission's regulations.
    29.3  Technical Arrangements to be Completed Prior to 
Commencement of Service: Network Integration Transmission Service 
shall not commence until the Transmission Provider and the Network 
Customer, or a third party, have completed installation of all 
equipment specified under the Network Operating Agreement consistent 
with Good Utility Practice and any additional requirements 
reasonably and consistently imposed to ensure the reliable operation 
of the Transmission System. The Transmission Provider shall exercise 
reasonable efforts, in coordination with the Network Customer, to 
complete such arrangements as soon as practicable taking into 
consideration the Service Commencement Date.
    29.4  Network Customer Facilities: The provision of Network 
Integration Transmission Service shall be conditioned upon the 
Network Customer's constructing, maintaining and operating the 
facilities on its side of each delivery point or interconnection 
necessary to reliably deliver capacity and energy from the 
Transmission Provider's Transmission System to the Network Customer. 
The Network Customer shall be solely responsible for constructing or 
installing all facilities on the Network Customer's side of each 
such delivery point or interconnection.
    29.5  Filing of Service Agreement: The Transmission Provider 
will file Service Agreements with the Commission in compliance with 
applicable Commission regulations.

Network Resources

    30.1  Designation of Network Resources: Network Resources shall 
include all generation owned or purchased by the Network Customer 
designated to serve Network Load under the Tariff. Network Resources 
may not include resources, or any portion thereof, that are 
committed for sale to non-designated third party load or otherwise 
cannot be called upon to meet the Network Customer's Network Load on 
a non-interruptible basis. Any owned or purchased resources that 
were serving the Network Customer's loads under firm agreements 
entered into on or before the Service Commencement Date shall 
initially be designated as Network Resources until the Network 
Customer terminates the designation of such resources.
    30.2  Designation of New Network Resources: The Network Customer 
may designate a new Network Resource by providing the Transmission 
Provider with as much advance notice as practicable. A designation 
of a new Network Resource must be made by a request for modification 
of service pursuant to an Application under Section 29.
    30.3  Termination of Network Resources: The Network Customer may 
terminate the designation of all or part of a generating resource as 
a Network Resource at any time but should provide notification to 
the Transmission Provider as soon as reasonably practicable.
    30.4  Operation of Network Resources: The Network Customer shall 
not operate its designated Network Resources located in the Network 
Customer's or Transmission Provider's Control Area such that the 
output of those facilities exceeds its designated Network Load plus 
losses.
    30.5  Network Customer Redispatch Obligation: As a condition to 
receiving Network Integration Transmission Service, the Network 
Customer agrees to redispatch its Network Resources as requested by 
the Transmission Provider pursuant to Section 33.2. To the extent 
practical, the redispatch of resources pursuant to this section 
shall be on a least cost, non-discriminatory basis between all 
Network Customers, and the Transmission Provider.
    30.6  Transmission Arrangements for Network Resources Not 
Physically Interconnected With The Transmission Provider: The 
Network Customer shall be responsible for any arrangements necessary 
to deliver capacity and energy from a Network Resource not 
physically interconnected with the Transmission Provider's 
Transmission System. The Transmission Provider will undertake 
reasonable efforts to assist the Network Customer in obtaining such 
arrangements, including without limitation, providing any 
information or data required by such other entity pursuant to Good 
Utility Practice.
    30.7  Limitation on Designation of Network Resources: The 
Network Customer must demonstrate that it owns or has committed to 
purchase generation pursuant to an executed contract in order to 
designate a generating resource as a Network Resource. 
Alternatively, the Network Customer may establish that execution of 
a contract is contingent upon the availability of transmission 
service under Part III of the Tariff.
    30.8  Use of Interface Capacity by the Network Customer: There 
is no limitation upon a Network Customer's use of the Transmission 
Provider's Transmission System at any particular interface to 
integrate the Network Customer's Network Resources (or substitute 
economy purchases) with its Network Loads. However, a Network 
Customer's use of the Transmission Provider's total interface 
capacity with other transmission systems may not exceed the Network 
Customer's Load Ratio Share.
    30.9  Network Customer Owned Transmission Facilities: The 
Network Customer that owns existing transmission facilities that are 
integrated with the Transmission Provider's Transmission System may 
be eligible to receive consideration either through a billing credit 
or some other mechanism. In order to receive such consideration the 
Network Customer must demonstrate that its transmission facilities 
are integrated into the planning and operations of the Transmission 
Provider to serve all of its power and transmission customers. For 
facilities constructed by the Network Customer subsequent to the 
Service Commencement Date under Part III of the Tariff, the Network 
Customer shall receive credit where such facilities are jointly 
planned and installed in coordination with the Transmission 
Provider. Calculation of the credit shall be addressed in either the 
Network Customer's Service Agreement or any other agreement between 
the Parties.

31  Designation of Network Load

    31.1  Network Load: The Network Customer must designate the 
individual Network Loads on whose behalf the Transmission Provider 
will provide Network Integration Transmission Service. The Network 
Loads shall be specified in the Service Agreement.
    31.2  New Network Loads Connected With the Transmission 
Provider: The Network Customer shall provide the Transmission 
Provider with as much advance notice as reasonably practicable of 
the designation of new Network Load that will be added to its 
Transmission System. A designation of new Network Load must be made 
through a modification of service pursuant to a new Application. The 
Transmission Provider will use due diligence to install any 
transmission facilities required to interconnect a new Network Load 
designated by the Network Customer. The costs of new facilities 
required to interconnect a new Network Load shall be determined in 
accordance with the procedures provided in Section 32.4 and shall be 
charged to the Network Customer in accordance with Commission 
policies.
    31.3  Network Load Not Physically Interconnected with the 
Transmission Provider: This section applies to both initial 
designation pursuant to Section 31.1 and the subsequent addition of 
new Network Load not physically interconnected with the Transmission 
Provider. To the extent that the Network Customer desires to obtain 
transmission service for a load outside the Transmission Provider's 
Transmission System, the Network Customer shall have the option of 
(1) electing to include the entire load as Network Load for all 
purposes under Part III of the Tariff and designating Network 
Resources in connection with such additional Network Load, or (2) 
excluding that entire load from its Network Load and purchasing 
Point-To-Point Transmission

[[Page 21720]]

Service under Part II of the Tariff. To the extent that the Network 
Customer gives notice of its intent to add a new Network Load as 
part of its Network Load pursuant to this section the request must 
be made through a modification of service pursuant to a new 
Application.
    31.4  New Interconnection Points: To the extent the Network 
Customer desires to add a new Delivery Point or interconnection 
point between the Transmission Provider's Transmission System and a 
Network Load, the Network Customer shall provide the Transmission 
Provider with as much advance notice as reasonably practicable.
    31.5  Changes in Service Requests: Under no circumstances shall 
the Network Customer's decision to cancel or delay a requested 
change in Network Integration Transmission Service (e.g. the 
addition of a new Network Resource or designation of a new Network 
Load) in any way relieve the Network Customer of its obligation to 
pay the costs of transmission facilities constructed by the 
Transmission Provider and charged to the Network Customer as 
reflected in the Service Agreement. However, the Transmission 
Provider must treat any requested change in Network Integration 
Transmission Service in a non-discriminatory manner.
    31.6  Annual Load and Resource Information Updates: The Network 
Customer shall provide the Transmission Provider with annual updates 
of Network Load and Network Resource forecasts consistent with those 
included in its Application for Network Integration Transmission 
Service under Part III of the Tariff. The Network Customer also 
shall provide the Transmission Provider with timely written notice 
of material changes in any other information provided in its 
Application relating to the Network Customer's Network Load, Network 
Resources, its transmission system or other aspects of its 
facilities or operations affecting the Transmission Provider's 
ability to provide reliable service.

32  Additional Study Procedures for Network Integration 
Transmission Service Requests

    32.1  Notice of Need for System Impact Study: After receiving a 
request for service, the Transmission Provider shall determine on a 
non-discriminatory basis whether a System Impact Study is needed. A 
description of the Transmission Provider's methodology for 
completing a System Impact Study is provided in Attachment D. If the 
Transmission Provider determines that a System Impact Study is 
necessary to accommodate the requested service, it shall so inform 
the Eligible Customer, as soon as practicable. In such cases, the 
Transmission Provider shall within thirty (30) days of receipt of a 
Completed Application, tender a System Impact Study Agreement 
pursuant to which the Eligible Customer shall agree to reimburse the 
Transmission Provider for performing the required System Impact 
Study. For a service request to remain a Completed Application, the 
Eligible Customer shall execute the System Impact Study Agreement 
and return it to the Transmission Provider within fifteen (15) days. 
If the Eligible Customer elects not to execute the System Impact 
Study Agreement, its Application shall be deemed withdrawn and its 
deposit shall be returned with interest.
    32.2  System Impact Study Agreement and Cost Reimbursement:
    (i) The System Impact Study Agreement will clearly specify the 
maximum charge, based on the Transmission Provider's estimate of the 
actual cost, and time for completion of the System Impact Study. The 
charge shall not exceed the actual cost of the study. In performing 
the System Impact Study, the Transmission Provider shall rely, to 
the extent reasonably practicable, on existing transmission planning 
studies. The Eligible Customer will not be assessed a charge for 
such existing studies; however, the Eligible Customer will be 
responsible for charges associated with any modifications to 
existing planning studies that are reasonably necessary to evaluate 
the impact of the Eligible Customer's request for service on the 
Transmission System.
    (ii) If in response to multiple Eligible Customers requesting 
service in relation to the same competitive solicitation, a single 
System Impact Study is sufficient for the Transmission Provider to 
accommodate the service requests, the costs of that study shall be 
pro-rated among the Eligible Customers.
    (iii) For System Impact Studies that the Transmission Provider 
conducts on its own behalf, the Transmission Provider shall record 
the cost of the System Impact Studies pursuant to Section 8.
    32.3  System Impact Study Procedures: Upon receipt of an 
executed System Impact Study Agreement, the Transmission Provider 
will use due diligence to complete the required System Impact Study 
within a sixty (60) day period. The System Impact Study shall 
identify any system constraints and redispatch options, additional 
Direct Assignment Facilities or Network Upgrades required to provide 
the requested service. In the event that the Transmission Provider 
is unable to complete the required System Impact Study within such 
time period, it shall so notify the Eligible Customer and provide an 
estimated completion date along with an explanation of the reasons 
why additional time is required to complete the required studies. A 
copy of the completed System Impact Study and related work papers 
shall be made available to the Eligible Customer. The Transmission 
Provider will use the same due diligence in completing the System 
Impact Study for an Eligible Customer as it uses when completing 
studies for itself. The Transmission Provider shall notify the 
Eligible Customer immediately upon completion of the System Impact 
Study if the Transmission System will be adequate to accommodate all 
or part of a request for service or that no costs are likely to be 
incurred for new transmission facilities or upgrades. In order for a 
request to remain a Completed Application, within fifteen (15) days 
of completion of the System Impact Study the Eligible Customer must 
execute a Service Agreement or request the filing of an unexecuted 
Service Agreement, or the Application shall be deemed terminated and 
withdrawn.
    32.4  Facilities Study Procedures: If a System Impact Study 
indicates that additions or upgrades to the Transmission System are 
needed to supply the Eligible Customer's service request, the 
Transmission Provider, within thirty (30) days of the completion of 
the System Impact Study, shall tender to the Eligible Customer a 
Facilities Study Agreement pursuant to which the Eligible Customer 
shall agree to reimburse the Transmission Provider for performing 
the required Facilities Study. For a service request to remain a 
Completed Application, the Eligible Customer shall execute the 
Facilities Study Agreement and return it to the Transmission 
Provider within fifteen (15) days. If the Eligible Customer elects 
not to execute the Facilities Study Agreement, its Application shall 
be deemed withdrawn and its deposit shall be returned with interest. 
Upon receipt of an executed Facilities Study Agreement, the 
Transmission Provider will use due diligence to complete the 
required Facilities Study within a sixty (60) day period. If the 
Transmission Provider is unable to complete the Facilities Study in 
the allotted time period, the Transmission Provider shall notify the 
Eligible Customer and provide an estimate of the time needed to 
reach a final determination along with an explanation of the reasons 
that additional time is required to complete the study. When 
completed, the Facilities Study will include a good faith estimate 
of (i) the cost of Direct Assignment Facilities to be charged to the 
Eligible Customer, (ii) the Eligible Customer's appropriate share of 
the cost of any required Network Upgrades, and (iii) the time 
required to complete such construction and initiate the requested 
service. The Eligible Customer shall provide the Transmission 
Provider with a letter of credit or other reasonable form of 
security acceptable to the Transmission Provider equivalent to the 
costs of new facilities or upgrades consistent with commercial 
practices as established by the Uniform Commercial Code. The 
Eligible Customer shall have thirty (30) days to execute a Service 
Agreement or request the filing of an unexecuted Service Agreement 
and provide the required letter of credit or other form of security 
or the request no longer will be a Completed Application and shall 
be deemed terminated and withdrawn.

33  Load Shedding and Curtailments

    33.1  Procedures: Prior to the Service Commencement Date, the 
Transmission Provider and the Network Customer shall establish Load 
Shedding and Curtailment procedures pursuant to the Network 
Operating Agreement with the objective of responding to 
contingencies on the Transmission System. The Parties will implement 
such programs during any period when the Transmission Provider 
determines that a system contingency exists and such procedures are 
necessary to alleviate such contingency. The Transmission Provider 
will notify all affected Network Customers in a timely manner of any 
scheduled Curtailment.
    33.2  Transmission Constraints: During any period when the 
Transmission Provider determines that a transmission constraint 
exists on the Transmission System, and such constraint may impair 
the reliability of the Transmission Provider's system, the 
Transmission Provider will take whatever

[[Page 21721]]

actions, consistent with Good Utility Practice, that are reasonably 
necessary to maintain the reliability of the Transmission Provider's 
system. To the extent the Transmission Provider determines that the 
reliability of the Transmission System can be maintained by 
redispatching resources, the Transmission Provider will initiate 
procedures pursuant to the Network Operating Agreement to redispatch 
all Network Resources and the Transmission Provider's own resources 
on a least-cost basis without regard to the ownership of such 
resources. Any redispatch under this section may not unduly 
discriminate between the Transmission Provider's use of the 
Transmission System on behalf of its Native Load Customers and any 
Network Customer's use of the Transmission System to serve its 
designated Network Load.
    33.3  Cost Responsibility for Relieving Transmission 
Constraints: Whenever the Transmission Provider implements least-
cost redispatch procedures in response to a transmission constraint, 
the Transmission Provider and Network Customers will each bear a 
proportionate share of the total redispatch cost based on their 
respective Load Ratio Shares.
    33.4  Curtailments of Scheduled Deliveries: If a transmission 
constraint on the Transmission Provider's Transmission System cannot 
be relieved through the implementation of least-cost redispatch 
procedures and the Transmission Provider determines that it is 
necessary to Curtail scheduled deliveries, the Parties shall Curtail 
such schedules in accordance with the Network Operating Agreement.
    33.5  Allocation of Curtailments: The Transmission Provider 
shall, on a non-discriminatory basis, Curtail the transaction(s) 
that effectively relieve the constraint. However, to the extent 
practicable and consistent with Good Utility Practice, any 
Curtailment will be shared by the Transmission Provider and Network 
Customer in proportion to their respective Load Ratio Shares. The 
Transmission Provider shall not direct the Network Customer to 
Curtail schedules to an extent greater than the Transmission 
Provider would Curtail the Transmission Provider's schedules under 
similar circumstances.
    33.6  Load Shedding: To the extent that a system contingency 
exists on the Transmission Provider's Transmission System and the 
Transmission Provider determines that it is necessary for the 
Transmission Provider and the Network Customer to shed load, the 
Parties shall shed load in accordance with previously established 
procedures under the Network Operating Agreement.
    33.7  System Reliability: Notwithstanding any other provisions 
of this Tariff, the Transmission Provider reserves the right, 
consistent with Good Utility Practice and on a not unduly 
discriminatory basis, to Curtail Network Integration Transmission 
Service without liability on the Transmission Provider's part for 
the purpose of making necessary adjustments to, changes in, or 
repairs on its lines, substations and facilities, and in cases where 
the continuance of Network Integration Transmission Service would 
endanger persons or property. In the event of any adverse 
condition(s) or disturbance(s) on the Transmission Provider's 
Transmission System or on any other system(s) directly or indirectly 
interconnected with the Transmission Provider's Transmission System, 
the Transmission Provider, consistent with Good Utility Practice, 
also may Curtail Network Integration Transmission Service in order 
to (i) limit the extent or damage of the adverse condition(s) or 
disturbance(s), (ii) prevent damage to generating or transmission 
facilities, or (iii) expedite restoration of service. The 
Transmission Provider will give the Network Customer as much advance 
notice as is practicable in the event of such Curtailment. Any 
Curtailment of Network Integration Transmission Service will be not 
unduly discriminatory relative to the Transmission Provider's use of 
the Transmission System on behalf of its Native Load Customers. The 
Transmission Provider shall specify the rate treatment and all 
related terms and conditions applicable in the event that the 
Network Customer fails to respond to established Load Shedding and 
Curtailment procedures.

