[Federal Register Volume 60, Number 67 (Friday, April 7, 1995)]
[Proposed Rules]
[Pages 17662-17726]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 95-8534]



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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket Nos. RM95-8-000 and RM94-7-001]


Promoting Wholesale Competition Through Open Access Non-
discriminatory Transmission Services by Public Utilities, Recovery of 
Stranded Costs by Public Utilities and Transmitting Utilities; Proposed 
Rulemaking and Supplemental Notice of Proposed Rulemaking

March 29, 1995.
AGENCY: Federal Energy Regulatory Commission.

ACTION: Notice of proposed rulemaking and supplemental notice of 
proposed rulemaking.

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SUMMARY: The Federal Energy Regulatory Commission (Commission) is 
proposing to require that public utilities owning and/or controlling 
facilities used for the transmission of electric energy in interstate 
commerce have on [[Page 17663]] file tariffs providing for non-
discriminatory open access transmission services. The Commission is 
also proposing to permit public utilities and transmitting utilities to 
recover legitimate and verifiable stranded costs. The Commission's goal 
is to encourage lower electricity rates by structuring an orderly 
transition to competitive bulk power markets. The Commission is seeking 
public comment on its proposals.

DATES: Written comments must be received by the Commission by August 7, 
1995. Reply comments must be received by the Commission by October 4, 
1995.

FOR FURTHER INFORMATION CONTACT:
David D. Withnell, Office of the General Counsel, Federal Energy 
Regulatory Commission, 825 North Capitol St., NE., Washington, DC 
20426, telephone: (202) 208-2063, (Docket No. RM95-8-000--legal 
issues).
Deborah B. Leahy, Office of the General Counsel, Federal Energy 
Regulatory Commission, 825 North Capitol Street, NE., Washington, DC 
20426, telephone: (202) 208-2039, (Docket No. RM94-7-001--legal 
issues).
Michael A. Coleman, Office of Electric Power Regulation, Federal Energy 
Regulatory Commission, 825 North Capitol Street, NE., Washington, DC 
20426, telephone: (202) 208-1236, (technical issues).

ADDRESSES: Send comments to: Office of the Secretary Federal Energy 
Regulatory Commission 825 North Capitol Street, N.E. Washington, D.C. 
20426.
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 Room 3401, at 941 North 
Capitol 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. To access CIPS, set your communications 
software to 19200, 14400, 12000, 9600, 7200, 4800, 2400, 1200 or 
300bps, full duplex, no parity, 8 data bits and 1 stop bit. The full 
text of this document will be available on CIPS for 60 days from the 
date of issuance in ASCII and WordPerfect 5.1 format. After 60 days the 
document will be archived, but still accessible. 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 room 3104, 941 North Capitol Street, NE., Washington, DC 20426.

    Promoting Wholesale Competition Through Open Access Non-
discriminatory Transmission Services by Public Utilities
Docket No. RM95-8-000
    Recovery of Stranded Costs by Public Utilities and Transmitting 
Utilities
Docket No. RM94-7-001

Notice of Proposed Rulemaking and Supplemental Notice of Proposed 
Rulemaking

March 29, 1995.

Table of Contents

I. Introduction
II. Public Reporting Burden
III. Discussion
    A. Summary of Authority and Findings
    B. Legal Authority
    1. Undue Discrimination/Anticompetitive Effects
    2. Section 211 Services
    C. Background
    1. Structure of the Electric Industry at Enactment of Federal 
Power Act
    2. Significant Changes in the Electric Industry
    3. The Public Utility Regulatory Policies Act and the Growth of 
Competition
    4. The Energy Policy Act
    5. The Present Competitive Environment
    a. Use of Sections 211 and 212 to Obtain Transmission Access
    b. Commission's Comparability Standard
    c. Lack of Market Power in New Generation
    d. Further Commission Action Addressing a More Competitive 
Electric Industry
    D. Need for Reform
    1. Market Power
    2. Discriminatory Access
    3. Analogies to the Natural Gas Industry
    4. Coordination Rates
    E. The Proposed Regulations
    1. Non-discriminatory Open Access Tariff Requirement
    2. Implementing Non-discriminatory Open Access: Functional 
Unbundling
    3. Real-time Information Networks
    4. Non-discriminatory Open Access Tariff Provisions
    5. Pro Forma Tariffs
    6. Broader Use of Section 211
    7. Status of Existing Contracts
    8. Effect of Proposed Rule on Commission's Criteria for Market-
based Rates
    9. Effect of Proposed Rule on Regional
    Transmission Groups
    F. Stranded Costs and Other Transition Costs
    G. Transmission/Local Distribution
    H. Implementation
IV. Regulatory Flexibility Act
V. Environmental Statement
VI. Information Collection Statement
VII. Public Comment Procedures Regulatory Text

    Appendices (Appendices A, B and C will not be published in the 
Federal Register.)

A. Electric Utility Average Revenue Per Kilowatthour, by State
B. Point-to-Point Tariff
C. Network Tariff
D. List of Commenters in Docket No. RM94-7-000

I. Introduction

    The electric power industry is today an industry in transition. In 
response to changes in the law, technology, and markets, competitive 
pressures are steadily building in the industry. Once the primary 
domain of large, vertically integrated utilities providing power at 
regulated rates, the industry now includes companies selling 
``unbundled'' power at rates set by competitive markets. New generating 
facilities are being built at costs well below the average costs of 
some vertically integrated utilities. In this environment, more 
competition will mean lower rates for wholesale customers and, 
ultimately, for consumers.
    The Commission's goal is to encourage lower electricity rates by 
structuring an orderly transition to competitive bulk power markets. 
Development of such markets is certain. The questions are when and how. 
Experience has shown that competitive pressures cannot be contained for 
long without serious economic distortions. Competition will, we are 
confident, result in lower rates. But experience has also shown that a 
measured transition from regulated to competitive markets is absolutely 
essential.
    Moving to competitive generation markets will fundamentally change 
long-standing regulatory relationships. Utilities have invested 
billions of dollars in order to meet their obligations. Those 
investments have been made under a ``regulatory compact'' whereby 
utilities--and their shareholders--expect to recover prudently incurred 
costs. With the advent of competition, even prudent investments may 
become stranded. Reliance on past contractual and regulatory practices 
must be recognized and past investments must be protected to assure an 
orderly, fair transition to competition.
    The focus of our proposal today is to facilitate competitive 
wholesale electric power markets. The key to competitive bulk power 
markets is opening up transmission services. Transmission is the vital 
link between sellers and buyers. To achieve the benefits of robust, 
competitive bulk power markets, all wholesale buyers and sellers must 
have equal access to the transmission [[Page 17664]] grid. Otherwise, 
efficient trades cannot take place and ratepayers will bear unnecessary 
costs. Thus, market power through control of transmission is the single 
greatest impediment to competition. Unquestionably, this market power 
is still being used today, or can be used, discriminatorily to block 
competition.
    The Commission has an obligation to prevent unduly discriminatory 
practices in transmission access. In current circumstances, the absence 
of tariffs offering open access, non-discriminatory transmission 
services by each public utility impedes the transition to competitive 
markets greatly enough to be unduly discriminatory under section 206 of 
the Federal Power Act (FPA). Proceeding as we have in the past, case-
by-case, would delay unreasonably the transition to competitive 
markets. A patchwork of transmission systems--some open and some not--
would also lead to unfair practices and inequitable burdens.
    At the same time, while fulfilling our duty under section 206 of 
the FPA to cure undue discrimination, we see no need now to abrogate 
existing contractual relationships. Rather, we propose to provide a 
transition to a competitive generation industry that allows for the 
recovery of legitimate, prudent and verifiable costs lawfully incurred 
to serve customers under the terms of existing contracts. In the 
context of today's electric industry, the goals of increased 
competition and lower bulk power rates are best pursued through a 
structured transition rather than through abrogating all existing 
contracts.
    In short, at this crossroad for the industry, it is critical to 
take the regulatory steps now to facilitate the transition to 
competitive bulk power markets in an orderly manner. The most important 
of these steps are to ensure non-discriminatory access to the 
transmission grid for all wholesale buyers and sellers of electric 
energy in interstate commerce, and to address the transition costs 
associated with open transmission access. The Commission will take 
these steps in a manner consistent with maintaining the reliability of 
the interstate transmission grid.
    In this proceeding, the Commission pursuant to its authority under 
sections 205 and 206:

    <bullet> proposes to require all public utilities owning or 
controlling facilities used for transmitting electric energy in 
interstate commerce to file open access transmission tariffs;
    <bullet> proposes to require the utilities to take transmission 
service (including ancillary services) for their own wholesale sales 
and purchases of electric energy under the open access tariffs;
    <bullet> issues a supplemental proposed rule to permit the 
recovery of legitimate and verifiable stranded costs associated with 
requiring open access tariffs; and
    <bullet> proposes regulations to implement the filing of the 
open access tariffs and the initial rates under these tariffs.

    The open access tariffs--to be offered to all sellers and buyers of 
electric energy sold at wholesale in interstate commerce--must offer 
wholesale transmission services (network and point-to-point), including 
ancillary services, on a non-discriminatory basis to third 
parties.<SUP>1 In addition, the public utility must price separately 
all wholesale generation and transmission services (including ancillary 
services) and take wholesale transmission service under its own tariff, 
i.e., ``functionally unbundle'' its wholesale generation and 
transmission services. The proposed rule does not mandate the corporate 
separation of generation, transmission, and distribution functions.