34  Rates and Charges

    The Network Customer shall pay the Transmission Provider for any 
Direct Assignment Facilities, Ancillary Services, and applicable 
study costs, consistent with Commission policy, along with the 
following:
    34.1  Monthly Demand Charge: The Network Customer shall pay a 
monthly Demand Charge, which shall be determined by multiplying its 
Load Ratio Share times one twelfth (\1/12\) of the Transmission 
Provider's Annual Transmission Revenue Requirement specified in 
Schedule H.
    34.2  Determination of Network Customer's Monthly Network Load: 
The Network Customer's monthly Network Load is its hourly load 
(including its designated Network Load not physically interconnected 
with the Transmission Provider under Section 31.3) coincident with 
the Transmission Provider's Monthly Transmission System Peak.
    34.3  Determination of Transmission Provider's Monthly 
Transmission System Load: The Transmission Provider's monthly 
Transmission System load is the Transmission Provider's Monthly 
Transmission System Peak minus the coincident peak usage of all Firm 
Point-To-Point Transmission Service customers pursuant to Part II of 
this Tariff plus the Reserved Capacity of all Firm Point-To-Point 
Transmission Service customers.
    34.4  Redispatch Charge: The Network Customer shall pay a Load 
Ratio Share of any redispatch costs allocated between the Network 
Customer and the Transmission Provider pursuant to Section 33. To 
the extent that the Transmission Provider incurs an obligation to 
the Network Customer for redispatch costs in accordance with Section 
33, such amounts shall be credited against the Network Customer's 
bill for the applicable month.
    34.5  Stranded Cost Recovery: The Transmission Provider may seek 
to recover stranded costs from the Network Customer pursuant to this 
Tariff in accordance with the terms, conditions and procedures set 
forth in FERC Order No. 888. However, the Transmission Provider must 
separately file any proposal to recover stranded costs under Section 
205 of the Federal Power Act.

35  Operating Arrangements

    35.1  Operation under The Network Operating Agreement: The 
Network Customer shall plan, construct, operate and maintain its 
facilities in accordance with Good Utility Practice and in 
conformance with the Network Operating Agreement.
    35.2  Network Operating Agreement: The terms and conditions 
under which the Network Customer shall operate its facilities and 
the technical and operational matters associated with the 
implementation of Part III of the Tariff shall be specified in the 
Network Operating Agreement. The Network Operating Agreement shall 
provide for the Parties to (i) operate and maintain equipment 
necessary for integrating the Network Customer within the 
Transmission Provider's Transmission System (including, but not 
limited to, remote terminal units, metering, communications 
equipment and relaying equipment), (ii) transfer data between the 
Transmission Provider and the Network Customer (including, but not 
limited to, heat rates and operational characteristics of Network 
Resources, generation schedules for units outside the Transmission 
Provider's Transmission System, interchange schedules, unit outputs 
for redispatch required under Section 33, voltage schedules, loss 
factors and other real time data), (iii) use software programs 
required for data links and constraint dispatching, (iv) exchange 
data on forecasted loads and resources necessary for long-term 
planning, and (v) address any other technical and operational 
considerations required for implementation of Part III of the 
Tariff, including scheduling protocols. The Network Operating 
Agreement will recognize that the Network Customer shall either (i) 
operate as a Control Area under applicable guidelines of the North 
American Electric Reliability Council (NERC) and the [applicable 
regional reliability council], (ii) satisfy its Control Area 
requirements, including all necessary Ancillary Services, by 
contracting with the Transmission Provider, or (iii) satisfy its 
Control Area requirements, including all necessary Ancillary 
Services, by contracting with another entity, consistent with Good 
Utility Practice, which satisfies NERC and the [applicable regional 
reliability council] requirements. The Transmission Provider shall 
not unreasonably refuse to accept contractual arrangements with 
another entity for Ancillary Services. The Network Operating 
Agreement is included in Attachment G.
    35.3  Network Operating Committee: A Network Operating Committee 
(Committee) shall be established to coordinate operating criteria 
for the Parties' respective responsibilities under the Network 
Operating Agreement. Each Network Customer shall be entitled to have 
at least one representative on the Committee. The Committee shall 
meet from time to time as need requires, but no less than once each 
calendar year.

[[Page 21722]]

Schedule 1--Scheduling, System Control and Dispatch Service

    This service is required to schedule the movement of power 
through, out of, within, or into a Control Area. This service can be 
provided only by the operator of the Control Area in which the 
transmission facilities used for transmission service are located. 
Scheduling, System Control and Dispatch Service is to be provided 
directly by the Transmission Provider (if the Transmission Provider 
is the Control Area operator) or indirectly by the Transmission 
Provider making arrangements with the Control Area operator that 
performs this service for the Transmission Provider's Transmission 
System. The Transmission Customer must purchase this service from 
the Transmission Provider or the Control Area operator. The charges 
for Scheduling, System Control and Dispatch Service are to be based 
on the rates set forth below. To the extent the Control Area 
operator performs this service for the Transmission Provider, 
charges to the Transmission Customer are to reflect only a pass-
through of the costs charged to the Transmission Provider by that 
Control Area operator.

Schedule 2--Reactive Supply and Voltage Control from Generation Sources 
Service

    In order to maintain transmission voltages on the Transmission 
Provider's transmission facilities within acceptable limits, 
generation facilities (in the Control Area where the Transmission 
Provider's transmission facilities are located) are operated to 
produce (or absorb) reactive power. Thus, Reactive Supply and 
Voltage Control from Generation Sources Service must be provided for 
each transaction on the Transmission Provider's transmission 
facilities. The amount of Reactive Supply and Voltage Control from 
Generation Sources Service that must be supplied with respect to the 
Transmission Customer's transaction will be determined based on the 
reactive power support necessary to maintain transmission voltages 
within limits that are generally accepted in the region and 
consistently adhered to by the Transmission Provider.
    Reactive Supply and Voltage Control from Generation Sources 
Service is to be provided directly by the Transmission Provider (if 
the Transmission Provider is the Control Area operator) or 
indirectly by the Transmission Provider making arrangements with the 
Control Area operator that performs this service for the 
Transmission Provider's Transmission System. The Transmission 
Customer must purchase this service from the Transmission Provider 
or the Control Area operator. The charges for such service will be 
based on the rates set forth below. To the extent the Control Area 
operator performs this service for the Transmission Provider, 
charges to the Transmission Customer are to reflect only a pass-
through of the costs charged to the Transmission Provider by the 
Control Area operator.

Schedule 3--Regulation and Frequency Response Service

    Regulation and Frequency Response Service is necessary to 
provide for the continuous balancing of resources (generation and 
interchange) with load and for maintaining scheduled Interconnection 
frequency at sixty cycles per second (60 Hz). Regulation and 
Frequency Response Service is accomplished by committing on-line 
generation whose output is raised or lowered (predominantly through 
the use of automatic generating control equipment) as necessary to 
follow the moment-by-moment changes in load. The obligation to 
maintain this balance between resources and load lies with the 
Transmission Provider (or the Control Area operator that performs 
this function for the Transmission Provider). The Transmission 
Provider must offer this service when the transmission service is 
used to serve load within its Control Area. The Transmission 
Customer must either purchase this service from the Transmission 
Provider or make alternative comparable arrangements to satisfy its 
Regulation and Frequency Response Service obligation. The amount of 
and charges for Regulation and Frequency Response Service are set 
forth below. To the extent the Control Area operator performs this 
service for the Transmission Provider, charges to the Transmission 
Customer are to reflect only a pass-through of the costs charged to 
the Transmission Provider by that Control Area operator.

Schedule 4--Energy Imbalance Service

    Energy Imbalance Service is provided when a difference occurs 
between the scheduled and the actual delivery of energy to a load 
located within a Control Area over a single hour. The Transmission 
Provider must offer this service when the transmission service is 
used to serve load within its Control Area. The Transmission 
Customer must either purchase this service from the Transmission 
Provider or make alternative comparable arrangements to satisfy its 
Energy Imbalance Service obligation. To the extent the Control Area 
operator performs this service for the Transmission Provider, 
charges to the Transmission Customer are to reflect only a pass-
through of the costs charged to the Transmission Provider by that 
Control Area operator.
    The Transmission Provider shall establish a deviation band of +/
- 1.5 percent (with a minimum of 1 MW) of the scheduled transaction 
to be applied hourly to any energy imbalance that occurs as a result 
of the Transmission Customer's scheduled transaction(s). Parties 
should attempt to eliminate energy imbalances within the limits of 
the deviation band within thirty (30) days or within such other 
reasonable period of time as is generally accepted in the region and 
consistently adhered to by the Transmission Provider. If an energy 
imbalance is not corrected within thirty (30) days or a reasonable 
period of time that is generally accepted in the region and 
consistently adhered to by the Transmission Provider, the 
Transmission Customer will compensate the Transmission Provider for 
such service. Energy imbalances outside the deviation band will be 
subject to charges to be specified by the Transmission Provider. The 
charges for Energy Imbalance Service are set forth below.

Schedule 5--Operating Reserve--Spinning Reserve Service

    Spinning Reserve Service is needed to serve load immediately in 
the event of a system contingency. Spinning Reserve Service may be 
provided by generating units that are on-line and loaded at less 
than maximum output. The Transmission Provider must offer this 
service when the transmission service is used to serve load within 
its Control Area. The Transmission Customer must either purchase 
this service from the Transmission Provider or make alternative 
comparable arrangements to satisfy its Spinning Reserve Service 
obligation. The amount of and charges for Spinning Reserve Service 
are set forth below. To the extent the Control Area operator 
performs this service for the Transmission Provider, charges to the 
Transmission Customer are to reflect only a pass-through of the 
costs charged to the Transmission Provider by that Control Area 
operator.

Schedule 6--Operating Reserve--Supplemental Reserve Service

    Supplemental Reserve Service is needed to serve load in the 
event of a system contingency; however, it is not available 
immediately to serve load but rather within a short period of time. 
Supplemental Reserve Service may be provided by generating units 
that are on-line but unloaded, by quick-start generation or by 
interruptible load. The Transmission Provider must offer this 
service when the transmission service is used to serve load within 
its Control Area. The Transmission Customer must either purchase 
this service from the Transmission Provider or make alternative 
comparable arrangements to satisfy its Supplemental Reserve Service 
obligation. The amount of and charges for Supplemental Reserve 
Service are set forth below. To the extent the Control Area operator 
performs this service for the Transmission Provider, charges to the 
Transmission Customer are to reflect only a pass-through of the 
costs charged to the Transmission Provider by that Control Area 
operator.

Schedule 7--Long-Term Firm and Short-Term Firm Point-To-Point 
Transmission Service

    The Transmission Customer shall compensate the Transmission 
Provider each month for Reserved Capacity at the sum of the 
applicable charges set forth below:
    (1) Yearly delivery: one-twelfth of the demand charge of 
$________/KW of Reserved Capacity per year.
    (2) Monthly delivery: $________/KW of Reserved Capacity per 
month.
    (3) Weekly delivery: $________/KW of Reserved Capacity per week.
    (4) Daily delivery: $________/KW of Reserved Capacity per day.
    The total demand charge in any week, pursuant to a reservation 
for Daily delivery, shall not exceed the rate specified in section 
(3) above times the highest amount in kilowatts of Reserved Capacity 
in any day during such week.
    (5) Discounts: If the Transmission Provider offers an affiliate 
a rate discount or attributes a discounted transmission rate to its 
own

[[Page 21723]]

transactions, the Transmission Provider must offer at the same time 
the same discounted Firm Point-To-Point Transmission Service rate to 
all Eligible Customers on the same path and on all unconstrained 
transmission paths. Information regarding any firm transmission 
discounts must be posted on the OASIS pursuant to Part 37 of the 
Commission's regulations. In addition, discounts to non-affiliates 
must be offered in a not unduly discriminatory manner.

Schedule 8--Non-Firm Point-To-Point Transmission Service

    The Transmission Customer shall compensate the Transmission 
Provider for Non-Firm Point-To-Point Transmission Service up to the 
sum of the applicable charges set forth below:
    (1) Monthly delivery: $________/KW of Reserved Capacity per 
month.
    (2) Weekly delivery: $________/KW of Reserved Capacity per week.
    (3) Daily delivery: $________/KW of Reserved Capacity per day.
    The total demand charge in any week, pursuant to a reservation 
for Daily delivery, shall not exceed the rate specified in section 
(2) above times the highest amount in kilowatts of Reserved Capacity 
in any day during such week.
    (4) Hourly delivery: The basic charge shall be that agreed upon 
by the Parties at the time this service is reserved and in no event 
shall exceed $________/MWH. The total demand charge in any day, 
pursuant to a reservation for Hourly delivery, shall not exceed the 
rate specified in section (3) above times the highest amount in 
kilowatts of Reserved Capacity in any hour during such day. In 
addition, the total demand charge in any week, pursuant to a 
reservation for Hourly or Daily delivery, shall not exceed the rate 
specified in section (2) above times the highest amount in kilowatts 
of Reserved Capacity in any hour during such week.
    (5) Discounts: If the Transmission Provider offers an affiliate 
a rate discount or attributes a discounted transmission rate to its 
own transactions, the Transmission Provider must offer at the same 
time the same discounted Non-Firm Point-To-Point Transmission 
Service rate to all Eligible Customers on the same path and on all 
unconstrained transmission paths. Information regarding any non-firm 
transmission discounts must be posted on the OASIS pursuant to Part 
37 of the Commission's regulations. In addition, discounts to non-
affiliates must be offered in a not unduly discriminatory manner.

Attachment A--Form Of Service Agreement for Firm Point-To-Point 
Transmission Service

    1.0  This Service Agreement, dated as of ________________, is 
entered into, by and between ________________ (the Transmission 
Provider), and ________________ (``Transmission Customer'').
    2.0  The Transmission Customer has been determined by the 
Transmission Provider to have a Completed Application for Firm 
Point-To-Point Transmission Service under the Tariff.
    3.0  The Transmission Customer has provided to the Transmission 
Provider an Application deposit in the amount of $________, in 
accordance with the provisions of Section 17.3 of the Tariff.
    4.0  Service under this agreement shall commence on the later of 
(1) ________________, or (2) the date on which construction of any 
Direct Assignment Facilities and/or Network Upgrades are completed, 
or (3) such other date as it is permitted to become effective by the 
Commission. Service under this agreement shall terminate on 
________________.
    5.0  The Transmission Provider agrees to provide and the 
Transmission Customer agrees to take and pay for Firm Point-To-Point 
Transmission Service in accordance with the provisions of Part II of 
the Tariff and this Service Agreement.
    6.0  Any notice or request made to or by either Party regarding 
this Service Agreement shall be made to the representative of the 
other Party as indicated below.

Transmission Provider:
----------------------------------------------------------------------
----------------------------------------------------------------------
Transmission Customer:
----------------------------------------------------------------------
----------------------------------------------------------------------
    7.0  The Tariff is incorporated herein and made a part hereof.
    In Witness Whereof, the Parties have caused this Service 
Agreement to be executed by their respective authorized officials.

Transmission Provider:
By:--------------------------------------------------------------------
Name

----------------------------------------------------------------------
Title

----------------------------------------------------------------------
Date

----------------------------------------------------------------------
----------------------------------------------------------------------
Transmission Customer:
By:--------------------------------------------------------------------
Name

----------------------------------------------------------------------
Title

----------------------------------------------------------------------
Date
----------------------------------------------------------------------
----------------------------------------------------------------------

Specifications for Firm Point-To-Point Transmission Service

1.0  Term of Transaction:----------------------------------------------
Start Date:------------------------------------------------------------
Termination Date:------------------------------------------------------
2.0  Description of capacity and energy to be transmitted by 
Transmission Provider including the electric Control Area in which the 
transaction originates.------------------------------------------------
----------------------------------------------------------------------
3.0  Point(s) of Receipt:----------------------------------------------
Delivering Party:------------------------------------------------------
4.0  Point(s) of Delivery:---------------------------------------------
Receiving Party:-------------------------------------------------------
5.0  Maximum amount of capacity and energy to be transmitted-----------
(Reserved Capacity):---------------------------------------------------
6.0  Designation of party(ies) subject to reciprocal service 
obligation:------------------------------------------------------------
7.0  Name(s) of any Intervening Systems providing transmission service:
    8.0  Service under this Agreement may be subject to some 
combination of the charges detailed below. (The appropriate charges 
for individual transactions will be determined in accordance with 
the terms and conditions of the Tariff.)
8.1  Transmission Charge:----------------------------------------------
8.2  System Impact and/or Facilities Study Charge(s):------------------
8.3  Direct Assignment Facilities Charge:------------------------------
----------------------------------------------------------------------
8.4  Ancillary Services Charges:---------------------------------------

 Attachment B--Form Of Service Agreement For Non-Firm Point-To-Point 
Transmission Service

    1.0  This Service Agreement, dated as of ____________, is 
entered into, by and between ____________, (the Transmission 
Provider), and ____________, (Transmission Customer).
    2.0  The Transmission Customer has been determined by the 
Transmission Provider to be a Transmission Customer under Part II of 
the Tariff and has filed a Completed Application for Non-Firm Point-
To-Point Transmission Service in accordance with Section 18.2 of the 
Tariff.
    3.0  Service under this Agreement shall be provided by the 
Transmission Provider upon request by an authorized representative 
of the Transmission Customer.
    4.0  The Transmission Customer agrees to supply information the 
Transmission Provider deems reasonably necessary in accordance with 
Good Utility Practice in order for it to provide the requested 
service.
    5.0  The Transmission Provider agrees to provide and the 
Transmission Customer agrees to take and pay for Non-Firm Point-To-
Point Transmission Service in accordance with the provisions of Part 
II of the Tariff and this Service Agreement.
    6.0  Any notice or request made to or by either Party regarding 
this Service Agreement shall be made to the representative of the 
other Party as indicated below.

Transmission Provider:
----------------------------------------------------------------------

Transmission Customer:
----------------------------------------------------------------------
    7.0  The Tariff is incorporated herein and made a part hereof.
    In Witness Whereof, the Parties have caused this Service 
Agreement to be executed by their respective authorized officials.

Transmission Provider:
----------------------------------------------------------------------
By:--------------------------------------------------------------------
----------------------------------------------------------------------
----------------------------------------------------------------------
Name
----------------------------------------------------------------------
Title
----------------------------------------------------------------------
Date

Transmission Customer:
----------------------------------------------------------------------
By:--------------------------------------------------------------------
----------------------------------------------------------------------
----------------------------------------------------------------------
Name
----------------------------------------------------------------------
Title
----------------------------------------------------------------------
Date

[[Page 21724]]

Attachment C--Methodology To Assess Available Transmission Capability

    To be filed by the Transmission Provider.

Attachment D--Methodology for Completing a System Impact Study

    To be filed by the Transmission Provider.

Attachment E--Index Of Point-To-Point Transmission Service Customers

Customer---------------------------------------------------------------
Date of Service Agreement----------------------------------------------

Attachment F--Service Agreement for Network Integration Transmission 
Service

    To be filed by the Transmission Provider.

Attachment G--Network Operating Agreement

    To be filed by the Transmission Provider.

Attachment H--Annual Transmission Revenue Requirement for Network 
Integration Transmission Service

    1. The Annual Transmission Revenue Requirement for purposes of 
the Network Integration Transmission Service shall be ____________.
    2. The amount in (1) shall be effective until amended by the 
Transmission Provider or modified by the Commission.

Attachment I--Index of Network Integration Transmission Service 
Customers

Customer---------------------------------------------------------------
Date of Service Agreement----------------------------------------------

Appendix E--Group 1 Public Utilities

Alabama Power Company
Appalachian Power Company
Arkansas Power & Light Company
Atlantic City Electric Company
Baltimore Gas & Electric Company
Black Hills Power & Light Company
Cambridge Electric Light Company
Central Illinois Light Company
Central Power and Light Company
Central Vermont Public Service Corporation
Cheyenne Light, Fuel and Power Company
Cincinnatti Gas & Electric Company
Citizens Utilities Company
Columbus Southern Power Company
Commonwealth Edison Company
Commonwealth Electric Company
Connecticut Light & Power Company
Connecticut Valley Electric Company
Consumers Power Company
Dayton Power & Light Company
Delmarva Power & Light Company
Duke Power Company
Duquesne Light Company
Florida Power & Light Company
Florida Power Corporation
Georgia Power Company
Granite State Electric Company
Gulf Power Company
Gulf States Utilities Company
Holyoke Power & Electric Company
Holyoke Water Power Company
Idaho Power Company
IES Utilities, Inc.
Illinois Power Company
Indiana Michigan Power Company
Interstate Power Company
Jersey Central Power & Light Company
Kansas City Power & Light Company
Kansas Gas & Electric Company
Kentucky Power Company
Kentucky Utilities Company
Kingsport Power Company
Louisiana Power & Light Company
Louisville Gas & Electric Company
Maine Public Service Company
Massachusetts Electric Company
Metropolitan Edison Company
MidAmerican Energy Company
Midwest Energy, Inc.
Minnesota Power & Light Company
Mississippi Power Company
Mississippi Power & Light Company
Monongahela Power Company
Montana Power Company
Montaup Electric Company
Nantahala Power & Light Company
Narragansett Electric Company
Nevada Power Company
New England Power Company
New Orleans Public Service Inc.
Northern Indiana Public Service Company
Northern States Power Company( Wisconsin)
Northern States Power Company (Minnesota)
Ohio Power Company
Orange & Rockland Utilities, Inc.
Pacific Gas & Electric Company
PacifiCorp
PECO Energy Company
Pennsylvania Electric Company
Pennsylvania Power & Light Company
Pike County Light & Power Company
Portland General Electric Company
Potomac Edison Company
Potomac Electric Power Company
PSI Energy, Inc.
Public Service Company of Colorado
Public Service Company of New Mexico
Public Service Company of New Hampshire
Public Service Electric and Gas Company
Public Utility Company of Oklahoma
Puget Sound Power & Light Company
Rockland Electric Company
San Diego Gas & Electric Company
Savannah Electric and Power Company
South Carolina Electric & Gas Company
Southern California Edison Company
Southern Indiana Gas & Electric Company
Southwestern Electric Power Company
Southwestern Public Service Company
Tampa Electric Company
United Illiminating Company
UtiliCorp United, Inc.
Washington Water Power Company
West Penn Power Company
West Texas Utilities Company
Western Massachusetts Electric Company
Western Resources, Inc.
Wheeling Power Company
Wisconsin Electric Power Company
Wisconsin Power & Light Company
Wisconsin Public Service Corporation

    Note: Transmission tariffs have also been filed for some public 
utilities associated with pending merger applications. These 
individual utilities are not included in Group 1 and will be 
required to file tariffs on compliance with the Final Rule. They 
are: Centerior's filing for Cleveland Electric Illuminating Company 
and Toledo Edison Company; Interstate Energy Corporation's filing 
for South Beloit Water, Gas & Electric Company; Resources West's for 
Sierra Pacific Power Company; and the rate filing associated with 
the merger of Union Electric Company and Central Illinois Public 
Service Company.

Appendix F--Group 2 Public Utilities

Arizona Public Service Company
Bangor Hydro-Electric Company
Blackstone Valley Electric Company
Boston Edison Company
Carolina Power & Light Company
Central Hudson Gas & Electric Corporation
Central Illinois Public Service Company
Central Louisiana Electric Company, Inc.
Central Maine Power Company
Cleveland Electric Illuminating Company
Commonwealth Edison Company of Indiana
Concord Electric Company
Consolidated Edison Company of New York Inc.
Consolidated Water Power Company
Detroit Edison Company
Eastern Edison Company
Edison Sault Electric Company
El Paso Electric Company
Electric Energy Inc.
Empire District Electric Company
Exeter & Hampton Electric Company
Fitchburg Gas & Electric Light Company
Green Mountain Power Corporation
Indiana-Kentucky Electric Corporation
Indianapolis Power & Light Company
Kanawha Valley Power Company
Lockhart Power Company
Long Island Lighting Company
Long Sault, Inc.
Madison Gas & Electric Company
MDU Resources Group, Inc.
Mt. Carmel Public Utility Company
New England Electric Transmission Corporation
New England Hydro Transmission Electric Company
New England Hydro Transmission Corporation
New York State Electric & Gas Corporation
Newport Electric Corporation
Niagara Mohawk Power Corporation
Northwestern Public Service Company
Northwestern Wisconsin Electric Company
Ohio Edison Company
Ohio Valley Electic Corporation
Oklahoma Gas & Electric Company
Old Dominion Electric Cooperative
Otter Tail Power Company
Pennsylvania Power Company
Peoples Electric Cooperative
Rayburn Country Electric Cooperative
Rochester Gas & Electric Corporation
Sierra Pacific Power Company
South Beloit Water, Gas & Electric Company
St. Joseph Light & Power Company
Superior Water, Light and Power Company
Texas-New Mexico Power Company
Toledo Edison Company
Tucson Electric Power Company
UGI Utilities, Inc.
Union Electric Company
Union Light, Heat & Power Company
Unitil Power Corporation
Upper Penninsula Power Company
Vermont Electric Transmission Company
Vermont Electric Power Company
Virginia Electric & Power Company
Yadkin, Inc.

[[Page 21725]]

Appendix G

I. Legal Analysis of Commission Jurisdiction Over the Rates, Terms and 
Conditions of Unbundled Retail Transmission in Interstate Commerce

    Based on an analysis of the relevant legislative history and 
case law under the Federal Power Act (FPA), the Commission concludes 
that it has exclusive jurisdiction over the rates, terms and 
conditions of the unbundled transmission in interstate commerce, by 
a public utility, of electric energy to an end user. This is also 
known as retail wheeling in interstate commerce. <SUP>1
---------------------------------------------------------------------------

    \1\ Section 212(h) of the FPA provides that no order issued 
under the FPA shall be conditioned upon or require the transmission 
of electric energy directly to an ultimate consumer. 16 U.S.C. 
824k(h). The Commission's assertion of jurisdiction in this final 
rule is over the rates, terms and conditions of retail transmission 
that occurs voluntarily or as a result of a state retail access 
program.
---------------------------------------------------------------------------

    The Commission's jurisdiction over the rates, terms and 
conditions of transmission in interstate commerce derives from 
Congress' power to regulate interstate commerce under the United 
States Constitution <SUP>2 and the FPA. When Congress enacted the 
FPA, it gave the Commission exclusive jurisdiction over the rates, 
terms and conditions of transmission in interstate commerce by 
public utilities. The Supremacy Clause of the Constitution provides 
that federal laws enacted pursuant to the powers delegated to the 
federal government by the United States Constitution are the supreme 
law of the land.<SUP>3 Accordingly, to the extent that retail 
wheeling involves transmission in interstate commerce by public 
utilities, the rates, terms and conditions of such service are 
subject to the exclusive jurisdiction of the Commission, and must be 
filed with the Commission.<SUP>4
---------------------------------------------------------------------------

    \2\ U.S. Const. art I, Section 8, cl.3.
    \3\ U.S. Const. art. VI, cl.2.
    \4\ See Montana-Dakota Utilities Co. v. Northwestern Public 
Service Co., 341 U.S. 246, 251-52 (1951) (Montana-Dakota).
---------------------------------------------------------------------------

1. Relevant Federal Power Act Provisions

    Section 201(b)(1) of the FPA provides:
    The provisions of this Part shall apply to the transmission of 
electric energy in interstate commerce and to the sale of electric 
energy at wholesale in interstate commerce * * *. The Commission 
shall have jurisdiction over all facilities for such transmission or 
sale of electric energy, but shall not have jurisdiction * * * over 
facilities used in local distribution or only for the transmission 
of electric energy in intrastate commerce, or over facilities for 
the transmission of electric energy consumed wholly by the 
transmitter.

16 U.S.C. 824(b)(1) (emphasis added). Thus, the statute on its face 
limits Commission jurisdiction over sales of energy to sales at 
wholesale, but does not limit jurisdiction over transmission to 
transmission used only for wholesale sales.
    Sections 201 (c) and (d) define the meaning of ``the 
transmission of electric energy in interstate commerce'' and ``sale 
of electric energy at wholesale in interstate commerce.'' Section 
201(c) provides:
    For the purpose of this Part, electric energy shall be held to 
be transmitted in interstate commerce if transmitted from a State 
and consumed at any point outside thereof: but only insofar as such 
transmission takes place within the United States.

16 U.S.C. 824(c). Section 201(d) provides:

    The term ``sale of electric energy at wholesale'' when used in 
this Part means a sale of electric energy to any person for resale.

16 U.S.C. 824(d).
    Sections 205 and 206 of the FPA give the Commission jurisdiction 
over the rates, terms and conditions of transmission in interstate 
commerce, and sales at wholesale in interstate commerce, by public 
utilities. 16 U.S.C. 824d and 824e.

2. Legislative History and Case Law

    Much of the legislative history of the FPA indicates that 
Congress intended the Commission's jurisdiction to extend only to 
those matters which the Attleboro decision <SUP>5 held to be beyond 
the reach of the States. For instance, the report accompanying the 
Senate bill states that subsection (b) ``leaves to the States the 
authority to fix local rates even in cases where the energy is 
brought in from another State.'' <SUP>6 In other words, states 
retain authority to regulate rates of electric energy to ultimate 
consumers. The Senate report also states:
---------------------------------------------------------------------------

    \5\ Public Utilities Commission v. Attleboro Steam & Electric 
Co., 273 U.S. 83 (1927) (Attleboro). In Attleboro, the Supreme Court 
held that State regulation of the interstate sale of electricity was 
barred by the Commerce Clause because such regulation would impose a 
``direct burden'' on interstate commerce.
    \6\ S. Rep. No. 621, 74th Cong., 1st Sess. 48 (1935). See also 
H.R. Rep. No. 1318, 74th Cong., 1st Sess. 8 (1935).
---------------------------------------------------------------------------

    The rate-making powers of the Commission are confined to those 
wholesale transactions which the Supreme Court held in (Attleboro) 
to be beyond the reach of the States. Jurisdiction is asserted also 
over all interstate transmission lines whether or not there is sale 
of the energy carried by those lines and over the generating 
facilities which produce energy <SUP>7 for interstate transmission 
and sale.

    \7\ The provisions of the Senate bill regarding federal 
jurisdiction over generating facilities were eliminated from the 
final version of the bill.
---------------------------------------------------------------------------

S. Rep. No. 621, 74th Cong., 1st Sess. 48 (1935) (emphasis added). 
Thus, federal jurisdiction over transmission lines is not dependent 
on whether those lines are used to effect a sale, wholesale or 
otherwise.
    The provisions of FPA section 201 reserving certain regulatory 
authority to the States have been interpreted narrowly.<SUP>8 The 
Supreme Court has stated:
---------------------------------------------------------------------------

    \8\ Section 201(a) declares that Federal regulation of the 
transmission of electric energy in interstate commerce and the sale 
of such energy at wholesale in interstate commerce is necessary in 
the public interest, ``such Federal regulation, however, to extend 
only to those matters which are not subject to regulation by the 
States.'' 16 U.S.C. 824(a). Section 201(b)(1) states that the 
provisions of Part II of the FPA apply to the transmission of 
electric energy in interstate commerce and the sale of electric 
energy at wholesale in interstate commerce but, except as 
specifically provided, ``shall not apply to any other sale of 
electric energy or deprive a State or State commission of its lawful 
authority now exercised over the exportation of hydroelectric energy 
which is transmitted across a State line.'' 16 U.S.C. 824(b)(1).
---------------------------------------------------------------------------

    In section 201(b), Congress did no more than leave standing 
whatever valid state laws then existed relating to the exportation 
of hydroelectric energy; by its plain terms, section 201(b) simply 
saves from pre-emption under Part II of the Federal Power Act such 
state authority as was otherwise ``lawful.'' <SUP>9
---------------------------------------------------------------------------

    \9\ New England Power Co. v. New Hampshire, 455 U.S. 331, 341 
(1982) (NEPCO).
---------------------------------------------------------------------------

    The Court also stated:
    Nothing in the legislative history or language of the statute 
evinces a congressional intent `to alter the limits of state power 
otherwise imposed by the Commerce Clause,' * * * or to modify the 
earlier holding of this Court concerning the limits of state 
authority to restrain interstate trade.<SUP>10
---------------------------------------------------------------------------

    \10\ Id. (citation omitted).
---------------------------------------------------------------------------

    Unlike the narrow interpretations given to the FPA provisions 
reserving certain regulatory authority to the States,<SUP>11 the 
courts have construed transmission ``in interstate commerce'' 
broadly. The term does not turn on whether the contract path for a 
particular power or transmission sale crosses state lines, but 
rather follows the physical flow of electricity. Because of the 
highly integrated nature of the electric system, this results in 
most transmission of electric energy being ``in interstate 
commerce.''
---------------------------------------------------------------------------

    \11\ While Congress may exercise its Commerce Clause authority 
to grant the States that ``ability to restrict the flow of 
interstate commerce that they would not otherwise enjoy,'' Lewis v. 
BT Investment Managers, Inc., 447 U.S. 27, 44 (1980), States may not 
exercise such regulatory powers unless Congress has expressly stated 
its intention to make such an affirmative grant of power. NEPCO, 455 
U.S. at 343.
---------------------------------------------------------------------------

    One of the earliest cases construing Commission jurisdiction 
over transmission was Jersey Central Power & Light Co. v. FPC, 319 
U.S. 61 (1943) (Jersey Central). In that case, the Commission 
asserted jurisdiction over a New Jersey utility by showing that the 
utility owned transmission facilities that were used to transmit 
energy in interstate commerce. The Court found that the Commission 
had demonstrated that the utility owned transmission facilities that 
were indirectly interconnected, through a second New Jersey utility, 
to facilities owned by a New York utility and that the facilities 
were used to transmit electric energy in interstate commerce.
    The Court noted that section 201(c) of the FPA defines electric 
energy transmitted in interstate commerce to be energy ``transmitted 
from a State and consumed at any point outside thereof.'' The Court 
stated:
    It is impossible for us to conclude that this definition [of 
transmission in interstate commerce] means less than it says and 
applies only to the energy at the instant it crosses the state line 
and so only to the facilities which cross the line and only to the 
company which owns the facilities that cross the line.

319 U.S. at 71. Thus, a critical question regarding the 
jurisdictional status of a wheeling transaction is whether the 
facilities used to provide the service transmit electric energy in 
interstate commerce.