    \1\Throughout this NOPR this requirement will be referred to as 
the ``non-discriminatory open access'' requirement.
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    The proposed rule proposes pro forma tariffs for network and point-
to-point services, defines non-discriminatory open access to include 
access to ancillary services, and requires that tariffs include a 
reciprocity provision requiring 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.
    To assure that the open access tariffs promote competition and do 
not operate in an unduly discriminatory manner, the proposed rule would 
require public utilities to provide all actual or potential 
transmission users the same access to information as the public utility 
enjoys. The Commission is proposing to develop industry-wide real-time 
information networks in a separate Notice of Technical Conference that 
is being issued concurrently with this proposed rule.<SUP>2

    \2\Notice of Technical Conference and Request for Comments, 
Docket No. RM95-9-000.
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    Not all transmitting utilities are public utilities subject to the 
Commission's jurisdiction under section 206 of the FPA.<SUP>3 The 
Commission cannot pursuant to section 206 require non-public utilities 
to file open access tariffs . Therefore, the proposed rule would 
encourage the broad application of section 211 as an additional means 
of achieving the goal in the Energy Policy Act of 1992 of promoting 
increased wholesale competition. Without broader application of section 
211, wholesale bulk power market participants could be denied access to 
more competitive generation sources to the detriment of consumers.

    \3\Section 206 of the FPA applies to public utilities, whereas 
section 211 applies to transmitting utilities. A public utility is 
defined under section 201(e) of the FPA as ``any person who owns or 
operates facilities subject to the jurisdiction of the Commission 
under this Part (other than facilities subject to such jurisdiction 
solely by reason of sections 210, 211, or 212).'' A transmitting 
utility is defined under section 3(23) of the FPA 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.'' Not all transmitting 
utilities are public utilities. For instance, a municipally-owned 
electric utility that owns transmission facilities that are used for 
the sale of electric energy at wholesale is a transmitting utility, 
but is not a public utility.
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    We presently do not find it necessary to use our authority under 
section 206 of the FPA to reform public utilities' existing 
requirements contracts or any other contracts to eliminate undue 
discrimination or attain more competitive bulk power markets. However, 
we seek information about existing requirements contracts, including 
the remaining life and notice provision in each such contract, and 
whether it would be in the public interest to modify any existing 
contracts.
    The Commission believes that the open access requirement will 
eliminate the transmission market power of public utilities by ensuring 
that all participants in wholesale power markets will have non-
discriminatory open access to the transmission systems of public 
utilities. This market power has been the Commission's primary concern 
in recent years in analyzing requests for market-based generation 
rates. We therefore seek comments on the effect of industry-wide non-
discriminatory open access on the Commission's criteria for authorizing 
power sales at market-based rates.
    The Commission's market-rate criteria also have included other 
aspects of market power, such as generation dominance. In particular, 
we note the Commission's recent KCP&L decision, in which we dropped the 
generation dominance standard for market-based sales from new 
capacity.<SUP>4 This rule proposes to codify that decision, and seeks 
comment on whether the generation dominance standard should also be 
dropped for market-based sales from existing capacity.

    \4\See Kansas City Power & Light Company, 67 FERC para. 61,183 
at 61,557 (1994) (KCP&L).
    In issuing this proposed rule, we are particularly concerned with 
its possible effect on stranded costs. It is important 
[[Page 17665]] to couple our open access rule with a rule ensuring 
recovery of all legitimate transition costs, consistent with the 
guidelines established herein. Accordingly, we are making preliminary 
findings with respect to the Stranded Cost NOPR issued on June 29, 
1994, seeking additional comments, and consolidating the Stranded Cost 
NOPR<SUP>5 with this proposed rule.

    \5\See Recovery of Stranded Costs by Public Utilities and 
Transmitting Utilities, Notice of Proposed Rulemaking, 59 FR 35274 
(July 11, 1994), IV FERC Stats. & Regs., Proposed Regulations 
para.32,507 (Stranded Cost NOPR).
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    Because of the benefits associated with the transition to a 
competitive regime, it is important to have the open access tariffs in 
place as soon as possible. Thus, we propose a two-stage procedure to 
accomplish that goal. In Stage One, we would place generic open access 
tariffs in effect simultaneously on a date certain for every public 
utility that owns and/or controls transmission facilities<SUP>6 and 
would establish rates for each public utility based on the most current 
Form No. 1 data available. In Stage Two, utilities would be free to 
propose changes to the rates, terms, and conditions in the generic 
tariffs and customers and others would be free to file complaints 
seeking changes in the rates, terms, and conditions. However, Stage Two 
tariffs must contain at least the non-price tariff terms and conditions 
contained in the pro forma tariffs.

    \6\Because power pools raise complex issues, we seek comments on 
how to implement the NOPR for power pools.
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    Comments of all interested persons should be filed pursuant to the 
procedures set out below.

II. Public Reporting Burden

A. Docket No. RM95-8-000

    The proposed rule specifies filing requirements to be followed by 
public utilities in making non-discriminatory open access tariff 
filings. The information collection requirements of the proposed rule 
are attributable to FERC-516 ``Electric Rate Filings.'' The current 
total annual reporting burden for FERC-516 is 784,488 hours.
    The proposed rule requires public utilities filing non-
discriminatory open access tariffs to provide certain information to 
the Commission. The public reporting burden for the information 
collection requirements contained in the proposed rule is estimated to 
average 300 hours per response. This estimate includes 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 
required information.
    There are approximately 328 public utilities, including marketers 
and wholesale generation entities. The Commission estimates that 
approximately 137 of these utilities own or control facilities used for 
the transmission of electric energy in interstate commerce and will 
respond to the information collection. The respondents would be all 
public utilities required to file non-discriminatory open access 
tariffs. These are the public utilities that are also transmitting 
utilities and either file Form 715 or have it filed on their behalf. 
The information will be provided with each filing by a respondent. 
Accordingly, the public reporting burden is estimated to be 41,100 
hours.
    Send comments regarding this burden estimate or any other aspect of 
the Commission's collection of information, including suggestions for 
reducing this burden, to the Federal Energy Regulatory Commission, 941 
North Capitol Street NE., Washington, DC 20426 [Attention: Michael 
Miller, Information Services Division, (202) 208-1415], and to the 
Office of Information and Regulatory Affairs of the Office of 
Management and Budget [Attention: Desk Officer for Federal Energy 
Regulatory Commission (202) 395-3087].

B. Docket No. RM94-7-001

    The initially proposed rule would require public utilities seeking 
to recover stranded costs to provide certain information to the 
Commission. The Commission estimated that the public reporting burden 
for the information collection requirements contained in the initially 
proposed rule would be 50 hours per response. The Commission also 
estimated that there would be ten respondents to the information 
collection annually.
    Under the proposed rule contained in this supplemental notice of 
proposed rulemaking, the information that public utilities will be 
required to file is not substantially different from that required by 
the initially proposed rule. The Commission also believes that the 
average filing burden and frequency of filing will be approximately the 
same as under the initially proposed rule. Therefore, the Commission 
estimates that there will be no additional public filing burden 
associated with the proposed rule.
    Send comments regarding this burden estimate or any other aspect of 
the Commission's collection of information, including suggestions for 
reducing this burden, to the Federal Energy Regulatory Commission, 941 
North Capitol Street, NE., Washington, DC 20426 [Attention: Michael 
Miller, Information Services Division, (202) 208-1415], and to the 
Office of Information and Regulatory Affairs of the Office of 
Management and Budget [Attention: Desk Officer for Federal Energy 
Regulatory Commission (202) 395-3087].

III. Discussion

A. Summary of Authority and Findings

    The primary purposes of the Federal Power Act are to curb abusive 
practices by public utility companies and to protect consumers from 
excessive rates and charges. To achieve these ends, section 205 of the 
FPA requires that no public utility shall ``make or grant any undue 
preference or advantage to any person or subject any person to any 
undue preference or disadvantage,'' with respect to the transmission of 
electric energy in interstate commerce or the sale for resale of 
electric energy in interstate commerce. <SUP>7 Section 206 of the FPA 
authorizes the Commission to investigate and remedy unduly 
discriminatory or preferential rules, regulations, practices or 
contracts affecting public utility rates for transmission in interstate 
commerce or for sales for resale in interstate commerce.

    \7\16 U.S.C. 824d(b) and 824(d).
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    The significant technological, structural, statutory, and 
regulatory changes over the past twenty years have affected the 
electric utility industry such that competitive bulk power markets are 
now emerging. This transition has expanded what the Commission must 
consider to be undue discrimination in the rates, terms, and conditions 
offered by public utilities. We find that utilities owning or 
controlling transmission facilities possess substantial market power; 
that, as profit maximizing firms, they have and will continue to 
exercise that market power in order to maintain and increase market 
share, and will thus deny their wholesale customers access to 
competitively priced electric generation; and that these unduly 
discriminatory practices will deny consumers the substantial benefits 
of lower electricity prices. We propose to prevent this discrimination 
by requiring all public utilities owning and/or controlling 
transmission facilities to offer non-discriminatory open access 
transmission services.
    At the same time, we see no need now to abrogate existing 
contractual relationships. Instead, contracts should [[Page 17666]] be 
permitted to run their course. Additionally, we believe that recovery 
of legitimate stranded costs is critical to the successful transition 
of the electric utility industry from a tightly regulated, cost-of-
service utility industry to an open access, competitively priced power 
industry.
    The requirement of open access coupled with the recovery of 
legitimate stranded costs furthers the Congressional purposes embodied 
in the Federal Power Act and the Energy Policy Act of 1992 of 
protecting consumers, ensuring reasonable rates, and encouraging 
competition.
    Below, we set out the Commission's legal authority to require non-
discriminatory open access, the relevant historical developments in the 
electric industry, and the need for regulatory reform.<SUP>8

    \8\On February 16, 1995, the Coalition for a Competitive 
Electric Market filed a petition for a rulemaking on comparability. 
The Industrial Consumers and the Transmission Access Policy Study 
Group filed comments in support of the petition. The Commission will 
not separately notice the Coalition's petition, but seeks comment on 
that pleading, and the supporting pleadings, in this notice of 
proposed rulemaking.
B. Legal Authority

1. Undue Discrimination/Anticompetitive Effects
    The Commission has authority to remedy undue discrimination. That 
is clear. Some may argue that case law under the FPA limits our 
authority to order wheeling. We have carefully analyzed relevant cases 
examining our wheeling authority. We conclude that we have authority to 
require wheeling, or non-discriminatory open access, as a remedy for 
undue discrimination. Our analysis of the case law is set forth below.
    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>9 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 as a remedy for undue discrimination. 
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>10

    \9\Associated Gas Distributors v. FERC, 824 F.2d 981, 998 
(D.C.Cir. 1987), cert. denied, 485 U.S. 1006 (1988) (AGD).
    \10\See Gulf States Utilities Company v. FPC, 411 U.S. 747, 758-
59 (1973).
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    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>11 We discuss below the primary court 
decisions that touch on our wheeling authority under sections 205 and 
206.

    \11\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.
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    The Commission's authority to order access as a remedy for undue 
discrimination under the NGA was upheld and discussed in detail in AGD. 
In AGD, the court upheld in relevant part the Commission's Order No. 
436.<SUP>12 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.

    \12\Order No. 436, Regulation of Natural Gas Pipelines After 
Partial Wellhead Decontrol, III FERC Stats. & Regs., Regulations 
Preambles para.30,665 (1985).
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    In upholding the Commission's authority to require open access, the 
court first noted that the opponents' arguments against such authority 
were ``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>13 Emphasizing Congress' deep concern with 
undue discrimination, the court found that the Commission had ample 
authority to ``stamp out'' such discrimination:

    \13\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. 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>14

    \14\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>15 That case was a civil antitrust 
suit against an electric utility. The Court rejected the argument that 
the District Court could not order wheeling because to do so would 
conflict with the Federal Power Commission's (FPC) purported wheeling 
authority.<SUP>16 It pointed out 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 granted power to order 
wheeling. The Otter Tail case, however, did not address whether the 
Commission can require transmission in fulfillment of its duty to 
remedy undue discrimination.

    \15\410 U.S. 366 (1974).
    \16\Id. at 375-76.
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    Richmond Power & Light Company v. FERC (Richmond)<SUP>17 also did 
not involve [[Page 17667]] requiring wheeling to remedy undue 
discrimination. In that case, 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.

    \17\574 F.2d 610 (D.C. Cir. 1978).
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    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>18

    \18\Id. at 620.
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    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>19 The case thus does not in any way limit the 
Commission's authority to remedy undue discrimination.

    \19\Id. at 623, nn. 53 and 57.
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    In Central Iowa Power Cooperative v. FERC,<SUP>20 the FPC<SUP>21 
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.

    \20\606 F.2d 1156 (D.C. Cir. 1979).
    \21\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>22]

    \22\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>23 However, neither the 
Commission nor the court was presented with the argument that wheeling 
was necessary as a remedy for undue discrimination.

    \23\Id. at 1169; see also Municipalities of Groton v. FERC, 587 
F.2d 1296 (D.C. Cir. 1978).
---------------------------------------------------------------------------

    In Florida Power & Light Company v. FERC (Florida),<SUP>24 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>25 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>26 There was no finding that the action 
ordered was necessary to remedy undue discrimination.

    \24\660 F.2d 668 (5th Cir. 1981), cert. denied sub nom. Fort 
Pierce Utilities Authority v. FERC, 459 U.S. 1156 (1983).
    \25\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.
    \26\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).
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    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>27 The 
Commission order would impose common carrier status on FP&L, the court 
found.<SUP>28 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>29

    \27\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'').
    \28\Id. at 676.
    \29\Id. at 678.
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    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>30 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 [[Page 17668]] the petitioners 
read the electric cases far too broadly:

    \30\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>31]

    \31\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>32 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>33

    \32\Id. at 999.
    \33\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>34 Thus, we conclude that we have the authority 
to remedy undue discrimination and anticompetitive effects by requiring 
all public utilities that own and/or control transmission facilities to 
file non-discriminatory open access transmission tariffs.

    \34\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).
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2. Section 211 Services
    In concluding that we must invoke our section 206 authority to 
remedy undue discrimination and anticompetitive actions in the electric 
industry, we have carefully considered the goals of Title VII of the 
Energy Policy Act, and whether section 211, by itself, is sufficient to 
remedy undue discrimination in public utility transmission 
services.<SUP>35 Title VII of the Energy Policy Act, which amended 
section 211 of the FPA, 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, 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.

    \35\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 Natural Gas Act) to remedy undue discrimination.
---------------------------------------------------------------------------

    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. While we interpret section 211 to permit a 
customer or group of customers to seek broad tariff-like 
arrangements,<SUP>36 case-by-case section 211 proceedings are not a 
substitute for tariffs of general applicability that permit timely, 
non-discriminatory access on request.

    \36\See El Paso Electric Company and Central and South West 
Services Inc., 68 FERC para.61,181 at 61,916 (1994) (CSW), reh'g 
pending.
---------------------------------------------------------------------------

    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 cannot be cured effectively 
through section 211.
    The Commission believes that its actions under sections 205 and 206 
will complement the section 211 procedures in achieving the goals of 
creating more competitive bulk power markets and lower rates for 
consumers, while avoiding many years of costly and unnecessary 
litigation. Section 211 will be particularly important for developing 
non-discriminatory access by non-public utilities.
C. Background

1. 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>37 Thus, there was no pressure 
on regulatory commissions to use regulation to affect the structure of 
the industry.<SUP>38

    \37\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).
    \38\See Joskow, supra note 37, at 312; see also Phillips, supra 
note 37, at 12.
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2. 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>39 This was the beginning of periods of rapid 
inflation, higher nominal interest rates, and higher electricity 
rates.<SUP>40 During [[Page 17669]] this time, consumers became 
concerned about higher electricity rates and questioned any price 
increases filed by utilities.<SUP>41

    \39\See Joskow, supra note 37, at 312; see also Phillips, supra 
note 37, at 12-13.
    \40\See Joskow, supra note 37, at 312-13; see also Phillips, 
supra note 37, 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).
    \41\See Joskow, supra note 37, at 313; see also Phillips, supra 
note 37, at 13.
---------------------------------------------------------------------------

    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>42 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>43 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>44 In addition, 
by the 1980s, the oil cartel collapsed, with a resulting glut of low-
priced oil.<SUP>45 At the same time, inflation substantially increased 
the costs of these large baseload generating plants.<SUP>46 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>47

    \42\See generally Jersey Central Power & Light Company v. FERC, 
810 F.2d 1168, 1171 (D.C. Cir. 1987).
    \43\Id.
    \44\See Pierce, supra note 40, 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.
    \45\Id.
    \46\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%.'').
    \47\See Phillips, supra note 37, 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.
    As a result, expensive large baseload plants came onto the market 
or were in the process of being constructed, for which there was little 
or no demand. 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>48 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>49 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.

    \48\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)).
    \49\Id.
---------------------------------------------------------------------------

    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>50 
These writeoffs significantly reduced the earnings of the affected 
utilities.<SUP>51 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>52

    \50\See Black & Pierce, supra note 46, at 1346 (These writeoffs 
were ``about 17% of the book value of total 1992 utility 
investment.'').
    \51\Id.
    \52\Id. (``The high perceived risk of future disallowances 
reversed utilities' incentives to overinvest, and made utilities 
extremely reluctant to build new power plants.'').
---------------------------------------------------------------------------

    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>53 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>54 A significant factor was that larger 
generation units were found to need relatively greater maintenance and 
experience longer downtimes.<SUP>55 The electric industry faced the 
situation ``where the price of each incremental unit of electric power 
exceeded the average cost.''<SUP>56 Bigger was no longer better.

    \53\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).
    \54\Id. at 965.
    \55\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.'')
    \56\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>57

    \57\``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>58 Similarly, the circulating 
fluidized bed combustion boilers, fueled by coal and other conventional 
fuels, provide a more efficient and less polluting resource.

    \58\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>59

    \59\Id. at 24.
---------------------------------------------------------------------------

    Indeed, smaller and more efficient gas-fired combined-cycle 
generation facilities can produce power on the grid at a cost between 3 
and 5 cents per [[Page 17670]] kWh.<SUP>60 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>61

    \60\FERC staff calculations based in part on combined-cycle 
plant cost data reported in 1993 FERC Form No. 1 for a sample of 
units placed in service during 1990-92. Costs vary with regional 
fuel and construction costs, among other reasons.
    \61\Coal and Nuclear plant cost data reported in 1993 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 1986-93; 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 
* * *'').
---------------------------------------------------------------------------

    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>62 This has 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>63 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.

    \62\See Black & Pierce, supra note 46, 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.'').
    \63\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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3. The Public Utility Regulatory Policies Act and the Growth of 
Competition
    In enacting PURPA,<SUP>64 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>65 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>66 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>67 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>68

    \64\Pub. L. 95-617, 92 Stat. 3117 (codified in U.S.C. sections 
15, 16, 26, 30, 42, and 43).
    \65\See generally FERC v. Mississippi, 456 U.S. 742, 745-46 
(1982).
    \66\The Power Plant and Industrial Fuel Use Act of 1978. Pub. L. 
95-617, 92 Stat. 3117 (codified in U.S.C. sections 15, 16, 26, 30, 
42, and 43).
    \67\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.
    \68\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>69 Notwithstanding these 
limitations, QFs proliferated. In 1989, there were 576 QF facilities. 
By 1993, there were more than 1,200 such facilities.<SUP>70 For the 
same time period, installed QF capacity increased from 27,429 megawatts 
to 47,774 megawatts.<SUP>71 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.