[[Page 21726]]

    In Connecticut Light & Power Co. v. FPC, 324 U.S. 515 (1945) 
(CL&P), the Court reviewed the Commission's finding that a 
Connecticut utility was jurisdictional because it owned transmission 
facilities that were used in interstate commerce. The Court 
generally embraced the Jersey Central standard for determining 
whether facilities are used to transmit electric energy in 
interstate commerce. The Court emphasized that whether certain 
facilities transmit electric energy in interstate commerce is more a 
technical than a legal question. The Court stated:
    Federal jurisdiction was to follow the flow of electric energy, 
an engineering and scientific, rather than a legalistic or 
governmental, test.

324 U.S. at 529. Thus, the Court adopted the Jersey Central test 
providing that the Commission's jurisdiction generally extends to 
transmission facilities that transmit electric energy in interstate 
commerce.
    The Court also applied the Jersey Central test in FPC v. Florida 
Power & Light Co., 404 U.S. 453 (1972), affirming the Commission's 
finding of jurisdiction over a Florida utility. The Commission 
demonstrated that the utility transmitted power to another Florida 
utility's ``bus'' <SUP>12 and that power was simultaneously 
transferred from the ``bus'' to a Georgia utility. The Court upheld 
the Commission's finding that electric energy from the two Florida 
utilities was commingled and was therefore transmitted in interstate 
commerce. 404 U.S. at 463.
---------------------------------------------------------------------------

    \12\ A bus is an electrical conductor which serves as a common 
connection for two or more electrical circuits. Electric Utility 
Rate Design Study, Glossary: Electric Utility and Ratemaking Load & 
Management Terms, Edison Electric Institute (Sept. 11, 1978).
---------------------------------------------------------------------------

    In all of the above cases, the Court's decisions turned on 
whether energy being transmitted flowed in interstate commerce as a 
technical matter. The decisions did not turn on whether the 
transmission of energy flowing in interstate commerce involved 
energy that was being sold for resale or was being sold to an end 
user. Thus, there is nothing in the statute, its legislative 
history, or the case law to indicate that the Commission's 
jurisdiction over rates, terms and conditions of transmission in 
interstate commerce extends only to wholesale transmission and not 
retail transmission. Indeed, the statute on its face gives the 
Commission jurisdiction over transmission in interstate commerce and 
makes no distinction between wholesale transmission and retail 
transmission.
    However, there are two important limitations on Commission 
authority. First, as discussed above, the FPA does not give the 
Commission jurisdiction over sales of electric energy at retail. 
Such sales historically have been bundled sales (i.e., generation 
and transmission), and courts and the Commission have recognized 
State jurisdiction over bundled sales of energy. Second, under 
section 201(b)(1) of the FPA, the Commission does not have 
jurisdiction over facilities used in local distribution. In CL&P, 
the Court stated that local distribution facilities are exempt from 
Commission jurisdiction even if those facilities ``carry no energy 
except extra-state energy.'' 324 U.S. at 531.
    In the next section the Commission further discusses the 
statutory provisions and case law that shed light on the demarcation 
between transmission and local distribution, and thus on the 
jurisdictional line between federal and State authority.

II. Legal Analysis of Commission Jurisdictional Transmission Facilities 
and State Jurisdictional Local Distribution Facilities

    Two specific circumstances are addressed:
    First, what facilities are jurisdictional to the Commission in a 
situation involving the unbundled delivery in interstate commerce by 
a public utility of electric energy from a third-party supplier to a 
purchaser who will then re-sell the energy to an end user?
    Second, what facilities are jurisdictional to the Commission in 
a situation involving the unbundled delivery in interstate commerce 
by a public utility of electric energy from a third-party supplier 
to an end user?
    Based on an analysis of the relevant legislative history and 
case law under the FPA, the Commission reaches the following 
conclusions. With respect to the first circumstance, the Commission 
concludes that a public utility's facilities used to deliver 
electric energy to a wholesale purchaser, whether labeled 
``transmission,'' ``distribution,'' or ``local distribution'' are 
subject to the Commission's exclusive jurisdiction under sections 
205 and 206 of the FPA, and that a public utility's facilities used 
to deliver electric energy from the wholesale purchaser to the 
ultimate consumer are ``local distribution'' facilities subject to 
the rate jurisdiction of the state. <SUP>13
---------------------------------------------------------------------------

    \13\ There are, of course, facilities that are used to provide 
delivery to both wholesale purchasers and end users. In those 
situations, we believe that the Commission and the States have 
jurisdiction to set rates for the services that are within their 
respective jurisdictions. That facilities are used to serve resale 
and retail customers does not, however, necessarily mean that the 
facilities are local distribution facilities.
---------------------------------------------------------------------------

    With respect to the second circumstance, the Commission believes 
that, based on the particular facts of the case, some of the public 
utility's facilities used to deliver electric energy to an end-user 
may be FERC-jurisdictional transmission facilities, while some of 
the facilities used may be state-jurisdictional local distribution 
facilities.
    We set forth below the relevant legislative history and case 
law, our legal conclusions, and the factors which we believe are 
indicative of whether facilities are used in ``local distribution'' 
or ``transmission in interstate commerce,'' as those terms are used 
in the FPA.

1. Relevant Federal Power Act Provisions

    The Commission's jurisdiction is set forth in section 201 of the 
FPA. <SUP>14 Section 201(b)(1) provides in pertinent part:
---------------------------------------------------------------------------

    \14\ 16 U.S.C. 824.
---------------------------------------------------------------------------

    The provisions of this Part shall apply to the transmission of 
electric energy in interstate commerce and to the sale of electric 
energy at wholesale in interstate commerce * * *. The Commission 
shall have jurisdiction over all facilities for such transmission or 
sale of electric energy, but shall not have jurisdiction * * * over 
facilities used in local distribution or only for the transmission 
of electric energy in intrastate commerce, or over facilities for 
the transmission of electric energy consumed wholly by the 
transmitter.<SUP>15
---------------------------------------------------------------------------

    \15\ 16 U.S.C. 824(b) (emphasis added).
---------------------------------------------------------------------------

    Some of the court decisions that construe jurisdictional 
facilities under section 201 also construe the Commission's 
jurisdiction under section 203. Section 203(a) provides, in relevant 
part:
    No public utility shall sell, lease, or otherwise dispose of the 
whole of its facilities subject to the jurisdiction of the 
Commission, * * * or by any means whatsoever, directly or 
indirectly, merge or consolidate such facilities or any part thereof 
with those of any other person * * * without first having secured an 
order of the Commission to do so.<SUP>16
---------------------------------------------------------------------------

    \16\ 16 U.S.C. 824b (emphasis added).
---------------------------------------------------------------------------

    In addition, section 206(d) concerns facilities ``under the 
jurisdiction of the Commission'':
    The Commission upon its own motion, or upon the request of any 
State commission whenever it can do so without prejudice to the 
efficient and proper conduct of its affairs, may investigate and 
determine the cost of the production or transmission of electric 
energy by means of facilities under the jurisdiction of the 
Commission in cases where the Commission has no authority to 
establish a rate governing the sale of such energy.<SUP>17
---------------------------------------------------------------------------

    \17\ 16 U.S.C. 824e(d) (emphasis added).
---------------------------------------------------------------------------

2. Legislative History of the FPA

    The relevant legislative history of the general purposes of 
Title II of the FPA, and of section 201 in particular, focuses 
primarily on bundled sales of electric energy and does not directly 
address the issue of what constitutes local distribution as opposed 
to transmission in interstate commerce.
    In discussing the general purposes of Title II of the House 
bill, the House Report states:
    Title II * * * establishes for the first time regulation of 
electric utility companies transmitting energy in interstate 
commerce.
 * * * * *
    * * * Under the decision of the Supreme Court of the United 
States in (Attleboro), the rates charged in interstate wholesale 
transactions may not be regulated by the States. Part II gives the 
Federal Power Commission jurisdiction to regulate these rates. A 
``wholesale'' transaction is defined to mean the sale of electric 
energy for resale and the Commission is given no jurisdiction over 
local rates even where the electric energy moves in interstate 
commerce.<SUP>18
---------------------------------------------------------------------------

    \18\ H.R. Rep. No. 1318, 74th Cong., 1st Sess. 7-8 (1935).
---------------------------------------------------------------------------

    In its analysis of section 201, the House Report states:
    As in the Senate bill no jurisdiction is given over local 
distribution of electric energy, and the authority of States to fix 
local rates is not disturbed even in those cases where the energy is 
brought in from another State.<SUP>19
---------------------------------------------------------------------------

    \19\ Id. at 27.

---------------------------------------------------------------------------

[[Page 21727]]

    The Senate Report's discussion of the general purposes of the 
FPA states:
    The decision of the Supreme Court in (Attleboro) placed the 
interstate wholesale transactions of the electric utilities entirely 
beyond the reach of the States. Other features of this interstate 
utility business are equally immune from State control either 
legally or practically.<SUP>20
---------------------------------------------------------------------------

    \20\ S. Rep. No. 621, 74th Cong., 1st Sess. at 17 (1935). See 
id. at 18 (``The revision [between the original and final versions 
of the Senate bill] has also removed every encroachment upon the 
authority of the States. The revised bill would impose Federal 
regulation only over those matters which cannot effectively be 
controlled by the States.'')
---------------------------------------------------------------------------

    In discussing material differences between the final version of 
the Senate bill and the original version, the Senate Report states:
    Subsection (b), formerly (a), which states the subject matter to 
which the part relates, has been clarified to make plain that it 
includes interstate transmission where there is no sale and excludes 
all facilities used only for production of transmission in 
intrastate commerce or in local distribution.<SUP>21
---------------------------------------------------------------------------

    \21\ Id. at 19.
---------------------------------------------------------------------------

    In discussing section 201 of the Senate bill, the Senate Report 
further states:
    The rate-making powers of the Commission are confined to those 
wholesale transactions which the Supreme Court held in (Attleboro) 
to be beyond the reach of the States. Jurisdiction is asserted also 
over all interstate transmission lines whether or not there is sale 
of the energy carried by those lines and over the generating 
facilities which produce energy for interstate transmission and 
sale. It is obvious that no steps can be taken to secure the planned 
coordination of this industry on a regional scale unless all of the 
facilities, other than those used solely for retail distribution, 
are made subject to the jurisdiction of the Commission. Facilities 
used only for intrastate commerce or local distribution are 
expressly excluded from the operation of the act.<SUP>22
---------------------------------------------------------------------------

    \22\ Id. at 48. The provisions of the Senate bill regarding 
federal jurisdiction over generating facilities were eliminated from 
the final version of the bill.
---------------------------------------------------------------------------

    The Conference Report adds little description regarding 
jurisdictional facilities. In reference to section 201(b) it states 
that:
    [T]he language of the House amendment has been followed with a 
clarifying phrase added to remove any doubt as to the Commission's 
jurisdiction over facilities used for the generation and local 
distribution of electric energy to the extent provided in other 
sections of this part and the part next following.<SUP>23
---------------------------------------------------------------------------

    \23\ H.R. Conf. Rep. No. 1903, 74th Cong., 1st Sess. 74 (1935).
---------------------------------------------------------------------------

    In addition to the above statements pertaining to section 201 of 
the FPA, Congress referenced distribution of energy in the 
legislative history of section 206(d). Section 206(d) was originally 
enacted as section 206(b) of the FPA. Under the Regulatory Fairness 
Act of 1988,<SUP>24 section 206(b) was redesignated as section 
206(d).
---------------------------------------------------------------------------

    \24\ Pub. L. No. 100-473, 102 Stat. 2299 (1988).
---------------------------------------------------------------------------

    The Conference Report on the original FPA does not address 
section 206(b). The Senate Report on the FPA bill states in 
pertinent part:
    Subsection (b) authorizes the Commission to investigate and 
determine the cost of the production or transmission of electric 
energy by means of facilities under the jurisdiction of the 
Commission in cases where the Commission has no authority to 
establish a rate governing the sale of such energy. * * * Since the 
rate-making powers granted to the Commission apply only to the 
wholesale rates of energy sold in interstate commerce, this last 
subsection should be of great benefit in removing the practical 
difficulty which the States may encounter in regulating the 
interstate distribution rates which are left under their control. 
Such rate regulation involves the examination and valuation of 
property outside the State. The task is one requiring an agency with 
a jurisdiction broader than that of a single State. The authority of 
the Federal Commission is to render assistance to the State 
commissions in a way which would preserve and make more effective 
the jurisdiction which is thus left to the States.<SUP>25
---------------------------------------------------------------------------

    \25\ S. Rep. No. 621, 74th Cong., 1st Sess. 51 (1935) (emphasis 
added).
---------------------------------------------------------------------------

    The House Report discusses section 206(b) as follows:
    This subsection reaches those situations where electric energy 
is transmitted in interstate commerce by the same company which 
distributes it locally, and will greatly aid State commissions in 
fixing reasonable rates in such cases.<SUP>26
---------------------------------------------------------------------------

    \26\ H.R. Rep. No. 1318, 74th Cong., 1st Sess. 29 (1935) 
(emphasis added).
---------------------------------------------------------------------------

    Thus, the discussions in the two reports do not appear to 
contemplate a situation in which the transmitter and seller of 
electric energy are different, and neither is a ``local'' 
distributor. The House Report expressly refers to the same company 
being the transmitter and seller of electric energy. The Senate 
Report by its terms addresses the regulation of interstate 
distribution rates.<SUP>27
---------------------------------------------------------------------------

    \27\ The Senate Report states that interstate distribution rates 
are left in the States' control. Obviously, the Senate drew a 
distinction between interstate distribution (left in the States' 
control) and interstate transmission (given to the FPC). Compare S. 
Rep. No. 621 at 49 with H.R. Rep. No. 1318 at 51.
---------------------------------------------------------------------------

    The above legislative history on sections 201 and 206(b) does 
not provide any definitive answers to the questions raised. We 
therefore turn to the case law under the FPA.

 3. Case Law Under the FPA

    Jersey Central was the first of the major FPC jurisdictional 
cases considered by the Supreme Court. The case involved the 
acquisition by New Jersey Power and Light Company (New Jersey Power) 
of certain securities of Jersey Central Power & Light Company 
(Jersey Central) without the Commission's prior approval. The 
question before the Court was whether Jersey Central was a ``public 
utility'' under section 201(e) <SUP>28 of the FPA so that the 
Commission's prior approval of the stock acquisition was necessary 
under section 203 of the FPA.
---------------------------------------------------------------------------

    \28\ Section 201(e) defines a ``public utility'' as ``any person 
who owns or operates facilities subject to the jurisdiction under 
this Part (other than facilities subject to such jurisdiction solely 
by reason of section 210, 211, or 212).'' 16 U.S.C. 824(e). The 
section as adopted in 1935 did not contain the parenthetical, which 
was adopted in 1978 as part of the Public Utility Regulatory 
Policies Act.
---------------------------------------------------------------------------

    Jersey Central owned transmission facilities that connected to 
facilities that Public Service Electric & Gas Company (Public 
Service) owned. The interconnection of these transmission facilities 
was in New Jersey. Public Service's facilities in turn connected to 
the facilities of the Staten Island Edison Corporation (Staten 
Island Edison), a New York utility, at the mid-channel of Kill van 
Kull, a body of water separating New Jersey and New York. Jersey 
Central delivered energy to and received energy from Public Service 
under contract, and Public Service delivered energy to and received 
energy from Staten Island Edison under contract.<SUP>29
---------------------------------------------------------------------------

    \29\ Jersey Central, 319 U.S. at 63-65.
---------------------------------------------------------------------------

    The Court found that, although Jersey Central generated and 
received electricity only in New Jersey, some of the electric energy 
that it dispatched to Public Service ``was instantaneously 
transmitted to New York.'' <SUP>30 The Court held that ``[t]his 
evidence * * * furnishes substantial basis for the conclusion of the 
Commission that facilities of Jersey Central are utilized for the 
transmission of electric energy across state lines.'' <SUP>31 
Therefore, the Court found that Jersey Central was a public utility 
within the meaning of section 201(e).<SUP>32
---------------------------------------------------------------------------

    \30\ Id. at 66.
    \31\ Id. at 67 (citation omitted).
    \32\ Id. at 73.
---------------------------------------------------------------------------

    The Court cited Attleboro, in which the Court found that the 
sale of locally produced electric energy for use in another state 
resulted in the transmission of electric energy in interstate 
commerce, even though title passed at the state line.<SUP>33 In 
Jersey Central, the Court explained the rationale for federal 
jurisdiction as follows:
---------------------------------------------------------------------------

    \33\ 273 U.S. at 86, 89-90.
---------------------------------------------------------------------------

    (Section 201(c) of the FPA) defines the electric energy in 
commerce as that ``transmitted from a State and consumed at any 
point outside thereof.'' There was no change in this definition in 
the various drafts of the bill. The definition was used to ``lend 
precision to the scope of the bill.'' It is impossible for us to 
conclude that this definition means less than it says * * *. The 
purpose of this act was primarily to regulate the rates and charges 
of the interstate energy.<SUP>34
---------------------------------------------------------------------------

    \34\ 319 U.S. at 71 (footnote omitted).
---------------------------------------------------------------------------

    The Court in Jersey Central thus interpreted the FPA as placing 
within the federal province regulation of wholesale sales of 
electric energy that, in any manner, flows in interstate commerce. 
The language quoted above and the citation to section 201(c) of the 
FPA, to be relied upon in subsequent Supreme Court cases, strongly 
suggested that the Commission's jurisdiction was not based on 
whether there was a sale by the utility, but rather on the flow of 
electric energy either into or out of a state, so long as the energy 
crosses state lines.
    CL&P, which was decided two years after Jersey Central, is the 
leading case interpreting