    \69\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. 796 (17) and (18).
    \70\Energy Information Administration, Electric Power Annual 
1993 (December 1994) 124 (Table 77).
    \71\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>72 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>73

    \72\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. 101-575, 104 Stat. 2834 
(1990), amended, Pub. L. 102-46, 105 Stat. 249 (1991).
    \73\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>74 severely inhibited these new entities from 
entering the generation business.<SUP>75 Second, these entities needed 
transmission service in order to compete in electricity markets.

    \74\15 U.S.C. 79 et seq.
    \75\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>76 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 [[Page 17671]] 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>77 Indeed, ``[i]n 1992, for the first time, generating 
capacity added by independent producers exceeded capacity added by 
utilities.''<SUP>78

    \76\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).
    \77\Energy Information Administration, Electric Power Annual 
1993 (December 1994) 124 (Table 77).
    \78\Black & Pierce, supra note 46, at 1349 n.25. possessed.
---------------------------------------------------------------------------

    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 power that they may have possessed.<SUP>79 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>80 As we have previously explained:

    \79\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) (Doswell); 
and Dartmouth Power Associates Limited Partnership, 53 FERC 
para.61,117 (1990).
    \80\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>81

    \81\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>82 In addition, beginning in the late 1980s, 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 to mitigate their market power to meet Commission 
conditions.<SUP>83 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>84 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 proposed in this rule. However, only 21 
public utilities have any form of open access transmission; the vast 
majority of IOUs still do not provide any form of ``open access'' 
transmission over their transmission systems.

    \82\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, 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.
    \83\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).
    \84\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).
    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, the advantages of these technological advances can be achieved 
only if more efficient generating plants can obtain access to the 
regional transmission grids. Because the traditional vertically 
integrated utilities still favor their own generation if and when they 
provide transmission access to third parties, barriers continue to 
exist to cheaper, more efficient generation sources.
4. The Energy Policy Act
    In response to the competitive developments following PURPA, and 
the fact that PUHCA and lack of transmission access<SUP>85 remained 
major barriers to new generators, Congress enacted Title VII of the 
Energy Policy Act of 1992 (Energy Policy Act).<SUP>86 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>87

    \85\See infra sections III.D.1 and 2.
    \86\Pub. L. 102-486, 106 Stat. 2776 (1992).
    \87\See El Paso Electric Company and Central and South West 
Services Inc., 68 FERC para.61,181 at 61,914 (1994); 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.'').
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    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>88

    \88\15 U.S.C. 79z-5a.
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If the Commission, upon an application, determines that a person is an 
EWG, that person will be exempt from PUHCA.<SUP>89 This provision 
removed a significant impediment to the development of IPPs and APPs by 
[[Page 17672]] allowing them to develop projects as EWGs free from the 
strictures of PUHCA or the QF PURPA limitations.

    \89\15 U.S.C. 79z-5a(e).
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    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 most circumstances.<SUP>90 
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.

    \90\See supra note 67.
    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 physical or other 
constraints.<SUP>91 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>92

    \91\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), 
III FERC Stats. & Regs., Regulations Preambles para. 30,975 (1993) 
(Policy Statement Regarding Good Faith Requests for Transmission 
Services).
    \92\See Order No. 558, 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, III FERC Stats. & 
Regs., Regulations Preambles para. 30,980, reh'g denied, Order No. 
558-A, 65 FERC para. 61,324 (1993), regulations modified, 59 FR 
15333 (April 1, 1994), III FERC Stats. & Regs., Regulations 
Preambles para. 30,993.
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5. 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>93 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:

    \93\See Order No. 550, Filing Requirements and Ministerial 
Procedures for Persons Seeking Exempt Wholesale Generator Status, 58 
FR 8897 (February 18, 1993), III FERC Stats. & Regs., Regulations 
Preambles para. 30,964, order on reh'g, Order No. 550-A, 58 FR 21250 
(April 20, 1993), III 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 91 and 92. 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>94

    \94\See Stranded Cost NOPR at 32,866; American Electric Power 
Service Corporation, 67 FERC para. 61,168, clarified, 67 FERC para. 
61,317 (1994).

    a. 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>95 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 requiring wheeling in 9 of the 10 cases it has acted on, 
including 3 proposed orders and 6 final orders.<SUP>96

    \95\16 U.S.C.A. 824j-824k (West 1985 and Supp. 1994).
    \96\See, e.g., final orders issued in City of Bedford, 68 FERC 
para. 61,003 (1994), reh'g pending; Florida Municipal Power Agency 
v. Florida Power & Light Company, 67 FERC para. 61,167 (1994), reh'g 
pending; 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 supra note 168.
---------------------------------------------------------------------------

    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>97 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>98

    \97\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), reh'g pending. 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.
    \98\Florida Municipal, 67 FERC at 61,477.
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    As discussed in more detail above, however, our preliminary 
conclusion is that section 211 alone is not enough to eliminate undue 
discrimination. The significant time delays involved in filing an 
individual service request for bilateral service under section 211 
places 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>99

    \99\69 FERC para. 61,035 at 61,165 (1994), reh'g pending; see 
also Southwest Regional Transmission Association, 69 FERC para. 
61,100 at 61,398 (1994) (SWRTA).
---------------------------------------------------------------------------

    b. 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 [[Page 17673]] transmission service 
for a minimum of one month.<SUP>100 The Commission accepted the 
proposed transmission tariff for filing and suspended its effectiveness 
for one day, subject to refund.<SUP>101 Rehearing requests challenged 
the Commission's summary approval of the restriction of service to 
point-to-point as being discriminatory and anticompetitive.<SUP>102 The 
rehearing 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.

    \100\64 FERC para. 61,279 (1993), reh'g granted, 67 FERC para. 
61,168, clarified, 67 FERC para. 61,317 (1994).
    \101\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.
    \102\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>103 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:

    \103\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>104

    \104\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>105

    \105\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 in support of a proposal to sell generation at 
market-based
rates.<SUP>106 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.

    \106\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>107 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>108 The Commission therefore announced a transmission 
comparability requirement for all new mergers:

    \107\E.g., CSW, supra 68 FERC at 61,914.
    \108\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>109

    \109\Id. at 915 (footnote omitted).
---------------------------------------------------------------------------

    In Heartland Energy Services, Inc.,<SUP>110 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

    \110\68 FERC ] 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>111

    \111\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>112 The Commission added that it

    \112\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>113

    \113\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>114 The Commission 
further declared that comparable services must be provided through 
``open access'' tariffs rather than only on a contract-by-contract 
basis:

    \114\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) (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), III FERC Stats. & 
Regs., Regulations Preambles para.30,976 at 30,870 n.4 (RTG Policy 
Statement).

    [T]ariffs are essential to the provision of comparable services. 
Tariffs set out the services that are available and the terms and 
[[Page 17674]] 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>115

    \115\SWRTA, 69 FERC at 61,398.

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.
    Most recently, the Commission has set for hearing whether 
transmission tariffs meet the AEP comparability standard in 
Commonwealth Edison Company,<SUP>116 Wisconsin Electric Power 
Company,<SUP>117 and Wisconsin Public Service Corporation.<SUP>118 In 
all three cases, the company agreed in principle to provide comparable 
service, but issues arose as to what constitutes such service.

    \116\70 FERC para.61,204 (1995).
    \117\70 FERC para.61,074 (1995).
    \118\70 FERC para.61,075 (1995).
---------------------------------------------------------------------------

    c. Lack of Market Power in New Generation. In KCP&L, 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>119 In particular, the Commission 
explained that it had previously noted in Entergy Services, Inc. that

    \119\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>120

    \120\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>121 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>122

    \121\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.
    \122\Id. In KCP&L, the Commission declined to dismiss the 
possibility of market power in generation associated with sales out 
of existing capacity. As noted, however, we here seek comments on 
whether, and if so under what conditions, to drop the generation 
dominance standard in short-run markets, i.e., for sales from 
existing capacity.
---------------------------------------------------------------------------

    d. 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 
additional proceedings: (1) Stranded Cost Notice of Proposed 
Rulemaking,<SUP>123 (2) Transmission Pricing Policy Statement,<SUP>124 
(3) Pooling Notice of Inquiry,<SUP>125 and (4) Regional Transmission 
Group (RTG) Policy Statement.<SUP>126

    \123\See supra note 5.
    \124\See 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), III FERC Stats. & Regs., 
Regulations Preambles para.31,005 (Transmission Pricing Policy 
Statement).
    \125\See Inquiry Concerning Alternative Power Pooling 
Institutions Under the Federal Power Act, 59 FR 54851 (October 26, 
1994), IV FERC Stats. & Regs., Notices para.35,529 (1995) (Pooling 
Notice of Inquiry).
    \126\See Policy Statement Regarding Regional Transmission 
Groups, 58 FR 41626 (August 5, 1993), III FERC Stats. & Regs., 
Regulations Preambles para.30,976 (RTG Policy Statement).
    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>127 Accordingly, the Commission proposed to 
establish provisions concerning the recovery of wholesale and retail 
stranded costs by public utilities and transmitting utilities.<SUP>128

    \127\Stranded Cost NOPR at 32,864.
    \128\The Commission herein is making preliminary findings on 
stranded costs and issuing a supplemental Stranded Cost NOPR, 
seeking comments on the impact of our proposed open access NOPR on 
stranded costs.
---------------------------------------------------------------------------

    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>129 Under the new policy, it will permit a 
variety of proposals, including distance sensitive and flow-based 
pricing,<SUP>130 which may be more suitable for competitive wholesale 
power markets. 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>131 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>132

    \129\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 infra discussion of Indiana 
Michigan Power Company, 64 FERC para.61,184.
    \130\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 would be compensated for the transaction.
    \131\Transmission Pricing Policy Statement at 31,136.
    \132\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 [[Page 17675]] are appropriately balancing our dual 
objectives of promoting coordination and competition.<SUP>133

    \133\Pooling Notice of Inquiry 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>134

    \134\Id. at 35,714.
---------------------------------------------------------------------------

    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 recently conditionally approved the formation of two 
RTGs.<SUP>135 One of the conditions is that each RTG member must offer 
comparable transmission services by tariff to other RTG members.

    \135\See WRTA and SWRTA, supra.
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    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.<SUP>136

    \136\The Energy Information Administration recently indicated 
that at least nine states--California, Connecticut, Illinois, 
Michigan, Nevada, Ohio, Texas, Utah, and Vermont have proposals or 
legislation for retail wheeling. EIA, Performance Issues for a 
Changing Electricity Power Industry, January 1995 19-22. Most 
prominent among the recent state proposals are the California Public 
Utility Commission's ``Blue Book'' proposal (Order Instituting 
Rulemaking on the Commission's Proposed Policies Governing 
Restructuring California's Electric Services Industry and Reforming 
Regulation, R. 94-04-031; Order Instituting Investigation on the 
Commission's Proposed Policies Governing Restructuring California's 
Electric Services Industry and Reforming Regulation, I. 94-04-032) 
and the Michigan Public Service Commission's proposal (Interim Order 
on Experimental Retail Wheeling Program, Case No. U-10143/U-10176 
(April 11, 1994)).
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D. 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 3 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>137 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>138 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.<SUP>139 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. It is also 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.

    \137\Energy Information Administration, Performance Issues for a 
Changing Electric Power Industry (January 1995) 10 and (Figure 5).
    \138\Current Competition, November 1994, Vol. 5, No. 8, at 8.
    \139\See map attached as Appendix A. This Appendix will not 
appear in the Federal Register.
---------------------------------------------------------------------------

    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>140 
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. Such action is required by the FPA's mandate that 
the Commission remedy undue discrimination.

    \140\As discussed above, only a minimal number of public 
utilities 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.
---------------------------------------------------------------------------

1. Market Power
    Unlike new generating capacity (see prior discussion of KCP&L), 
transmission remains and is expected to remain a natural monopoly. The 
Commission has addressed the natural monopoly character of transmission 
in the major cases summarized above and in the Commission's recent 
Transmission Pricing Policy Statement. The monopoly characteristic 
exists in part because entry into the transmission market is restricted 
or difficult.<SUP>141 In addition, as unit costs are less for larger 
lines and networks, transmission facilities still exhibit scale 
economies. From an economic, environmental, and aesthetic viewpoint, it 
is often better for a single owner (or group of owners) to build a 
single large transmission line rather than for many transmission owners 
to build smaller parallel lines on a non-coordinated basis.

    \141\An example of this is that, except in the limited case of 
licensed hydroelectric projects under Part I of the FPA, there is no 
Federal right of eminent domain available to assist in acquiring 
rights of way for new transmission lines. In addition, the 
regulatory requirements to build a transmission line vary from state 
to state. In all states, siting new transmission lines is getting 
harder.
---------------------------------------------------------------------------

    Further, effective competition among owners of parallel 
transmission lines is unlikely, and often impossible, with existing 
practices and technology. For example, on an alternating current (AC) 
electric system, electricity flows on parallel paths based on the 
impedance of each path. With two electric systems providing parallel 
contract paths, a share of the actual power flows would occur on each 
system according to the physical characteristics of the system. Thus, 
each of the two transmission service providers would have the incentive 
to underbid the other because the winner would receive all of the 
transmission revenues, but only incur a fraction of the costs. The 
loser, on the other hand, would incur the remaining costs, but would 
receive no revenues.
    In today's electric industry, which is dominated by vertically 
integrated utilities, an owner or controller of transmission service 
can exclude generation competitors from the market, thereby favoring 
the transmission [[Page 17676]] owner's own generation. This can occur 
through outright denial of transmission access, or, as is more likely, 
through access that is discriminatory as to rates, terms or conditions 
of service.<SUP>142 Thus, in the absence of non-discriminatory open 
access tariffs, the development of fully competitive bulk power markets 
cannot occur, and consumers will be deprived of the benefits that would 
be expected from such a competitive market.

    \142\See, e.g., David W. Penn, A Municipal Perspective on 
Electric Transmission Access Questions, Pub. Util. Fort. 18-19 (Feb. 
6, 1986).
---------------------------------------------------------------------------

2. Discriminatory Access
    Some transmission-owning utilities have voluntarily begun to offer 
unbundled transmission tariff services to third-party suppliers and 
purchasers of wholesale power, though none have done so to the extent 
proposed by this proposed rule.<SUP>143 However, because utilities are 
naturally profit maximizers and monopoly suppliers to their native 
load, the vast majority of transmission-owning utilities have not 
agreed to give up their market power voluntarily. Transmission-owning 
utilities have an incentive to deny access either by not filing any 
open access tariff or by filing a tariff that offers services inferior 
to those used by the transmission owner. This is particularly true for 
those utilities that emerged from the recent decades of technological 
and legal changes as high-cost generation companies. Open access 
transmission places their existing generation at risk because their 
wholesale customers may seek alternative lower price suppliers. It is 
in their self-interest to maintain and use market power to retain (or 
expand) market share for their existing generation facilities, at least 
until they can get their generation costs in line with current market 
prices. Because generating units are usually depreciated over a 30- to 
50-year physical life, many high cost companies may attempt to exercise 
transmission market power for decades to preserve the value of past 
generation investments.

    \143\The majority have offered only point-to-point services. 
However, a few utilities have sought to comply with the non-
discrimination (comparability) standard announced in AEP. For 
example, Kansas City Power & Light Company (KCP&L) and Louisville 
Gas & Electric Company (LG&E) recently filed settlements to this 
effect. KCP&L, Docket No. ER94-1045 (settlement filed February 14, 
1995) and LG&E, Docket No. ER94-1380 (settlement filed February 10, 
1995).
    Unless all public utilities are required to provide non-
discriminatory open access transmission, the ability to achieve full 
wholesale power competition, and resulting consumer benefits, will be 
jeopardized. If utilities are allowed to discriminate in favor of their 
own generation resources at the expense of providing access to others' 
lower cost generation resources by not providing open access on fair 
terms, the transmission grid will be a patchwork of open access 
transmission systems, systems with bilaterally negotiated arrangements, 
and systems with transmission ordered under section 211. Under such a 
patchwork of transmission systems, sellers will not have access to 
transmission on an equal basis, and some sellers will benefit at the 
expense of others. The ultimate loser in such a regime is the consumer.
    A patchwork of transmission systems will also result in 
inefficiencies across the Nation's transmission grids. Because of the 
physical properties of the transmission system, electric power moves 
over parallel transmission lines from generator to load, without regard 
to whether a line is part of a system providing open access or 
not.<SUP>144 However, today the industry develops transmission 
contracts as if power flowed along one series of lines belonging to 
specific owners, which is called the ``contract path.'' Thus, 
transmission users will search for contract paths through open access 
systems to take advantage of the non-discriminatory open access 
tariffs. Because open access transmission tariffs include an obligation 
to expand when necessary to accommodate third-party requirements for 
service, transmitting companies offering open access services across 
their systems could end up constructing a disproportionate share of new 
transmission facilities.

    \144\In Indiana Michigan Power Company, 64 FERC para. 61,184 
(1993), the Commission explained loop flows and parallel power 
flows:
    In general, utilities transact with one another based on a 
contract path concept. For pricing purposes, parties assume that 
power flows are confined to a specified sequence of interconnected 
utilities that are located on a designated contract path. However, 
in reality power flows are rarely confined to a designated contract 
path. Rather, power flows over multiple parallel paths that may be 
owned by several utilities that are not on the contract path. The 
actual power flow is controlled by the laws of physics which cause 
power being transmitted from one utility to another to travel along 
multiple parallel paths and divide itself among those paths along 
the lines of least resistance. This parallel path flow is sometimes 
called ``loop flow.''
    Id. at 62,545.
---------------------------------------------------------------------------

    Expansion cannot be efficient under such a patchwork of open access 
transmission systems. Not only would this misallocate cost burdens to 
open access companies, but it is unlikely that the optimal transmission 
development will always be within their service territories. Expansion 
on closed systems, instead of open systems, may in some cases be the 
more efficient way to relieve constraints. Thus, a patchwork of open 
access systems will not result in the least cost expansion of the 
Nation's transmission grids. In addition, states with open access 
utilities may refuse to site new lines if their closed access neighbors 
are not doing their share.<SUP>145

    \145\The Commission partially addressed this concern by allowing 
reciprocity provisions in open access transmission tariffs. See, 
e.g., Southwestern Electric Power Company and Public Service Company 
of Oklahoma, 65 FERC para. 61,212 at 61,981-82 (1993), order on 
reh'g, 66 FERC para. 61,099 (1994).
---------------------------------------------------------------------------

    A discriminatory, patchwork system also works against pricing 
parallel power flows on a sensible regional basis. The formation of 
effective regional transmission groups, which the Commission strongly 
encourages, would be fostered if all utilities in a region offered non-
discriminatory open access.<SUP>146 In fact, optimal cooperative 
regional action would involve all transmission systems in the region 
offering non-discriminatory open access to all wholesale customers.