[[Page 21728]]

the section 201(b) local distribution proviso. In CL&P, the 
Commission sought to regulate the accounting practices of 
Connecticut Light & Power Company (CL&P). <SUP>35 At issue was 
whether CL&P was a ``public utility'' under the FPA. The utility's 
system encompassed an area solely within a single state 
(Connecticut) <SUP>36 and did not interconnect with any other 
company that operated out of state. <SUP>37 ``Its purchases and 
sales, its receipts and deliveries of power, (were) all within the 
state.'' <SUP>38 However, CL&P did purchase energy from companies 
that had, in turn, purchased energy from Massachusetts. The company 
also sold energy to a municipality that exported a portion of that 
energy to Fishers Island, located off the coast of Connecticut but 
``territory of New York.'' <SUP>39 The Commission based its 
jurisdiction on these few transactions.<SUP>40
---------------------------------------------------------------------------

    \35\ CL&P, 324 U.S. at 517.
    \36\ Id. at 518.
    \37\ Id. at 521.
    \38\ Id. at 522.
    \39\ Id. at 519-21.
    \40\ Id.
---------------------------------------------------------------------------

    The Court of Appeals affirmed the Commission, holding that the 
Commission's jurisdiction extended to ``electric distribution 
systems which normally would operate as interstate businesses.'' The 
Court of Appeals found that:
    Whether or not the facilities by which petitioner distributes 
energy from Massachusetts should be classified as `local' is not 
relevant to this case. The sole test of jurisdiction of the 
Commission over accounts is whether these facilities, `local' or 
otherwise, are used for the transmission of electric energy from a 
point in one state to a point in another.( <SUP>41)
---------------------------------------------------------------------------

    \41\ Id. at 522, quoting Connecticut Light & Power Co. v. FPC, 
141 F.2d 14, 18 (D.C. Cir. 1944).
---------------------------------------------------------------------------

    The Supreme Court reversed. It held that the statutory language 
in section 201(b) of the FPA providing that the Commission ``shall 
not have jurisdiction * * * over facilities used in local 
distribution'' is a limitation upon Commission jurisdiction that 
``the Commission must observe and the courts must enforce.'' <SUP>42 
In analyzing the statute, the Court stated:
---------------------------------------------------------------------------

    \42\ 324 U.S. at 529.
---------------------------------------------------------------------------

    It has never been questioned that technologically generation, 
transmission, distribution and consumption are so fused and 
interdependent that the whole enterprise is within the reach of the 
commerce power of Congress, either on the basis that it is, or that 
it affects, interstate commerce, if at any point it crosses a state 
line.
* * * * *
    But whatever reason or combination of reasons led Congress to 
put the provision in the Act, we think it meant what it said by the 
words ``but shall not have jurisdiction * * * over facilities used 
in local distribution.'' Congress by these terms plainly was trying 
to reconcile the claims of federal and local authorities and to 
apportion federal and state jurisdiction over the industry.<SUP>43
---------------------------------------------------------------------------

    \43\ Id. at 529-31.
---------------------------------------------------------------------------

    The Court decided that this limitation on jurisdiction was ``a 
legal standard that must be given effect in this case in addition to 
the technological transmission test.''<SUP>44
---------------------------------------------------------------------------

    \44\ Id. at 531.
---------------------------------------------------------------------------

    The Court stated that whether or not local distribution 
facilities carried out-of-state electric energy was irrelevant. 
Whatever the origin of the electric energy they carried, so long as 
the utility used the lines for local distribution,<SUP>45 they were 
exempt from federal jurisdiction.<SUP>46 In fact, the Court stated 
that local distribution facilities ``may carry no energy except 
extra-state energy and still be exempt under the Act.'' Id. at 531. 
The Court concluded that the Commission's order:
---------------------------------------------------------------------------

    \45\ It appears that while the Company received power (at one 
location) at 66 kV, it primarily owned facilities at 13.8 kV and 
below.
    \46\ 324 U.S. at 531.
---------------------------------------------------------------------------

    Must stand or fall on whether this company owned facilities that 
were used in transmission of interstate power and which were not 
facilities used in local distribution.<SUP>47
---------------------------------------------------------------------------

    \47\ Id. at 531 (emphasis added).
---------------------------------------------------------------------------

    Upon reversing the Court of Appeals, the Court commented, in 
dictum, on the evidence the Commission had relied upon in finding 
that the facilities in question were used for transmission. It noted 
that the Commission had relied upon certain gas transportation cases 
in concluding that transmission extends from the generator to the 
point where the function of conveyance in bulk over distance is 
completed and the process of subdividing the energy to serve 
ultimate consumers, which is the characteristic of ``local 
distribution,'' is begun. The Court cautioned:
    But a holding that distributing gas at low pressure to consumers 
is a local business is not a holding that the process of reducing it 
from high to low pressure is not also part of such local business. 
In so far as the Commission found in these cases a rule of law which 
excluded from the business of local distribution the process of 
reducing energy from high to low voltage in subdividing it to serve 
ultimate consumers, the Commission has misread the decisions of this 
Court. No such rule of law has been laid down.<SUP>48
---------------------------------------------------------------------------

    \48\ Id. at 534.
---------------------------------------------------------------------------

    The Court also noted in its dictum, however, that once a company 
is properly found to be a ``public utility'' under the Act, the fact 
that a local commission may also have jurisdiction does not preclude 
exercise of the Commission's functions. Id. at 533.<SUP>49 The Court 
instructed the lower court to remand the case to the Commission for 
a finding regarding whether the facilities in question were used in 
local distribution.<SUP>50
---------------------------------------------------------------------------

    \49\ See United States v. Public Utilities Commission of 
California, 345 U.S. 295, 316 (1953) (Public Utilities Commission): 
Certainly the concrete fact of resale of some portion of the 
electricity transmitted from a state to a point outside thereof 
invokes federal jurisdiction at the outset, despite the fact that 
the power thus used traveled along its interstate route 
``commingled'' with other power sold by the same seller and 
eventually directly consumed by the same purchaser-distributor.
    See also Arkansas Power & Light Co. v. FPC, 368 F.2d 376, 383 
(8th Cir. 1966) (``Where a company is in fact a public utility, all 
wholesale sales for resale in interstate commerce are subject to the 
provisions of sections 205 and 206 of the (FPA), regardless of the 
facilities used.''). The Eighth Circuit further noted that the 
section 201(b) exemption applies to a company's status as a public 
utility and not to the Commission's jurisdiction over sales in 
interstate commerce for resale. Id., citing Public Utilities 
Commission, Colton, infra, and Wisconsin-Michigan, infra.
    \50\ Id. at 536.
---------------------------------------------------------------------------

    The CL&P case was ultimately disposed of without the Commission 
having made a finding that the facilities were used in local 
distribution. While the Commission found that it was ``extremely 
doubtful'' that it could find that the facilities in question were 
not local distribution facilities, 6 FPC 104, 106 (1947), the 
Commission did not articulate a definition of local distribution 
facilities.
    In Wisconsin-Michigan Power Co. v. Federal Power Commission, 
<SUP>51 the Seventh Circuit held that a utility was a jurisdictional 
public utility where it operated two divisions in Wisconsin and 
Michigan in a coordinated manner such that electric energy from one 
state was transmitted to the other, and vice versa, ``in appreciable 
amounts by the power company and by it commingled with energy 
generated in the two respective districts and then delivered to the 
[wholesale] customers * * *.'' <SUP>52 The court also rejected the 
notion that the energy changed its form or character when it was 
stepped down in voltage before it reached the wholesale purchasers. 
<SUP>53
---------------------------------------------------------------------------

    \51\ 197 F.2d 472 (7th Cir. 1952), cert. denied, 345 U.S. 934 
(1953) (Wisconsin-Michigan).
    \52\ Id. at 474.
    \53\ Id. (``Obviously the energy thus transmitted in interstate 
commerce is not changed in form or in character except that the 
voltage is reduced to an extent consistent with efficient economic 
management and operation.'').
---------------------------------------------------------------------------

    The court in Wisconsin-Michigan distinguished between 
transmission and local distribution by focusing on wholesale sales 
of electric energy versus retail sales (``local rates'') of electric 
energy. It cited the House Report on the FPA, and characterized the 
legislative history as follows:
    The legislative history, (H.R. Rep. No. 1318), 74th Cong., 1st 
Sess. pages 7, 8 and 27 (1935), discloses that the Congressional 
Committee intended that the provisions of the (FPA) should apply to 
the transmission of electric energy in interstate commerce, i.e., 
the sale of energy at wholesale in interstate commerce, but not to 
the retail sale of any such energy in local distribution; that the 
(FPA) left to the state the authority to fix local rates where the 
energy is brought in from other states, and that the rate making 
power of the (FPC) was to be confined to those wholesale 
transmissions which the Supreme Court had held in (Attleboro) to be 
beyond the reach of the state. Under that decision, said the 
committee, the rates charged in interstate wholesale transactions 
could not be regulated by the states. It defined a wholesale 
transaction as the sale of electric energy for resale.<SUP>54
---------------------------------------------------------------------------

    \54\ 197 F.2d at 476 (emphasis added).
---------------------------------------------------------------------------

    The Seventh Circuit's characterization of the House Report seems 
to equate transmission of electric energy in interstate commerce 
with the sale of energy at wholesale in interstate commerce. 
However, this interpretation is at odds with both the

[[Page 21729]]

plain words of the statute as well as the language of the House 
Report, both of which refer to transmission in interstate commerce 
separately from sales for resale in interstate commerce.<SUP>55 In 
addition, the Senate Report, which the Seventh Circuit did not 
mention, clearly recognized jurisdiction over all interstate 
transmission lines, whether or not a sale of energy is carried by 
those lines.<SUP>56
---------------------------------------------------------------------------

    \55\ See H.R. Rep. No. 1318 at 27. (``Subsection (b) confers 
jurisdiction upon the Commission over the transmission of electric 
energy in interstate commerce and the sale of electric energy in 
wholesale in interstate commerce * * *.'' emphasis added).
    \56\ See S. Rep. No. 621 at 48 (``Jurisdiction is asserted over 
all interstate transmission lines whether or not there is a sale of 
the energy carried by those lines * * *.'').
---------------------------------------------------------------------------

    The Wisconsin-Michigan court also cited analogous natural gas 
cases, stating that ``[t]he question is essentially, when does 
interstate commerce transportation end and where do the local 
distribution facilities first become operative.'' <SUP>57 The court 
further stated that:
---------------------------------------------------------------------------

    \57\ 197 F.2d at 477.
---------------------------------------------------------------------------

    (U)pon delivery to (the wholesaler) local distribution begins 
when he resells. His sales and distribution at retail are clearly 
local in character, and constitute only local distribution; but at 
no point before delivery to him has been completed, has interstate 
transmission terminated. In other words, ``facilities used in local 
distribution'' means facilities used for making resale and 
distribution to consumers, jurisdiction over which is left to the 
states. It was only because of this conclusion that the Supreme 
Court said, (citation omitted), the Act ``cut(s) sharply and cleanly 
between sales for resale and direct sales for consumptive uses.'' We 
think there is no ground for the position that local distribution 
includes any transmission occurring before the wholesaler who 
resells at retail is reached.<SUP>58
---------------------------------------------------------------------------

    \58\ Id., citing FPC v. East Ohio Gas Co., 338 U.S. 464 (1950) 
(East Ohio).
---------------------------------------------------------------------------

    The Seventh Circuit concluded that the sales for resale were 
made in interstate commerce; that local distribution had not begun; 
that the interstate character of the transmission persisted until 
delivery to the wholesaler; that, up to that point, no local 
distribution facilities were in operation and that, therefore, the 
sales were subject to Commission regulation.
    In Federal Power Commission v. Southern California Edison 
Company (the Colton case),<SUP>59 the Supreme Court held that the 
FPA provides a clear line of demarcation between jurisdictional 
transactions and non-jurisdictional transactions. However, this 
case, too, involved bundled sales of electric energy. In the facts 
of the case, Southern California Edison Company (Edison) admitted 
that it was a public utility by virtue of owning two interstate 
transmission lines.<SUP>60 At issue was whether its sales of 
electric energy to the City of Colton, California, for resale to 
Colton's retail customers, were jurisdictional. Included in the 
electric energy that Edison sold to Colton was out-of-state electric 
energy from Hoover Dam.<SUP>61 The Commission ruled that the sale to 
Colton was a sale of electric energy at wholesale in interstate 
commerce subject to regulation under the FPA.<SUP>62 In upholding 
the Commission, the Court held that Edison's importation of out-of-
state electricity for resale to Colton sufficed to confer federal 
jurisdiction.
---------------------------------------------------------------------------

    \59\ 376 U.S. 205 (1964) (Colton).
    \60\ The Supreme Court noted that Edison's status as a public 
utility did not decide the question of whether the FPC could assert 
jurisdiction over the rates for the Edison-Colton sale. Id. at 208 
n.3.
    \61\ Id. at 208, 209 & n.5.
    \62\ Id. at 208. See Arkansas Electric Cooperative Corp. v. 
Arkansas Public Service Commission, 461 U.S. 375, 380 (1983) 
(``(Colton) held, among other things, that * * * a California 
utility that received some of its power from out-of-state was 
subject to federal and not state regulation in its sales of 
electricity to a California municipality that resold the bulk of the 
power to others.'').
---------------------------------------------------------------------------

    The Court, citing an earlier Supreme Court case,<SUP>63 
characterized Congressional intent in the FPA:
---------------------------------------------------------------------------

    \63\ Illinois Natural Gas Co. v. Central Illinois Public Service 
Co., 314 U.S. 498, 504 (1942).
---------------------------------------------------------------------------

    (W)hat Congress did was to adopt the test developed in the 
Attleboro line which denied state power to regulate a sale ``at 
wholesale to local distributing companies'' and allowed state 
regulation of a sale at ``local retail rates to ultimate 
consumers.'' <SUP>64
---------------------------------------------------------------------------

    \64\ 376 U.S. at 214.
---------------------------------------------------------------------------

    The Court rejected the argument that FPC jurisdiction was 
confined to those interstate wholesale sales constitutionally beyond 
the power of state regulation by force of the Commerce Clause, and 
was to be determined on a case-by-case analysis of the impact of 
state regulation upon the national interest. The Court stated that 
in the FPA:
    (C)ongress meant to draw a bright-line easily ascertained, 
between state and federal jurisdiction, making unnecessary such 
case-by-case analysis. This was done in the Power Act by making FPC 
jurisdiction plenary and extend[ed] it to all wholesale sales in 
interstate commerce except those which Congress has made explicitly 
subject to regulation by the States.<SUP>65

    \65\ Id. at 215-216.
---------------------------------------------------------------------------

The Court held that ``(t)here is no such exception covering the 
Edison-Colton sale.'' <SUP>66

    \66\ Id. at 216 (footnote omitted).
---------------------------------------------------------------------------

    Parties in the Colton case had raised the question of whether 
jurisdiction over the Colton sale was prevented by the ``local 
distribution'' proviso of section 201(b). The Court stated that 
whether facilities are local distribution facilities is a matter for 
the Commission to decide in the first instance. Citing CL&P, supra, 
it stated:
    Whether facilities are used in local distribution--although a 
limitation on FPC jurisdiction and a legal standard that must be 
given effect in addition to the technological transmission test * * 
*--involves a question of fact to be decided by the FPC as an 
original matter.<SUP>67

    \67\ Id. at 210 n.6 (citation omitted).