    \146\While the Commission has conditioned its approval of RTGs 
to achieve this same result, the formation of RTGs is voluntary. By 
contrast, compliance with the final rules adopted in this proceeding 
will be required.
---------------------------------------------------------------------------

    A transmission-owning utility may deny access to third parties not 
only to avoid losing its own generation sales, but also to maintain 
other trading gains. For example, a company can buy low cost power for 
its own use from a neighbor at a low price if other buyers cannot reach 
that neighbor to bid up the price. Furthermore, if it does not need the 
energy, it can market that power by buying low and selling high.
    In the past, transmission-owning utilities have discriminated 
against others seeking transmission access. Transmission-owning 
utilities have denied access by outright refusals to deal. While such 
actions tend to be rare, likely because transmission owners fear they 
may trigger antitrust action,<SUP>147 they have occurred.<SUP>148 More 
often, however, discrimination is likely to be manifested more subtly 
and indirectly.<SUP>149 One such [[Page 17677]] way would be for 
transmission owners to adopt a negotiating strategy that involves a 
sequence of informational and other requirements over a protracted 
period of time. By the time all of the requirements are finally 
satisfied, the window for the customer's trade opportunity has 
closed.<SUP>150 Another way of frustrating access is to substantially 
change the terms of negotiated agreements through protracted delay, 
including filings with regulatory agencies.<SUP>151

    \147\See, e.g., Penn, supra note 142, at 18. 
    \148\Otter Tail Power Company refused to wheel power for the 
village of Elbow Lake. The Supreme Court ultimately ruled against 
Otter Tail on antitrust grounds. Otter Tail Power Company, 410 U.S. 
366 (1974). The Commission has also found that Utah Power & Light 
Company consistently refused to permit the wheeling of low-cost 
power across its system in order to use its strategically located 
bottleneck transmission system to extract monopoly prices. Utah 
Power & Light Company, supra, 45 FERC at 61,287 and n.137 (1988).
    \149\See, e.g., Penn, supra note 142, at 18-19 (discussion of 
methods used to deny access). Penn also noted in his 1986 article 
that the American Public Power Association had conducted a survey of 
its members in which about 25% indicated a problem in securing 
transmission in effecting coordination services and about an equal 
amount had reported being denied transmission access in the recent 
past. Id. at 18. See also Pacific Gas & Electric Company, 51 FPC 
1030, 1031-32, reh'g denied, 51 FPC 1543 (1974) (parties alleged 
that public utility proposed ``a wholesale rate so high that its 
wholesale customers would be unable to compete with PG&E for large 
industrial retail loads'' and entered into restrictive and 
anticompetitive contracts that strengthened public utility's 
monopoly).
    \150\Members of the Coalition for a Competitive Electricity 
Market alleged that they have encountered this strategy. Coalition 
Petition at 13, n.19.
    \151\An example of this tactic is evident in 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). 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 what came to be known 
as the South of Tesla Principles). PG&E spent the next four years 
filing substitute provisions for what it had promised in the 
Principles. 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 para. 61,006 (1994).
    Another way for transmission-owning utilities to frustrate access 
and competition is to allow access, but only on non-comparable or 
unsupportable terms and conditions that are inferior to the conditions 
under which the transmission owners themselves use or could use the 
transmission grid or on terms and conditions that have no operational 
or financial basis. Discrimination can be exercised this way in the 
---------------------------------------------------------------------------
following areas:

    (1) Network Service. Network service allows a transmission 
customer to distribute a given amount of transmission usage between 
specified resources and specified loads without having to pay 
multiple charges for each resource-load pairing. Transmission owners 
can refuse to provide service on these terms and instead insist on 
charges that are a function of the number of resource load 
pairings.<SUP>152 This can dramatically increase the cost of such 
service. Such treatment does not reflect the way transmission 
owners' costs are allocated to their own native load customers.

    \152\See Pacific Gas and Electric Company, 52 FERC para. 61,347 
at 62,375-76 (1990) (proposal to charge a base demand and a 
flexibility adder for an integrating transmission service). PG&E 
eventually withdrew the proposal. 56 FERC para. 61,373 at 62,429 
(1991); see also Florida Municipal Power Agency v. Florida Power & 
Light Company, 65 FERC para. 61,125 (1993) (Federal Municipal Power 
Agency requested a section 211 order directing network service); 
Tex-La Electric Cooperative of Texas, 67 FERC para. 61,019 at 61,057 
(1994) (Tex-La requested a section 211 order directing network 
service).
---------------------------------------------------------------------------

    (2) Pricing. Transmission service can be made unattractive to 
third-party customers by pricing such service on a basis that is 
different from that used by the transmission owner and that results 
in higher rates. One example would be charging third-party customers 
distance-sensitive rates, while pricing all similar transmission 
bundled with power services on a postage stamp basis.<SUP>153

    \153\See notes 129 and 130, supra; see also Tex-La Electric 
Cooperative of Texas, 69 FERC para. 61,269 at 62,034-35 (1994), in 
which the Commission found this practice to be unduly 
discriminatory.
---------------------------------------------------------------------------

    (3) Service Priority. The priority of transmission service is a 
critical service factor. The transmission provider could 
disadvantage third-party transmission customers by making firm 
transmission service to them subordinate to the transmission 
utility's native load service.<SUP>154

    \154\See AEP, 64 FERC at 62,971-72.
---------------------------------------------------------------------------

    (4) Scheduling and Balancing Provisions. A transmission owner 
could hold transmission customers to unnecessarily long lead times 
to change power schedules. In some cases, scheduling could be 
required as much as a month ahead of time.<SUP>155 This precludes 
transmission customers from using their service for short-term 
trading. Transmitting utilities may also insist that customers keep 
strict adherence to scheduling and balancing provisions by requiring 
them to get back on schedule quickly or face stiff 
penalties.<SUP>156 One example of a stiff penalty for failure to 
schedule sufficient power would be to assess shortfalls based on a 
partial requirements rate with an 11-month ratchet.<SUP>157 In 
contrast, transmitting utilities may have access to less costly 
balancing alternatives, such as substituting resources without 
notice or borrowing capacity from neighboring utilities and settling 
the imbalance by returning energy in-kind within a much longer time 
period than allowed to customers.<SUP>158

    \155\Id.
    \156\See Coalition Petition at 20-21.
    \157\See Borough of Zelienople, 70 FERC para. 61,073 at 61,184 
(1995) (load exceeding schedule by 1 MW would be filled at a partial 
requirements rate using a 60% demand ratchet for 11 months, i.e., 1 
MW times 60% times $9.30 per kW times 11, for a total of $61,380).
    \158\See Coalition Petition at 20-21.
---------------------------------------------------------------------------

    (5) Use of Firm Transmission Capacity. Transmission owners can 
unnecessarily restrict the firm transmission capacity made available 
to transmission customers. One way to restrict service would be to 
prohibit the customer from reassigning such capacity when it is not 
needed.<SUP>159 This restricts the customer's ability to manage the 
risk of long-term capacity purchases and to compete as a seller in 
the transmission service market. Another example would be that the 
transmission owner could restrict a customer's use of transmission 
capacity by allowing sales only from the customer's generating 
resources that are temporarily in excess of actual load 
needs.<SUP>160 Transmission owners do not face these restrictions in 
their own use of transmission capacity.

    \159\See, e.g., Pacific Gas and Electric Company, 53 FERC para. 
61,145 at 61,505 (1990) (utility proposed a reassignment prohibition 
on the use of Reserve Transmission Service available to the 
Sacramento Municipal Utility District under a proposed 
Interconnection Agreement).
    \160\Id. at 61,504-05 (utility proposed an export restriction on 
the use of Reserve Transmission Service available to the Sacramento 
Municipal Utility District under a proposed Interconnection 
Agreement).
---------------------------------------------------------------------------

    (6) Ancillary Services. A transmitting utility may offer to a 
transmission customer ancillary services (e.g., scheduling) that are 
inferior to the services it provides for itself. Transmission owners 
may be free to choose whether to supply some of these services to 
themselves or contract for them if available more cheaply 
elsewhere.<SUP>161 Third-party transmission customers do not always 
have this option on a comparable basis.

    \161\See Coalition Petition at 28-29 and 32.
    (7) Creditworthiness and Security Deposits. Customers are 
sometimes required to make onerous deposits in order to obtain 
service.<SUP>162

    \162\For example, it is reported that one customer was told that 
a $13 million line of credit would be required to ensure 
creditworthiness for a request of only one MW of transmission 
capacity for a coordination trade. See Coalition Petition at 30.
---------------------------------------------------------------------------

    (8) Reciprocity Double Payments. Transmission agreements often 
require reciprocity. Non-transmission owners could be required to 
contract with, and pay, third-party transmitting utilities to 
provide the required reciprocal service.<SUP>163 Transmission owners 
do not face such obstacles in using their own systems.

    \163\See Coalition Petition at 25; see also AES Power, Inc., 69 
FERC para.61,345 at 62,295 and 62,301 (1994) (AES).

    Finally, an additional way for transmission-owning utilities to 
frustrate access and competition is by granting each other superior 
rights and lower rates--compared to those available to non-transmission 
owning customers--in pools, interconnection agreements, and other 
protocols.<SUP>164 For example, pool-wide transmission service can be 
made available to members at rates less than those that each member 
would separately propose under traditional rate methods. This could 
disadvantage non-transmission owners if pool membership is restricted 
or if it requires excessive or vaguely stated transmission 
contributions that could be difficult to meet.<SUP>165

    \164\See Coalition Petition at 13-14.
    \165\See Mid-Continent Area Power Pool, 69 FERC para.61,347 at 
62,308 (1994).
---------------------------------------------------------------------------

    Section 211 is not always a sufficient remedy for this 
discriminatory behavior. Third parties may seek non-discriminatory 
transmission under section 211, but they will not be able to compete if 
the sale or purchase [[Page 17678]] opportunity is gone before a final 
order can be obtained under section 211. This could be the case in many 
situations because of the procedural requirements of sections 211 and 
212.<SUP>166 Indeed, to date, the Commission has received eighteen 
section 211 transmission requests,<SUP>167-168 which it has tried to 
process expeditiously within the procedural constraints contained in 
sections 211 and 212. As to the seven requests that have received a 
final order, the average elapsed time from date of filing to the date 
of a final order was 9 months. The remaining ten requests have been 
pending, on average, more than 6 months.