The Court cited evidentiary support and the Commission's expertise 
in such matters in upholding the Commission's determination that 
certain facilities owned by Edison were used exclusively to effect 
the wholesale sale to Colton and not for local distribution. Such 
facilities included 12 kV lines that served an industrial customer, 
several lighted highway signs, a residence and a railroad section 
house before they reached the transformers in the Colton substation. 
The FPC had held that those uses prior to the lines reaching the 
Colton substation did not transform the lines into local 
distribution facilities.<SUP>68
---------------------------------------------------------------------------

    \68\ Id. at 210 n.6.
---------------------------------------------------------------------------

    In Duke Power Company v. Federal Power Commission (Duke),<SUP>69 
the D.C. Circuit held that a public utility's acquisition of 
facilities used solely in local distribution, and which would 
continue to be used for local distribution, was beyond the 
Commission's jurisdiction under section 203. The case involved Duke 
Power Company's (Duke's) proposed acquisition of facilities owned by 
Clemson University (Clemson), which were used to distribute 
electricity off-campus to customers (primarily university personnel) 
in two South Carolina counties. Clemson purchased the power at 
wholesale from Duke. No one appeared to contest the conclusion that 
the 7 miles of distribution line and 418 service connections owned 
by Clemson were ``local distribution'' facilities.<SUP>70 Rather, 
the case turned on interpreting section 203 and whether it was 
intended to affect only acquisitions of jurisdictional facilities, 
or also to affect acquisitions of non-jurisdictional facilities. In 
interpreting section 203, however, the D.C. Circuit extensively 
analyzed and discussed the fundamental jurisdictional lines that 
Congress drew in section 201.
---------------------------------------------------------------------------

    \69\ 401 F.2d 930 (D.C. Cir. 1968) (Duke).
    \70\ Duke delivered power to Clemson at a distribution voltage 
of 4,160 volts. The step-down transformers by which the voltage was 
reduced, and the substations at which the delivery was effected, 
were owned by Duke. 401 F.2d at 931, n.8.
---------------------------------------------------------------------------

    Citing to the CL&P case, the court in Duke stated:
    The Act, as we have seen, effectuated federal control over the 
transmission and the sale at wholesale of electric energy in 
interstate commerce, and established the Commission's regulatory 
power over public utilities engaging in either of these 
pursuits.\71\

    \71\ 401 F.2d at 938-39 (emphasis added, footnotes omitted).
---------------------------------------------------------------------------

However, quoting CL&P, the court further stated:

    The expression ``facilities used in local distribution'' is one 
of relative generality. But as used in this Act it is not a 
meaningless generality in the light of our history and the structure 
of our government. We hold the phrase to be a limitation on 
jurisdiction and a legal standard that must be given effect in this 
case in addition to the technological transmission test.\72\
---------------------------------------------------------------------------

    \72\ Id. (footnote omitted).
---------------------------------------------------------------------------

    The court further rejected the Commission's concept that, in 
order to determine whether jurisdiction over any particular 
acquisition existed, the impact of local supervision be measured on 
a case-by-case basis. Quoting from Colton, the court stated:
    [T]his ``flexible approach''--involving as it does the 
consideration, inter alia, of ``the

[[Page 21730]]

effect of the regulation upon the national interest in the 
commerce''--has been flatly rejected as a technique for resolving 
jurisdictional conflicts between the Commission and state bodies. * 
* * We think that like the line ``(i)t cut sharply and cleanly 
between sales for resale and direct sales for consumptive uses'' to 
facilitate jurisdictional determinations in rate regulation, 
``Congress meant to draw a bright line easily ascertained, between 
state and federal jurisdiction, making unnecessary such case-by-case 
analysis,'' in distributing regulatory power over the acquisition of 
facilities.\73\

    \73\ Id. at 949 (footnotes omitted).
---------------------------------------------------------------------------

The court rejected the Commission's argument that jurisdiction over 
the merger or consolidation of jurisdictional facilities with those 
of any other ``person'' under section 203 gave the Commission 
jurisdiction over Duke's acquisition. The court stated that the FPA 
reflects a policy ``` that matters largely of a local nature, even 
though interstate in character, should be handled locally and should 
receive the consideration of local [officials] familiar with the 
local conditions in the communities involved.' '' \74\
---------------------------------------------------------------------------

    \74\ Id. at 936 (quoting from Hearings on H.R. 5423 before the 
House Committee on Interstate and Foreign Commerce, 74th Cong., 1st 
Sess. 393 (1935) (testimony of then-FPC Commissioner Seavey)).
---------------------------------------------------------------------------

    Federal Power Commission v. Florida Power & Light Company \75\ 
is the last major court case to address the Commission's 
transmission jurisdiction. In this case, the Commission sought to 
impose its accounting rules upon Florida Power & Light Company 
(Florida Power & Light). The company's system lay solely within the 
borders of Florida and did not directly connect with any out-of-
state utility.\76\ The Commission held that Florida Power & Light 
did own facilities that transmitted electric energy in interstate 
commerce, but the Court of Appeals for the Fifth Circuit ruled that 
the Commission did not have substantial evidence to support its 
finding.
---------------------------------------------------------------------------

    \75\ 404 U.S. 453, reh'g denied, 405 U.S. 948 (1972) (Florida 
Power & Light).
    \76\ 404 U.S. at 456.
---------------------------------------------------------------------------

    The Supreme Court reversed. The Supreme Court noted that Florida 
Power & Light was a member of the Florida Power Pool along with 
Florida Power Corporation (Florida Power Corp.).\77\ In turn, 
Florida Power Corp. connected with Georgia Power Company (Georgia 
Power) at a ``bus'' \78\ south of the Georgia-Florida border.\79\ 
Florida Power Corp. regularly exchanged power with Georgia 
Power.\80\ In many instances, Florida Power Corp. transferred power 
to Florida Power & Light instantly after receiving power from 
Georgia Power, and transferred power to Georgia Power immediately 
after receiving power from Florida Power & Light.\81\ The Supreme 
Court found that power commingled in the bus moved across state 
lines, and concluded that Florida Power & Light engaged in 
transmission in interstate commerce. The Court held that, to 
establish jurisdiction, the Commission need only show that ``some 
(Florida Power & Light) power goes out of State.'' \82\ The Court 
further explained that ``(i)f any (Florida Power & Light) power has 
reached Georgia, or (if Florida Power & Light) makes use of any 
Georgia power * * * FPC jurisdiction will attach * * *.''\83\
---------------------------------------------------------------------------

    \77\ Id. at 456.
    \78\ A ``bus'' is a connector or group of connectors that serves 
as a common connection for two or more circuits.
    \79\ 404 U.S. at 457.
    \80\ Id.
    \81\ Id. at 457 & n.8.
    \82\ Id. at 461. (emphasis omitted).
    \83\ Id. at 461 n.10. (emphasis added).
---------------------------------------------------------------------------

    There is also a line of cases that address, among other things, 
what constitutes a Commission jurisdictional ``sale of electric 
energy at wholesale'' \84\ under section 201 of the FPA.\85\ These 
cases all concerned bundled sales. While the issues posed above 
involve unbundled wheeling, the ``resale'' cases are helpful to the 
extent they suggest that local distribution takes place only after 
power is subdivided. See, e.g., 345 U.S. at 316 (``the facilities 
supplied `local distribution' only after the current was subdivided 
for individual consumers.'').
---------------------------------------------------------------------------

    \84\ See Section 201(d), 16 U.S.C. 824(d) (1988).
    \85\ Public Utilities Commission, supra note 345; City of 
Oakland, California v. FERC, 754 F.2d 1378 (9th Cir. 1985) 
(Oakland). See also Alexander v. FERC, 609 F.2d 543 (D.C. Cir. 1979) 
(Alexander).
---------------------------------------------------------------------------

4. Natural Gas Act

    The Natural Gas Act (NGA) was adopted in 1938. Like the FPA, the 
NGA contains language limiting the Commission's jurisdiction in 
situations involving local distribution.\86\
---------------------------------------------------------------------------

    \86\ Courts often rely on cases construing the NGA when 
interpreting the FPA, and vice versa. E.g., Arkansas Louisiana Gas 
Co. v. Hall, 453 U.S. 571, 577 n.7 (1981).
---------------------------------------------------------------------------

    Section 1(b) of the NGA provides:
    The provisions of this Act shall apply to the transportation of 
natural gas in interstate commerce, to the sale in interstate 
commerce of natural gas for resale for ultimate public consumption 
for domestic, commercial, industrial, or any other use, and to 
natural gas companies engaged in such transportation or sale, but 
shall not apply to any other transportation or sale of natural gas 
or to the local distribution of natural gas or to the facilities 
used for such distribution or to the production or gathering of 
natural.\87\
---------------------------------------------------------------------------

    \87\ 15 U.S.C. 717(b) (emphasis added).
---------------------------------------------------------------------------

    There is similarity in many respects between the House and 
Senate Reports on the FPA and the NGA with respect to the 
jurisdiction given the Commission. For example, all four reports 
mention Attleboro as placing interstate wholesale transactions 
beyond the reach of the States. As indicated in the House Report on 
the NGA, the States could ``regulate sales to consumers even though 
such sales are in interstate commerce, such sales being considered 
local in character and in the absence of congressional prohibition 
subject to State regulation.'' (See H.R. Rep. No. 709, 75th Cong., 
1st Sess. 1). However, the House and Senate Reports on the NGA 
contain identical language not found in the reports on the FPA:
    In view of the importance of section 1(b), which states the 
scope of the act, it seems advisable to comment on certain 
provisions appearing therein. It will be noted that this subsection 
of the bill, after affirmatively stating the matters to which the 
act is to apply, contains a provision specifying what the act is not 
to apply to, as follows:
    But shall not apply to any other transportation or sale of 
natural gas or to the local distribution of natural gas or to the 
facilities used for such distribution or to the production or 
gathering of natural gas.
    The quoted words are not actually necessary, as the matters 
specified therein could not be said fairly to be covered by the 
language affirmatively stating the jurisdiction of the Commission, 
but similar language was in previous bills, and, rather than invite 
the contention, however unfounded, that the elimination of the 
negative language would broaden the scope of the act, the committee 
has included it in this bill. That part of the negative declaration 
stating that the act shall not apply to ``the local distribution of 
natural gas'' is surplusage by reason of the fact that distribution 
is made only to consumers in connection with sales, and since no 
jurisdiction is given to the Commission to regulate sales to 
consumers the Commission would have no authority over distribution, 
whether or not local in character. (Emphasis added).<SUP>88
---------------------------------------------------------------------------

    \88\ H.R. Rep. No. 709, 75th Cong., 1st Sess. 3 (1937); S. Rep. 
No. 1162, 75th Cong., 1st Sess. 3 (1937).
---------------------------------------------------------------------------

    As a result of this language it can be argued that Congress 
considered distribution (and local distribution) only in the context 
of bundled retail sales of natural gas. In fact, it appears that all 
of the court cases affirming the states' right to regulate local 
distribution of gas have involved bundled retail sales. See 
Panhandle Eastern Pipe Line Co. v. Michigan Public Service 
Commission, 341 U.S. 329 (1951) (Panhandle). There the Court, in 
affirming the State of Michigan's right to regulate an interstate 
pipeline's proposed bundled retail sales of gas to industrial 
consumers, noted that the pipeline company proposed to lay pipeline 
in ``the streets and alleys of Detroit'' and ignored the local 
distribution company's request for additional gas to meet the 
increased needs of the industrial consumers. Id. at 333. While the 
Court based its holding on a state's authority to regulate direct 
(retail) sales to an end-user, rather than on the basis of the 
section 1(b) local distribution provision, it also found that the 
proposed sales were ``primarily of local interest'' and ``emphasized 
the need for local regulation.'' Id. Two years before Panhandle, the 
Supreme Court issued its decision in FPC v. East Ohio Gas Co., 338 
U.S. 465 (1949) (East Ohio). East Ohio Gas Company owned and 
operated a natural gas business wholly within the State of Ohio. The 
company sold gas only to Ohio customers but most of the gas was 
transported to Ohio from other states by interstate pipelines. These 
interstate pipelines connected inside Ohio with East Ohio's large 
high pressure lines. The gas then was transported over 100 miles 
through East Ohio's system to its local distribution system. East 
Ohio argued that it was exempt from Commission jurisdiction because 
all of its facilities were local distribution.
    The Court disagreed, finding the Commission's jurisdiction 
extends over the

[[Page 21731]]

transportation of gas in interstate commerce through high-pressure 
transmission lines and that distribution did not begin until the 
point where pressure is reduced and gas enters local mains. The 
Court stated that: ``[w]hat Congress must have meant by `facilities' 
for `local distribution' was equipment for distributing gas among 
customers within a particular local community, not the high-pressure 
pipelines transporting the gas to the local mains.'' <SUP>89
---------------------------------------------------------------------------

    \89\ 338 U.S. at 469-70.
---------------------------------------------------------------------------

    The Commission relied in part on East Ohio's high pressure/low 
pressure distinction in a recent NGA section 7 certificate case 
which authorized construction of facilities to bypass the local 
distribution company.<SUP>90 On appeal, the California Commission 
argued that under section 1(b) it should at least have 
``jurisdiction over the `taps, meters and other tie-in facilities' 
that link the pipeline to end users.'' <SUP>91 The court disagreed:
---------------------------------------------------------------------------

    \90\ See Mojave Pipeline Company, 35 FERC para. 61,199 (1986), 
reh'g denied, 41 FERC para. 61,040 (1987), reh'g denied, 42 FERC 
para. 61,351 (1988); see also Mojave Pipeline Company, 66 FERC para. 
61,194 (1994), reh'g pending.
    \91\ See Public Utilities Commission of the State of California 
v. FERC, et al., 900 F.2d 269, 273 (D.C. Cir. 1990) (footnote 
omitted) (WyCal).
---------------------------------------------------------------------------

    While as a matter of ordinary English `local distribution' might 
be understood to encompass any delivery to an end user, that is 
hardly the only or even more plausible reading. Distribution 
conjures up receiving a large quantity of some good and parcelling 
it out among many takers.<SUP>92
---------------------------------------------------------------------------

    \92\ Id. at 276.
---------------------------------------------------------------------------

    After reviewing the report language discussed above, the court 
also stated:
    Insofar as congressional committees spoke to the matter * * * 
they appear to have viewed distribution as confined to its 
parcelling out function and (probably) even more narrowly, to 
parcelling out accompanied by retail sales. <SUP>93
---------------------------------------------------------------------------

    \93\ Id. (emphasis in original).
---------------------------------------------------------------------------

    In Cascade Natural Gas Corporation v. FERC, et al. (Cascade), 
the court affirmed the Commission's authorizing an interstate 
pipeline under section 7 of the NGA ``to construct a tap and meter 
facility that would allow it to deliver natural gas directly to two 
industrial consumers * * *.''<SUP>94 To reach the interstate 
pipeline, the industrials constructed a nine-mile pipeline. 
Together, the facilities bypassed the local distribution 
company.<SUP>95
---------------------------------------------------------------------------

    \94\ 955 F.2d 1412, 1414 (10th Cir. 1992).
    \95\ Unlike the situation in WyCal where the pipeline made 
direct sales to end users, in Cascade the pipeline transported gas 
purchased from third parties. See Northwest Pipeline Corporation, 51 
FERC para. 61,289 at 61,909 (1990).
---------------------------------------------------------------------------

    The court rejected arguments that section 1(b) deprived the 
Commission of jurisdiction holding that:
     ``Local distribution,'' as Congress viewed the term, involves 
two components: the retail sale of natural gas and its local 
delivery, normally through a network of branch lines designed to 
supply local consumers.<SUP>96
---------------------------------------------------------------------------

    \96\ Cascade, 955 F.2d at 1421.
---------------------------------------------------------------------------

5. Analysis

    a. What facilities are jurisdictional to the Commission in a 
situation involving the unbundled delivery in interstate commerce by 
a public utility of electric energy from a third-party supplier to a 
purchaser who will then re-sell the energy to an end user?
    The case law supports the conclusion that any facilities of a 
public utility used to deliver electric energy in interstate 
commerce to a wholesale purchaser, whether such facilities are 
labeled ``transmission,'' ``distribution'' or ``local 
distribution,'' are subject to the Commission's jurisdiction under 
sections 205 and 206.
    This conclusion is supported by Public Utilities Commission, 
supra, in which the Supreme Court, in the section of its opinion 
addressing the section 201(b) local distribution provision, held 
that local distribution facilities began ``only after the current 
was subdivided for individual consumers.'' \97\ Wisconsin-Michigan, 
supra, in which the Seventh Circuit held that there is no local 
distribution until the wholesaler who re-sells at retail is reached, 
is to like effect.
---------------------------------------------------------------------------

    \97\ 345 U.S. at 316 (footnote omitted).
---------------------------------------------------------------------------

    This conclusion, which results in a ``functional'' line being 
drawn to determine Commission jurisdiction, is not only consistent 
with the case law under section 201, but is also consistent with our 
interpretation of the line drawn under newly amended FPA sections 
211 and 212. As long as electric energy is being sold to a 
legitimate wholesale purchaser, we believe the Commission has 
jurisdiction under sections 201, 205, and 206 of the FPA over the 
public utility's facilities used to deliver electric energy to that 
purchaser.
     b. What facilities are jurisdictional to the Commission in a 
situation involving the unbundled delivery in interstate commerce by 
a public utility of electric energy from a third-party supplier 
directly to an end user?
    In analyzing jurisdiction over unbundled retail wheeling, we 
believe it is important to distinguish between unbundled wheeling 
provided by the public utility who previously provided bundled 
retail service to the end user, and unbundled wheeling provided by 
other public utilities to the end user. For example, a former 
bundled retail customer may need unbundled wheeling services from 
its previous public utility generation supplier, as well as 
unbundled wheeling from one or more intervening public utilities, in 
order to reach a distant generation supplier. In this scenario, the 
Commission believes it would have jurisdiction over all of the 
facilities used for the unbundled wheeling provided by the 
intervening public utilities.\98\ The more difficult issue is 
whether some portion of the facilities used to transmit energy from 
the transmitting utility in closest proximity to the end user (the 
former supplier of the bundled product) is local distribution 
facilities. We believe that in most, if not all circumstances, some 
portion will be local distribution facilities.
---------------------------------------------------------------------------

    \98\ The Commission would not have jurisdiction over the rates 
for the sale of generation by the distant supplier because the 
transaction would be a retail sale of electric energy.
---------------------------------------------------------------------------

    The case law is replete with statements that the local 
distribution provision of section 201 must be given effect. However, 
the Supreme Court in both CL&P and Colton, supra, has stated that 
whether facilities are used in local distribution is a question of 
fact to be decided by the Commission as an original matter. Thus, 
there is no clear case law on a ``bright line'' between transmission 
and local distribution. In addition, regardless of the details of 
the chain of delivery services necessary to move electric energy 
from the generator to the end user, in most cases the last public 
utility in the chain will use facilities that historically were 
considered local distribution facilities. Accordingly, unlike the 
situation involving unbundled wholesale wheeling, for which the case 
law clearly supports a ``functional'' test, the Commission believes 
the case law and practical realities of a changing industry support 
an analysis of local distribution facilities based on the 
facilities' functional as well as technical characteristics.
    While it would be preferable to draw an absolutely ``bright'' 
line (e.g., based on technical characteristics such as voltage), the 
Commission does not believe this is required by the case law and, 
importantly, would not be a workable approach in all cases because 
of the variety of circumstances that may arise and because utilities 
themselves classify facilities differently (e.g., one utility may 
classify a 69 kV facility as transmission; another may classify it 
as distribution).
    Therefore, the Commission is adopting several indicators it will 
evaluate in determining whether particular facilities are 
transmission or local distribution in the case of vertically 
integrated transmission and distribution utilities: \99\
---------------------------------------------------------------------------

    \99\ In the case of a distribution-only utility, which is 
franchised by a State or local government and sells only at retail, 
all of the circuits (and related wires, transformers, towers, and 
rights of way) which it owns or operates (regardless of voltage) 
would be local distribution facilities.
---------------------------------------------------------------------------

    <bullet> Local distribution facilities are normally in close 
proximity to retail customers.
    <bullet> Local distribution facilities are primarily radial in 
character.
    <bullet> Power flows into local distribution systems, it rarely, 
if ever, flows out.
    <bullet> When power enters a local distribution system, it is 
not reconsigned or transported on to some other market.
    <bullet> Power entering a local distribution system is consumed 
in a comparatively restricted geographical area.
    <bullet> Meters are based at the transmission/local distribution 
interface to measure flows into the local distribution system.
    <bullet> Local distribution systems will be of reduced 
voltage.\100\
---------------------------------------------------------------------------

    \100\ The Commission has analyzed utilities' filings required by 
the Commission's regulations. These filings are made on FERC Form 
No. 1. While there is no uniform breakpoint between transmission and 
distribution, it appears that utilities account for facilities 
operated at greater than 30 kV as transmission and that distribution 
facilities are usually less than 40 kV.
---------------------------------------------------------------------------

    In summary, for unbundled wholesale wheeling the Commission will 
apply a

[[Page 21732]]

functional test. The only definitive question will be whether the 
entity to whom the power is delivered is a lawful wholesaler. For 
unbundled retail wheeling the Commission will apply a combination 
functional-technical test that will take into account technical 
characteristics of the facilities used for the wheeling. The 
Commission concludes that these tests are consistent with the FPA, 
---------------------------------------------------------------------------
its legislative history and the case law discussed above.