    \166\For example, an applicant must make a request for 
transmission service to the transmitting utility at least 60 days 
before filing an application with the Commission for an order to 
provide transmission. The Commission must first issue a proposed 
order and allow the parties a reasonable time to negotiate agreeable 
terms and conditions before it can issue a final order. Moreover, a 
final order faces possible rehearing and a court appeal.
    \167-168\One request was withdrawn.
---------------------------------------------------------------------------

    The following sets forth the status of the section 211 cases filed 
with the Commission:

------------------------------------------------------------------------
                Date of                                           Months
 Docket No.   application                 Status                 pending
------------------------------------------------------------------------
TX93-1......     01/19/93  Final Order-7/29/93.................        6
TX93-2......     06/18/93  Final Order-7/1/94..................       12
TX93-3......     06/30/93  Withdrew-9/10/93....................        2
TX93-4......     07/02/93  Final Order-5/11/94.................       10
TX94-1......     10/21/93  Final Order-7/6/94..................        9
TX94-2......     11/04/93  Pending<SUP>a............................       16
TX94-3......     11/09/93  Final Order-7/13/94.................        8
TX94-4......     12/15/93  Final Order-12/1/94.................       11
TX94-5......     04/15/94  Final Order-3/23/95.................       11
TX94-6......     07/05/94  Pending.............................        8
TX94-7......     07/15/94  Pending<SUP>a............................        8
TX94-8......     08/05/94  Pending.............................        7
TX94-9......     09/09/94  Pending<SUP>a............................        6
TX94-10.....     09/16/94  Pending.............................        6
TX95-1......     10/11/94  Pending.............................        5
TX95-2......     10/17/94  Pending.............................        5
TX95-3......     01/19/95  Pending.............................        2
TX95-4......     01/24/95  Pending.............................       2 
------------------------------------------------------------------------
<SUP>aA proposed order has been issued.                                      

    As the wholesale power markets become more competitive, delayed 
access becomes a matter of increasing concern. Not only have long-term 
purchases from non-traditional generators become more important, but 
short-term firm and non-firm power sales and purchases create 
significant profit or cost-saving opportunities for utilities, 
marketers, and their customers. As a result, market participants are 
exploring various ways to reduce their costs through trading. These 
include poolcos, changes to existing pools, short-term trading systems, 
and futures contracts.<SUP>169 We do not see how such options will work 
unless all parties have non-discriminatory transmission access rights 
and hour-to-hour access without having to go through a regulatory 
proceeding for each trade.

    \169\We note that NEPOOL and MAPP are currently exploring ways 
to modify their pool structures to accommodate competitive power 
markets. As noted in the Pooling Notice of Inquiry, supra, the 
poolco concept basically involves an independent entity that would 
control the operation of all transmission facilities and some or all 
generating facilities in a region. It would be open and would 
provide transmission service to all generators. Thus, the poolco 
would create a spot market for power in the region.
---------------------------------------------------------------------------

    In today's emerging competitive wholesale power markets, the 
practices of some transmission-owning utilities are unduly 
discriminatory and anticompetitive. These practices produce market 
distortions today, undermine the goal of the Energy Policy Act to 
create competitive bulk power markets, and will continue if this 
Commission does not take action. Most important, they can harm 
consumers by denying them the benefits of competitively priced power. 
We seek additional specific examples of such practices.
3. Analogies to the Natural Gas Industry
    The electric industry today is analogous in many ways to the 
natural gas industry before the Commission issued Order Nos. 436 and 
636.<SUP>170 Then, natural gas pipelines were primarily merchants 
offering a bundled sales service, which provided gas to customers at 
the city-gate from the pipelines' own system supplies. In addition, 
pipelines moved a relatively small amount of third-party gas under a 
separate transportation service. To meet their sales service 
obligations, pipelines purchased most of their system supply from 
third-party producers under long-term contracts. In the early 1980s, 
due to changing market conditions, the prices under many of these 
contracts ended up being higher than those available in the then 
evolving spot market. Because of the long-term contracts and the 
resulting higher cost gas, system supply gas tended to be more costly 
than gas that the customers could buy in the competitive spot market. 
At the same time, the transportation service bundled with a pipeline's 
sales service was usually superior to the transportation service third 
parties could obtain. Essentially, the pipeline would provide itself 
service that had much greater flexibility and often promised greater 
reliability than that available to third-party shippers. Pipelines had 
a considerable incentive to maintain this difference in transportation 
service quality to make their own, more expensive gas more attractive.

    \170\Order No. 436, Regulation of Natural Gas Pipelines After 
Partial Wellhead Decontrol, FERC Regulations Preambles para.30,665 
(1985); Order 636, 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, 57 FR 13267 (April 16, 
1992), III FERC Stats. & Regs., Regulations Preambles para.30,939 
(Order No. 636), appeal pending.
---------------------------------------------------------------------------

    A similar situation exists today in the electric industry. 
Traditional public utilities deliver bundled service--generation and 
transmission--to most of their wholesale customers. They have monopoly 
control over transmission facilities and thus control access to their 
customers. The lack of non-discriminatory access to transmission 
services raises the same general concerns that were prevalent in the 
gas industry. Accordingly, unless similar regulatory measures are 
undertaken, the Commission expects the same type of discriminatory and 
anticompetitive behavior will continue in the electric industry as was 
present in the gas industry, because denying non-discriminatory access 
will continue to be in the economic self-interest of transmission 
monopolists, absent regulatory changes.<SUP>171

    \171\See AGD, supra, 824 F.2d at 1008 (``Agencies do not need to 
conduct experiments in order to rely on the prediction that an 
unsupported stone will fall.''). The ongoing discriminatory behavior 
by owners or controllers of transmission in the electric industry is 
detailed supra.
---------------------------------------------------------------------------

    In its regulation of interstate pipelines under the Natural Gas Act 
(NGA) the Commission initially addressed the problem of undue 
discrimination in Order No. 436, finding natural gas pipeline practices 
to be unduly [[Page 17679]] discriminatory under the NGA<SUP>172 and 
effectuating ``open access'' transportation. The Commission in that 
order sought to make transportation available to third parties on a 
non-discriminatory basis. The Commission provided that, if a pipeline 
held itself out as a transporter of gas for others, it must provide 
that service to all shippers without discrimination. At the same time, 
the Commission allowed pipelines and their customers to retain the 
traditional bundled sales and transportation services under existing 
certificate authority.

    \172\In this regard, sections 4 and 5 of the NGA are virtually 
identical to sections 205 and 206 of the FPA.
    As a result of Order No. 436, pipelines became primarily 
transporters of natural gas. However, in Order No. 636, the Commission 
noted that pipelines were still providing, albeit at a reduced level, a 
bundled, city gate, sales service in competition with third-party sales 
and transportation, and concluded that the competition was not 
occurring on an equal basis. The Commission also noted that pipelines' 
natural gas sales prices exceeded those of their competitors, much as 
electric utilities' embedded costs can exceed the cost of new 
generating capacity and excess generating capacity of others. In this 
regard, the Commission determined that the transportation service 
bundled with pipelines' sales service was superior to that made 
available to third parties and that pipelines and unregulated 
competitors were not selling the same product.<SUP>173 Accordingly, in 
Order No. 636, the Commission found this behavior anticompetitive and 
required pipelines to ``unbundle'' their sales services from their 
transportation services and to provide open access transportation 
service that is equal in quality for all gas supplies whether purchased 
from the pipeline or some other supplier.<SUP>174

    \173\Order No. 636 at 30,402. The Commission explained that 
pipelines were selling a regulated bundled sales and transportation 
service, but that their competitors were generally selling only the 
gas commodity. The Commission also recognized that pipelines were at 
a competitive disadvantage due to their certificate and contractual 
obligations to their firm sales customers. Id. at 30,403.
    \174\Order No. 636 at 30,393-94.
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    Our experience in the gas area influences our decision that, at a 
minimum, functional unbundling of wholesale services is necessary in 
order to obtain non-discriminatory open access and to avoid 
anticompetitive behavior in wholesale electricity markets.
4. Coordination Rates
    In finding a need for non-discriminatory open access transmission, 
the Commission has considered the structure of the coordination market, 
i.e., the market for wholesale sales to a public utility's non-
requirements customers. Utilities now engage in coordination trades 
primarily under rates no lower than the seller's variable cost and no 
higher than that variable cost plus 100% contribution to the fixed 
costs of the production unit used to price energy and the relevant 
transmission facilities. This rate flexibility allows the buyer and 
seller to negotiate a price reflecting the market at the time of the 
sale, including the number of buyers and sellers, the relative 
incremental and decremental variable costs, and the amount of savings 
attainable by transacting. Thus, while the seller's ceiling rate 
reflects some measure of fixed and variable costs, the actual 
transaction price is set, to a certain extent, by the marketplace. This 
marketplace, however, may be skewed by the general lack of transmission 
access, and the resulting price may be considerably above prices in a 
fully competitive market.
    Some utilities transact under a split-savings rate that generally 
sets the price halfway between the seller's incremental variable cost 
and the buyer's decremental variable cost. Here again, price is a 
function of the alternatives reachable through the transmission grid at 
the time of the transaction. This rate form is primarily used today to 
distribute the savings derived from the central dispatch of power pools 
on an after-the-fact basis.
    The Commission believes that unless the participants in 
coordination markets mitigate their transmission market power, market-
driven prices for coordination trades may no longer be just and 
reasonable. Thus, our preliminary conclusion is that current 
coordination pricing is no longer justified in the absence of a tariff 
offer of non-discriminatory open access transmission services by the 
seller (owning or controlling transmission) in a coordination 
transaction.<SUP>175 The Commission's past practice of allowing such 
pricing for coordination trades appears to be inconsistent with 
emerging competitive markets unless those who benefit from such trading 
offer access to other, lower-priced trading opportunities. We seek 
comments on this issue.