BILLING CODE 6717-01-P
[GRAPHIC] [TIFF OMITTED] TR10MY96.000


BILLING CODE 6717-01-C

     Appendix H.--Table ES-2.--National Emissions of NO<INF>X <INF>as <INF>Projected <INF>in <INF>Both <INF>Base <INF>Cases <INF>and <INF>All <INF>Proposed <INF>Rule  
                                                    <INF>Scenarios                                                   
                                                 [Thousand tons]                                                
----------------------------------------------------------------------------------------------------------------
                                                Under assumption that        Under assumption that gas prices   
                                                relative gas and coal        increase compared to coal prices   
                                               prices remain constant   ----------------------------------------
                                            ----------------------------                                        
                    Year                                   Competition-                Competition-      Low    
                                               Constant     favors-gas    High-price-   favors-coal    response 
                                                price-       proposed    differential    proposed      proposed 
                                             differential      rule        base case       rule          rule   
                                               base case     scenario                    scenario      scenario 
----------------------------------------------------------------------------------------------------------------
1993.......................................         5,844         5,844         5,844         5,844        5,844
2000.......................................         5,362         5,255         5,672         5,763        5,743
2005.......................................         5,579         5,449         6,053         6,108        6,056
2010.......................................         5,772         5,638         6,426         6,519        6,426
----------------------------------------------------------------------------------------------------------------


[[Page 21733]]



Promoting Wholesale Competition Through Open Access Non- Discriminatory 
Transmission Services by Public Utilities

Recovery of Stranded Costs by Public Utilities and Transmitting 
Utilities

(As corrected April 25, 1996)

[Docket No. RM95-8-000; Docket No. RM94-7-001]

Issued April 24, 1996.
    HOECKER, Commissioner, concurring in part and dissenting in 
part:

General Observations

    A. Four years and untold numbers of conferences, studies, and 
speculations after the Energy Policy Act, the Commission today takes 
a major step in bringing competition to the wholesale bulk power 
market in the United States. Order No. 888 (FERC Stats. & Regs. 
para. 31,036), together with our order establishing an open access 
same-time information system (OASIS) (Order No. 889, FERC Stats. & 
Regs. para. 31,037) and our proposal to conform all transmission 
tariffs to a uniform capacity reservation system (FERC Stats. & 
Regs. para. 32,517), will set in motion a dynamism seldom witnessed 
in the electric power business. In that sense, the organizational, 
operational, and economic consequences of the requirements we adopt 
today defy prediction. I believe nevertheless that the Commission's 
Final Rule today is a sound and reasoned decision about the industry 
as we now know it and as we think it may evolve. I therefore 
announce my unequivocal support for the order's basic tenets as we 
have chosen to implement them--the unbundled wholesale utility 
services, open and non-discriminatory access to transmission and to 
information about transmission, service comparability, an 
opportunity for increased competition among generation sources, 
coordination with and deference to state regulatory interests, and 
full recovery of eligible stranded investments.
    B. Restructuring the electric power industry is a matter of 
national interest and priority. Electricity is ubiquitous. Its 
benefits are key to the American quality of life. Operating 750,000 
MW of generation capacity arrayed across three synchronous regional 
transmission grids, the electric industry is the nation's most 
capital intensive. The 179 largest investor-owned utilities alone 
control nearly $600 billion in assets. And, total electricity 
revenues constitute between 3 and 4 percent of the gross domestic 
product (GDP)--larger than telecommunications, natural gas pipeline, 
and airline revenues combined.
    Both the Congress and the President have recognized our 
obligation to ensure that these resources are used wisely and 
efficiently. We all recognize that systemic change is happening 
within the industry and that regulation must change to take maximum 
advantage of the most constructive of those forces. ``At the center 
of the success of our economy is the market, and at the core of the 
success of the market is competition,'' states the President in his 
1996 Economic Report to the Congress; ``it is competition that 
drives down costs and prices, induces firms to produce the goods 
consumers want, and spurs innovation and the expansion of new 
markets abroad.'' Yet, as state and local governments consider the 
future of industries heretofore heavily regulated in the public 
interest, deregulation is not enough, states the President. 
Competition must be actively promoted and preserved from the abuses 
and distortions associated with monopoly power, as well as from 
outdated forms of regulation that provide inappropriate incentives.
    In the electric utility restructuring process, several difficult 
challenges must still be met here and elsewhere. First, policymakers 
must make the tough choices to attack access discrimination and 
promote competition while also ensuring reliability and economical 
service. Success in these undertakings may require pricing 
innovation and structural reforms to attain significant long-run 
gains in efficiency and productivity. Economic Report, at 183-185. 
Second, no transition to a new regime of operating rules and 
assumptions, can be achieved reasonably if regulated companies are 
shorn of the opportunity to recover prudently incurred costs. 
Utility investments that may become stranded or uneconomic as 
competitive choice displaces franchise monopoly are estimated to 
represent a $100 billion-plus risk for public utilities. State and 
federal regulators must confront this issue in the interest of 
equity and a swift readjustment to the new competitive realities. As 
the President's Economic Report makes clear, it will be important to 
future suppliers of private capital for public use that a regulatory 
bargain made must remain a bargain kept. ``Credible government is 
key to a successful market economy, because it is so important for 
encouraging long-term investments.''  Id., at 186-188. Third, 
maintaining competitive parity and environmental protection are key 
challenges as well. That means, among other things, that 
environmental policy must respond to the environmental risks 
associated with restructuring and vice versa. Id., at 188-189. This 
assessment of the realities and challenges facing this Commission, 
its state counterparts, and the diverse elements of the industry 
substantially ratifies the Commission's actions today.
    C. The long-run prospect for reform of the wholesale market is 
promising, though the task seems daunting. The preamble to the Final 
Rule begins by outlining the difficult issues that await this 
Commission and the industry: (1) Corporate organizational matters, 
including the role of independent system operators (ISOs) in 
promoting more efficient operation of the transmission system on a 
regional basis; (2) the need for a new merger policy, which I 
believe must be predicated on a thorough understanding of emerging 
markets and genuine ratepayer protections instead of a subjective 
tally of supposed ``benefits''; and (3) further efforts to make 
greater use of flow-based pricing where appropriate. In adopting the 
OASIS requirements, we have taken a first step in recognizing that 
competitive markets do not consist of wires and turbines alone, but 
of information also. Full competition requires the consolidation of 
the electron transportation system with the electronic information 
superhighway.
    One thing is abundantly clear: restructuring will require 
continued innovation and fortitude from our capable staff, 
cooperation from state regulators, patience and foresight from 
legislators and, most of all, creativity, responsiveness, and 
endurance from both utility management and electric consumers.

II. Concurrence on Specific Issues

    The Final Rule resolves certain matters of policy and law in 
ways which, despite my fundamental agreement, I would like to offer 
some additional perspectives.

A. Coordinating State and Federal Regulatory Interests

    Perhaps no single issue will influence the success or failure of 
restructuring as will the capacity of the FERC and state regulators 
to reach meaningful accommodations as the electric utility industry 
becomes increasingly subject to competitive forces. The vertical 
organization and technological integration of the electric power 
business contributes to the impression of a regulatory system 
riddled with gaps and overlaps, interregional inequities, and 
uncertainty. To the extent that impression predominates in the 
months to come, the pressure from legislators and the financial 
community to devise single-minded national solutions to issues of 
regional or local significance will likely prove irresistible.
    The regulation of this industry is a unique exercise in 
federalism. The Deputy Secretary of Energy wisely acknowledged 
months ago that, ``the aftermath of FERC's open access rulemaking 
will put to the test our ability to evolve improved means for 
unsnarling the governance problems of federal and state 
authorities.'' Charles B. Curtis, Remarks Before the Third DOE/NARUC 
National Symposium, December 4, 1995. I find no shortage of good 
ideas on how to achieve better state, federal, and inter-regional 
cooperation. But, unanswered questions persist about the 
availability of sufficient political will and leadership to achieve 
electricity markets that at once satisfy the need for operational 
efficiency on a regional level and also provide the ``opportunity 
for experimentation and market testing with the flexibility to 
comprehend local differences * * * [that is] the very genius of the 
federal system.'' Id.
    Although it remains unclear today whether this challenge will be 
met, I firmly believe that the Final Rule is a sound resolution of 
the jurisdictional questions facing this Commission as a result of 
competition and open access. State PUC comments reflect enormous 
concern about the potential loss of jurisdiction over some wires and 
services, if and when ``retail transmission'' becomes unbundled. 
States raise legal objections to our claim of jurisdiction. While 
reaffirming our view that the Commission has exclusive jurisdiction 
over the rate, terms, and conditions of interstate transmission, 
today's order addresses state concerns squarely--first, by adhering 
to the practical distinctions between transmission and distribution 
set forth in the NOPR and, second, by according deference <SUP>1 to 
states where appropriate when

[[Page 21734]]

retail transmission services become subject to a FERC tariff. These 
accommodations will smooth the transition to a seamless competitive 
market with full customer choice, if and when individual states 
initiate retail competition.
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    \1\ The Commission leaves unexplored the precise meaning of 
``deference'' in these circumstances. At one extreme, it could mean 
courteous regard for another's views and, at the other, binding 
submission to another's judgment. I would, for example, accord state 
views on cost allocation considerable or presumptive, but not 
conclusive, weight.
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    While the Final Rule, not unexpectedly, manifests this 
Commission's strong interest in preventing balkanization of the 
interstate power market, nothing adopted by the Commission today, 
including the interpretation of its authority over retail 
transmission when retail service is unbundled, is inconsistent with 
the traditional state roles in developing regulatory, social, and 
environmental requirements and programs suited to the circumstances 
of their localities. Section I of the Final Rule is emphatic about 
this.
    I will conclude with two observations on matters I believe to be 
of particular sensitivity to the states. First, it appears to me 
that state regulators may impose distribution and other non-
bypassable charges or other retail requirements on direct access 
services, even in those circumstances where no distribution 
facilities can be identified under the functional/technical test. 
The Final Rule ensures that result by acknowledging state authority 
over distribution-related services under the FPA.
    Second, state authority is traditionally employed to ensure that 
power production conforms to local economic, environmental, and 
resource diversity policy preferences. A state may wish, for 
example, to ensure that a direct access industrial customer is no 
less obligated to purchase power consistent with the resource 
diversity or environmental requirements than is that customer's 
franchise distribution utility. To the extent that state 
requirements to own or purchase a certain amount of generation from, 
say, renewable sources are enshrined in utility supply portfolios, 
those states have direct influence on the economic and environmental 
consequences of energy consumption in that jurisdiction. Moreover, 
such requirements ought to be compatible with open access 
transmission. However, it will be important that state authority 
over resource procurement be exercised on a not unduly 
discriminatory basis. In other words, a PUC may not treat in-state 
and out-of-state suppliers differently. If access over the network 
is non-discriminatory in nature, the federal regulatory and 
constitutional interests are arguably satisfied.

B. Environmental Effects of Restructuring

    1. Last July, we instructed our staff to prepare an 
Environmental Impact Statement (EIS) in conjunction with this 
rulemaking. The Final EIS (FEIS), issued on April 12, 1996, is an 
impressive and, with respect to the air impacts of electric 
restructuring, a pioneering work. It considers in detail: (1) The 
possible environmental consequences of adopting this Rule, including 
a number of additional analyses requested by commenters, (2) 
alternative methods of pursuing open access transmission service, 
(3) a range of environmental mitigation actions proposed by 
commenters, and (4) the Commission's legal and technical ability to 
undertake environmental mitigation. On the whole, I find staff's 
studies to be analytically sound and generally in conformance with 
my understanding of this agency's powers to engage in environmental 
mitigation. Moreover, its conclusions and recommendations are 
thoughtful and well-reasoned. I therefore believe that consideration 
of the FEIS as part of the Commission's actions today meets our 
National Environmental Policy Act of 1969 (NEPA) obligations <SUP>2 
and the requirement of reasoned decisionmaking.
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    \2\ NEPA (42 U.S.C. 4321-4370), the Council on Environmental 
Quality's (CEQ) regulations promulgated thereunder (40 CFR parts 
1500-1508 (1995)), and our own environmental regulations 
supplementing those of CEQ (18 CFR part 380 (1995)) together 
establish an important procedural mechanism that was designed, not 
to impose upon this Commission substantive duties to achieve 
particular results, but to infuse our decisional processes with a 
broad awareness of the environmental consequences of our actions. 
Under NEPA, the Commission must in any applicable instance consider 
and weigh its core objectives and responsibilities under the Federal 
Power Act and the impacts of its actions on all aspects of the human 
environment--economic and social as well as ecological. This 
exercise requires the Commission to ascertain the availability and 
consider the feasibility of alternative approaches with lesser 
impacts. In other words, the Commission's duty is to take a ``hard 
look'' at the environmental effects of its major actions. Robertson 
v. Methow Valley Citizens Council, et al., 490 U.S. 332 (1988); 
Strycker's Bay Neighborhood Council, Inc. v. Karlen, et al., 444 
U.S. 223 (1980). The EIS process fulfills that requirement.
---------------------------------------------------------------------------

    The FEIS highlights a very important public health and social 
welfare issue, not to mention a matter of great financial importance 
to certain utilities. To be specific, the FEIS examines potential 
air quality impacts in the event generation increases from certain 
coal-fired units. Open transmission access is expected by some to 
stimulate that additional generation and hence additional nitrogen 
oxide (NO<INF>X) emissions and related ozone formation. From these 
projections, a substantive and not altogether constructive debate 
has ensued. As Section V of the Final Rule describes more fully, the 
Commission conducted additional studies to respond to comments on 
the draft EIS, using new recommended baselines for comparison. The 
results confirm that the air quality impacts of the rule are within 
reason.
    The Commission has satisfied itself that the three most pressing 
questions have been addressed: (1) What increment of the NO<INF>X 
emissions problem may be attributable to this Final Rule? (2) Will 
Final Rule-induced NO<INF>X emission increases be so significant and 
their impacts sufficiently adverse to justify an alternative 
regulatory approach, such as ``no action'' on utility restructuring? 
(3) Short of no action, can the Commission undertake direct actions 
that mitigate any potential adverse effects? Based on the FEIS, I 
can find no justification in the cause, size, or certainty of near-
term emissions increases for delaying or diluting the Open Access 
Rule and no clear basis for a FERC-sponsored emissions control 
regime, even on an interim basis.
    2. Having discharged our NEPA obligations, I cannot pretend that 
this matter of public interest is no longer of any interest or 
concern to us. Clean air is a birthright. Air emissions are 
therefore an important concern. I would not relegate this issue to 
the periphery of our deliberations. If the EIS process accomplishes 
nothing else, it has familiarized the FERC with the difficulties of 
addressing the seemingly intractable problem of NO<INF>X emissions. 
The problem engenders interregional economic and environmental 
conflicts that can be addressed only by a sophisticated balancing of 
interests and a selfless commitment to the greater good. EPA and 
several commenters on our Rule express frustration over the progress 
being made to reduce NO<INF>X emissions. For this and other 
environmental issues, such as NO<INF>X waivers, resort to the courts 
has become customary, and complex technological and economic 
disputes are the norm. See e.g., Electric Power Alert, April 24, 
1996, at 29-30.
    Regions of the country differ, often vehemently, about the 
source and effects of ozone-causing emissions and how best to curb 
the generation and transport of pollutants that create ozone. 
Utilities in some regions have made commitments and invested heavily 
to achieve ``attainment'' levels, while the blessings of geography 
and circumstance have imposed no such burden on others. We recognize 
in essence that reconciling these interests is a task the Congress 
has assigned to the EPA. Although the Clean Air Act authorizes EPA 
to develop a national program to enforce emissions reduction largely 
through state environmental regulatory efforts (the so-called State 
Implementation Plans (SIPs)), the statutory process is ponderous in 
practice. Moreover, even where gains are expected to be made in the 
form of reduced NO<INF>X emissions (e.g., under EPA's pending 
rulemaking to set NO<INF>X emissions limitations for certain types 
of utility boilers), those gains might arguably be offset by future 
increases in the demand for electricity or, according to some 
parties, by the additional power generation some say will be 
encouraged by open access transmission.
    The inability to guarantee future NO<INF>X reductions for a 
variety of reasons that range well beyond this Rule presents 
formidable challenges. EPA places great faith in the ability of the 
Ozone Transport Assessment Group (OTAG), a voluntary multi-state 
organization established in part to set up NO<INF>X emission 
mitigation mechanism, to address these complex issues and achieve a 
resolution. It nevertheless appears to me that, for the most part, 
consensus remains distant. The alternative appears to be an even 
more protracted EPA procedure.
    With respect to the gravamen of this issue (i.e., the 
establishment of an emissions cap and credit trading system 
reminiscent of what Congress ordered for sulphur dioxide 
(SO<INF>2)), this Commission has no real choice but to defer to 
agencies with jurisdiction by law and special expertise. The EPA has 
done an outstanding job implementing the market-based SO<INF>2 
allowance program. It is widely regarded as both creative and 
successful.

[[Page 21735]]

OTAG, regardless of any concerns about its processes, brings 
together a broad range of regional interests, thereby offering an 
unprecedented opportunity for achieving consensus resolution of this 
difficult problem.
    3. In my view, it behooves this Commission to assist in any way 
it can, consistent with its expertise and authority, to find 
consensual solutions. I do not think that means denying polluting 
utilities access to the transmission system and thereby merely 
reinforcing their monopoly power. Rather, we must stand ready to 
assist EPA and OTAG in making competition and environmental 
responsibility equally attractive. We have begun providing that 
assistance by ensuring (see II.A. above) that state regulators 
retain their customary authority under state law to structure the 
generation and purchase power portfolios of state-regulated 
utilities. Moreover, the Commission has in the past addressed 
through its rate jurisdiction various public interest goals, 
including environmental concerns, intergenerational equities, and 
least-cost planning needs. For instance, in order to encourage 
capital investment in pollution control equipment and conservation, 
the Commission has long allowed utilities to include in rate base 
the costs of ``construction work in progress'' (CWIP) for pollution 
control devices and fuel conversion measures that discourage use of 
certain fossil fuels.<SUP>3 In addition, utilities are not eligible 
for CWIP treatment for plant construction not shown to be the 
product of integrated resource planning.<SUP>4
---------------------------------------------------------------------------

    \3\ 18 CFR 35.25 (1995).
    \4\ 18 CFR 35.13(h)(38) (1995).
---------------------------------------------------------------------------

    With respect to the NO<INF>X issue specifically, the Commission 
is competent to help facilitate an emissions cap and trading system. 
For instance, the accounting treatment provided for the cost of 
SO<INF>2 emissions allowances in rates was done to assist 
implementation of the Clean Air Act.<SUP>5 The same accommodations 
could be instituted for a NO<INF>X program. Perhaps the greatest 
potential for DOE-EPA-OTAG-FERC collaboration and consultation 
involves our knowledge of the industry and, after preparing the 
FEIS, our familiarity with the NO<INF>X problem itself. That 
information should be useful beyond the confines of this rulemaking. 
In addition, the FEIS indicates (at p. 7-22) that we can structure 
the electronic bulletin board systems we require so as to facilitate 
the posting of emissions data required by EPA.
---------------------------------------------------------------------------

    \5\ Revisions to Uniform Systems of Accounts to Account for 
Allowances under the Clean Air Act Amendments of 1990, Order No. 
552, III FERC Statutes and Regulations para.30,967 (1993).
---------------------------------------------------------------------------

    4. Based upon the mutual concerns and the different but 
complementary expertise of the affected agencies, I encourage the 
development of consultative mechanisms, memoranda of understanding, 
or other procedures that will support and help ensure the success of 
OTAG's efforts. Such efforts must be consistent with the goals and 
allocation of responsibilities under the Clean Air Act, and our own 
regulatory role. Restructuring may pose some environmental risks. We 
think they are small and (at least eventually) manageable. Further 
experience is likely to demonstrate that restructuring opens up new 
possibilities for addressing longstanding environmental problems 
associated with utility operations. Open access enhances the 
prospects for environmental dispatch on a statewide or regional 
basis. It gives isolated renewable plants, particularly 
hydroelectric and wind power units that are tied to specific 
geographical features, better market access. I must note that 
investments in DSM and renewable resources, which offer relatively 
stable costs, may be an attractive component of utilities' 
generation portfolios because they also minimize risks. And, as 
restructuring makes electricity a more customer-driven business, the 
public's documented preference for environmentally benign power will 
become more powerful. In addition, efficient markets provide the 
necessary means to ``marketize'' environmental rules and perhaps to 
modify siting and other regulatory processes that are predicated on 
the vertical integration of the utility sector. And, finally, energy 
services companies that can promote conservation and generation 
alternatives require more open and dynamic markets. For the 
environment, the prospects offered by restructuring are exciting. 
Inhibiting or stopping its development will not help it.

III. Partial Dissent

    The Final Rule announces that the Commission will be the 
``primary forum'' to hear stranded cost claims where a retail power 
customer turns wholesale wheeling customer, usually through a 
municipalization (Situation 2). Although the Final Rule recognizes 
that states do have authority to deal with stranded costs in 
Situation 2, the majority nevertheless instructs parties to bring 
their claims to this Commission ``in the first instance.'' However, 
where costs are stranded due to state authorized retail wheeling 
(Situation 3), the majority takes a different and, I contend, 
incongruent approach that effectively denies any forum for those 
costs if state regulators possess authority to act but do not do so. 
Because I find nothing in policy or law to commend this approach, I 
respectfully dissent.<SUP>6
---------------------------------------------------------------------------

    \6\ My views conform generally to Commissioner Massey's partial 
dissent today.
---------------------------------------------------------------------------

    I take issue with the ``primary forum'' approach because I 
believe that it: (1) Requires the Commission to second-guess state 
determinations on recovery of costs incurred at retail at a time 
when many states are addressing the issue; (2) will encourage forum 
shopping; and (3) is inconsistent with our approach in the retail 
wheeling situation; and (4) involves an unnecessary legal risk for 
the Commission.

A. Second-Guessing State Determinations of Retail Stranded Costs is 
Unwise and Unnecessary

    The Final Rule's stranded cost recovery methodologies and the 
underlying jurisdictional assumptions are aimed at achieving full 
recovery of all legitimate, verifiable and prudent stranded costs, 
consistent with a utility's reasonable expectations and the justness 
and reasonableness of the underlying contract. I believe that this 
is a worthy objective, but it is not one which requires the 
Commission to second-guess state determinations. As state 
proceedings now reveal, the Commission's leadership in raising this 
issue has borne fruit. Where municipalization is occurring, states 
are addressing stranded costs responsibly. In nearby Virginia, for 
example, the Virginia State Corporation Commission has interceded 
into the dispute between Virginia Electric Power Company and the 
City of Falls Church over the City's plans to undertake a ``muni-
lite'' form of municipalization. Moreover, the record before us 
today does not endorse the view that municipalization constitutes a 
major bypass threat to stranded cost recovery.
    Notwithstanding such developments, the Final Rule announces that 
the Commission will be the ``primary forum'' to hear stranded cost 
claims where a retail power customer turns wholesale wheeling 
customer, usually through a municipalization. While declaration of 
``primary forum'' status sounds very legalistic, there is in fact no 
legal basis for it. The policy is not founded on a concept of 
federal preemption in the area. Indeed, the Federal Power Act 
provides no basis for preemption. Moreover, the Final Rule 
recognizes that states do have authority to deal with stranded costs 
in these circumstances. The majority's instruction to bring claims 
directly to FERC will, if anything, afford states a reason to avoid 
this difficult issue altogether.

B. The ``Primary Forum'' Approach May Encourage Forum Shopping

    As a policy matter, the majority's approach is peculiar on its 
face. Although the ``primary forum'' approach is intended to 
eliminate forum shopping, it will not achieve even that objective. 
Indeed, I think the ``primary forum'' approach may encourage parties 
to forum shop. State commissions or legislatures will often provide 
for stranded cost recovery at the time the wholesale entity is 
formed. Similarly, condemnation proceedings may provide for stranded 
costs in whole or part. Moreover, standards for stranded cost 
recovery are occasionally prescribed by statute. In reality, the 
Commission cannot preclude the states from acting on stranded cost 
issues and our proposed rule may encourage rather than discourage 
forum shopping.

C. The ``Primary Forum'' Approach Covers Fact Situations Largely 
Indistinguishable From the Retail Wheeling Scenario

    The majority's decision to take primary jurisdiction of costs 
where a retail power customer becomes wholesale wheeling customer 
through municipalization and to distance itself from virtually any 
cost recovery responsibility where retail power customers becomes 
retail wheeling customers does not withstand scrutiny. These are not 
factually distinguishable cases, insofar as jurisdiction over 
stranded costs is concerned. The inadequacy of the majority's 
reasoning is palpable because it has adopted very different policies 
with respect to two stranded cost situations that, if properly 
understood, are virtually indistinguishable.

[[Page 21736]]

    First, in both Situations 2 and 3, retail power costs are 
stranded by customers who gain access to FERC jurisdictional 
transmission tariffs via state action. In Situation 2, state 
municipalization law governs. In Situation 3, the state has 
authorized retail wheeling by statute or regulation, or both. 
Notwithstanding the need for state authorization in both cases, the 
majority decides that the Commission should be the ``primary forum'' 
in Situation 2, but that a much more narrow approach to retail 
stranded costs in Situation 3.<SUP>7 The more aggressive ``primary 
forum'' approach to municipalization is predicated on the view that 
any strandings are a result of an inducement (i.e., market options) 
created by this Commission's Open Access Rule. Yet, since both 
wholesale transmission customers and retail transmission customers 
are ``eligible customers'' under the tariffs required by this Rule, 
if the Rule induces the stranding of retail power costs in one 
situation, it obviously does it in both.
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    \7\ The policy adopted with respect to Situation 3 is that the 
Commission would only be a forum for hearing stranded costs issues 
in the narrow circumstance where ``the state regulatory authority 
does not have authority under state law to address stranded costs 
when the retail wheeling is required.'' The majority fails to 
address what would happen if a legislature addresses the issue of 
stranded costs directly without delegating the task to a state 
regulatory authority. I would hope that the Commission would not set 
itself up for confrontation with a state legislature and I would 
have preferred that to also exclude those circumstances ``where the 
state otherwise addresses the issue'' from the circumstances in 
which the Commission would act in Situation 3.
---------------------------------------------------------------------------

    As commenters have noted, the relationship between FERC-
regulated transmission service and retail power customers is 
generally the same in both Situations 2 and 3.<SUP>8 The similarity 
runs first to the actions that actually cause costs to be stranded. 
While it is true that retail wheeling will only occur pursuant to 
state legislative or regulatory action, it is also true that a 
retail customer can only convert to wholesale status (e.g., 
municipalize) pursuant to state law. This process sometimes may 
occur in the absence of regulatory or other oversight (e.g., 
municipalization under pre-established statutory scheme), or with 
direct and immediate review and approval. The current evidence 
reflects active state commission oversight, typically. In this 
latter case, there is even less reason to distinguish between these 
Situations.
---------------------------------------------------------------------------

    \8\ This argument is made both by commenters arguing that the 
Commission has no jurisdiction over stranded costs in Situation 2 or 
3 (California Public Utilities Commission Initial Comments at 7) and 
by commenters arguing that the Commission should assert primary 
jurisdiction over stranded costs in both Situations (see e.g., 
Edison Electric Institute Initial Comments at IV-13; Coalition For 
Economic Competition Initial Comments at 22; Utilities For An 
Improved Transition Initial Comments at 16-26).
---------------------------------------------------------------------------

    The majority implicitly seeks to delimit the area of appropriate 
state authority over stranded costs according to whether the state 
acts directly and by current enactments to authorize retail 
wheeling, on one hand, or less directly through established state 
municipalization laws, on the other. However, costs could be 
stranded under state law by either action. Under the former 
scenario, however, a state is presumed to be more willing and 
capable of dealing with stranded costs. Under the latter, it is 
presupposed to be less interested. This distinction is specious.
    A second similarity pertains to the jurisdictional status of 
transmission service. The Commission has been clear and consistent 
that the FPA gives the Commission exclusive jurisdiction over 
interstate transmission service, regardless of whether the customer 
is a wholesale or a retail wheeling customer. It is this authority 
upon which we rely to claim jurisdiction over transmission assets 
and related costs originally incurred to provide customers at the 
retail level with bundled service. New wheeling customers in both 
Situations 2 and 3 will take service under FERC open access tariffs. 
There are identical cost-causational facts in Situations 2 and 3, 
yet the majority adopts very different outcomes in each case under 
the Final Rule.

D. The ``Primary Forum'' Approach is More Subject to Legal 
Challenge

    In my view, our disagreement involves more than a policy choice. 
The majority's chosen approach clearly makes our stranded cost 
recovery approach more vulnerable to a legal challenge. The cost 
recovery scheme which would result from the majority's approach will 
render a FERC-ordered transmission surcharge to recover retail 
stranded costs susceptible to legal challenge on the basis that it 
is anti-competitive and unduly discriminatory. The ``primary forum'' 
approach imposes upon a retail-turned-wholesale customer something 
akin to double jeopardy. In other words, a departing customer might 
have to pay both an exit fee for the retail costs which the state 
commission finds it has stranded and, in addition, an entry fee for 
wholesale access in the amount of the additional retail stranded 
costs which FERC determines are inadequately covered by state 
proceedings.
    This, in my view, makes the Final Rule more susceptible to 
challenges that FERC's transmission surcharge is anti-competitive. 
E.g., Cajun Electric Power Cooperative, Inc. v. FERC, 28 F.3d 173 
(D.C. Cir. 1994). The second-guessing of states inherent in the 
``primary forum'' approach makes any arguments that stranded cost 
recovery is anti-competitive more difficult to overcome than if the 
stranded costs resulted from wholesale customers simply changing 
wholesale suppliers. This is because, unlike wholesale-to-wholesale 
strandings, the Commission cannot plausibly argue that the costs 
incurred were originally addressed in the context of its own rate 
decisions or were previously part of its responsibility for 
administering wholesale service obligations.
    I am strongly persuaded that the Commission would be on much 
stronger legal ground if we were to treat state authority over 
stranded costs with the same deference in the municipalization or 
``retail-turned-wholesale'' situation in the same manner as the 
Final Rule prescribes for situations where retail wheeling occurs. 
In the latter case, the Commission ought to provide a forum where 
neither the state legislature nor the state commission attempts to 
address this important transition issue.
James J. Hoecker,
Commissioner.

Promoting Wholesale Competition Through Open Access Non-Discriminatory 
Transmission Services by Public Utilities

Recovery of Stranded Costs by Public Utilities and Transmitting 
Utilities

[Docket No. RM95-8-000; Docket No. RM94-7-001]

Issued April 24, 1996.
    MASSEY, Commissioner, dissenting in part:
    I support all of the provisions of this rule save one, the 
provision on stranded costs arising from retail competition and from 
municipalization. When the Commission issued the Notice of Proposed 
Rulemaking, I stated that the Commission should treat stranded costs 
arising from retail competition and municipalizations similarly, as 
follows:
    For either retail competition or municipalization, when the 
state commission has authority to address the issue, and uses such 
authority to decide the recoverability of the stranded costs, the 
state's decision should not be second-guessed by this Commission. 
However, when a state commission does not have the authority to 
decide the recoverability of stranded costs, or has authority but 
does not use it, this Commission should act on requests for stranded 
cost recovery.
    My approach would assure utilities of getting a decision on the 
merits of their claim. Costs would not be stranded for lack of a 
regulatory decision. At the same time, this Commission would allow 
states to make decisions, when they have authority, on issues of 
critical concern to their local utilities and ratepayers. Only if 
states lack, or fail to use, such authority would this Commission 
step in to assure the utility of receiving a decision on the merits.
    For the reasons I stated then, I still disagree with the rule's 
approach to stranded costs arising from retail competition or 
municipalization. In all other respects, I support this rule.
William L. Massey,
Commissioner.
[FR Doc. 96-10694 Filed 5-9-96; 8:45 am]
BILLING CODE 6717-01-P