    \175\As discussed infra, sellers must also meet the Commission's 
other requirements to obtain market-based rates.
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E. The Proposed Regulations

    The goals of the proposed regulations are two-fold: (1) To 
facilitate the development of competitive wholesale bulk power markets 
by ensuring that wholesale purchasers of electric energy and wholesale 
sellers of electricity can reach each other by eliminating 
anticompetitive practices and undue discrimination in transmission 
services; and (2) to address the transition costs associated with the 
development of competitive wholesale markets. This section addresses 
the elimination of undue discrimination. Transition costs are addressed 
below in Section F.
    Non-discriminatory open access transmission is critical to the 
ability of sellers to compete on a fair basis and the ability of 
purchasers to reach the lowest priced generation options. Thus far, the 
Commission has developed an open access comparability requirement on a 
case-by-case basis. We have directed our administrative law judges, to 
whom the various cases have been referred, to examine the factual 
circumstances surrounding a utility's use of its own system vis-a-vis 
the type of service provided to third parties. Nonetheless, it has now 
become evident to us that it is necessary for the Commission to define 
the parameters of a non-discriminatory open access tariff much more 
precisely.
    Until now, we have been applying the new standard of what 
constitutes undue discrimination only to new voluntary tariff filings. 
We now no longer believe it is appropriate to apply this standard so 
narrowly; therefore, we are proposing to require all public utilities 
to offer non-discriminatory open access services in accord with the 
proposed rule and the attached tariffs. This broad application is 
consistent with our determination that undue discrimination by 
jurisdictional public utilities must be prevented or remedied. It is 
also consistent with our desire to bring further efficiencies to the 
provision of electric service by encouraging competitive bulk power 
markets.
1. Non-discriminatory Open Access Tariff Requirement
    Transmission owners can discriminate by restricting access to, or 
restricting expansion of, transmission facilities, or by restricting 
access to the ancillary services that control the generation resources 
on the transmission grid.<SUP>176 To ensure that all 
[[Page 17680]] participants in wholesale electricity markets have non-
discriminatory open access to the transmission network, transmission 
owners must offer non-discriminatory open access transmission and 
ancillary services to wholesale sellers and purchasers of electric 
energy in interstate commerce.<SUP>177 This will require tariffs that 
offer point-to-point and network transmission services, including 
ancillary services. All of these services must be non-discriminatory as 
to price as well as to non-price terms and conditions. Services must be 
available to any entity that could obtain transmission services under 
section 211.

    \176\Examples of ancillary services (which include control area 
services) are: Scheduling service between control areas, and various 
services that facilitate power movements within control areas, e.g., 
dispatch service, load following service, imbalance resolution 
service, reactive power support, and operating reserves. We invite 
comment on definitions of these terms and their component parts. 
Regardless, the proposed rule would require that all ancillary 
services be offered on a non-discriminatory basis.
    \177\See generally William W. Hogan, Reshaping the Electricity 
Industry, Prepared for the Federal Energy Bar Conference, ``Turmoil 
for the Utilities,'' 5 Washington, D.C. (Nov. 17, 1994):
    Commercial functions must facilitate non-discriminatory, 
comparable open access and support market operations in the 
competitive sectors. The EPAct requirements and the FERC 
implementation emphasize the need to obtain market access under 
terms and conditions that support competition. Everyone should have 
equal access to and use of essential facilities, particularly 
transmission, with the rights of ownership limited to compensation 
consistent with opportunity costs in a competitive market.
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    In our AEP rehearing order and in several subsequent cases,<SUP>178 
we set for hearing the following issues:

    \178\See, e.g., AEP, 67 FERC at 61,491.

    1. The different uses that a transmission owner makes of its 
transmission system and whether there are any operational 
differences between any particular use that the owner makes of the 
system and the use third parties might need, and in particular, the 
degree of flexibility the transmission owner accords itself in using 
its transmission system for different purposes.
    2. Any potential impediments or consequences to providing a 
particular service to third-party transmission customers which is 
the same or comparable to service that the transmission owner 
provides itself.
    3. The costs that the transmission owner incurs in providing 
transmission associated with its use of the system, and whether the 
costs to provide such service or comparable service to third parties 
would be different.

Based on what we have learned in the past year, the Commission proposes 
to address these issues generically. Concurrently with this order, the 
Commission is issuing a separate order on how a final rule would apply 
to pending cases.<SUP>179 We believe that the parties and the 
administrative law judges in the individual pending proceedings should 
continue their efforts, but in doing so should take into account the 
principles announced in this proposed rule. This will permit any fine 
tuning of the broader principles announced here and set forth in the 
pro forma tariffs that may be necessary to recognize the individual 
circumstances of particular systems.

    \179\Order Providing Guidance Concerning Pending and Future 
Proceedings involving Non-discriminatory Open Access Transmission 
Services, Docket Nos. ER93-540-000, et al. 
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    With regard to the first issue, the Commission believes 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>180 This network transmission service 
is bundled as part of retail service and as part of wholesale 
requirements service, and is the fundamental support of a utility's 
dispatch that underlies its trading in the wholesale coordination 
market.<SUP>181

    \180\While there may be any number of specific services used by 
a particular customer, we have concluded, after analyzing the 
historical types of transmission service tariffs on file, as well as 
the tariffs filed in the ongoing comparability proceedings, that all 
transmission services generally fall within these two categories.
    \181\A utility's own coordination purchases may involve hourly 
scheduled transfers of fixed blocks of power. These schedules are 
supported by the utility's own network transmission service used for 
its economic dispatch. Consequently, network service is covered by 
the proposed rule because it supports a utility's coordination 
purchases, regardless of whether or not the utility has any 
requirements customers that also would use network service.
    The Commission has preliminarily concluded that third parties may 
need one or both of these basic uses in order to obtain competitively 
priced generation or to have the opportunity to be competitive sellers 
of power. 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 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. For example, a utility may not 
provide itself ``wheeling-through'' service,<SUP>182 which is a 
specific form of point-to-point service. However, because ``wheeling-
through'' service is merely a subset of basic point-to-point service, 
which the utility does provide to itself, the Commission will require a 
utility to provide such service.<SUP>183 Similarly, a utility may 
contend that it does not provide non-firm point-to-point service to 
itself because all of its transmission investment results in firm 
entitlements. Nonetheless, the utility provides itself with the 
functional equivalent of non-firm service when it uses, subject to 
curtailment or interruption, capacity that is temporarily unused by 
other firm reservation holders. Therefore, it must offer non-firm 
point-to-point service.

    \182\``Wheeling through'' refers to transmittal of electric 
energy through a transmitting utility's grid, i.e., entering at one 
point of interconnection and leaving at another.
    \183\This would be true of other services as well.
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    We will not allow transmission providers to define terms or specify 
transmission uses to erect barriers to fair and equal competition in 
power markets, or to engage in undue discrimination.
    On the second issue set for hearing in AEP, et al. (potential 
impediments to providing a particular service), we believe there are 
none, except for impediments to siting. However, any impediments to 
siting are the same whether the utility is providing service to itself 
or to a third party.
    On the third issue set for hearing AEP, et al. (the costs of 
providing comparable service), we believe there is no difference in the 
costs incurred by a transmission provider in providing transmission to 
itself or to a third party. Thus, the transmission owner must charge 
itself and third parties the same rates for the use of its system.
    All electricity trade is supported and facilitated in one way or 
another by ancillary services, and transmission services may be 
comprised of many different combinations of ancillary services. 
Therefore, the Commission will require that such ancillary services be 
offered separately through open access tariffs. These are discussed in 
detail infra.
    Public utilities that are transmission-only companies or transcos, 
i.e., companies that do not own or control generation, do not use their 
own transmission systems to sell their own power. However, a public 
utility transco would be required to offer open access transmission 
services as well as ancillary services. It would also have to provide a 
real-time information network, as discussed below. The Commission is 
also announcing certain quality-of-service guidelines to aid in 
evaluating the quality of transmission service that must be provided by 
public utilities. These are described infra and are reflected in 
proposed pro forma point-to-point and network tariffs 
[[Page 17681]] attached to this notice of proposed rulemaking. Our 
preliminary conclusion is that the provisions contained in the pro 
forma tariffs are the minimum provisions necessary to meet the 
requirement of non-discriminatory open access. We seek comments on 
these tariffs.
2. Implementing Non-Discriminatory Open Access: Functional Unbundling
    The Commission's preliminary view is that functional unbundling of 
wholesale services is necessary to implement non-discriminatory open 
access. Accordingly, the proposed rule requires that a public utility's 
uses of its own transmission system for the purpose of engaging in 
wholesale sales and purchases of electric energy must be separated from 
other activities, and that transmission services (including ancillary 
services) must be taken under the filed transmission tariff of general 
applicability. The proposed rule does not require corporate unbundling 
(selling off assets to a non-affiliate, or establishing a separate 
corporate affiliate to manage a utility's transmission assets) in any 
form, although some utilities may ultimately choose such a course of 
action. The proposed rule accommodates corporate unbundling, but does 
not require it.
    Functional unbundling means three things. First, it means that 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 under which others take 
service. New wholesale sales and purchases are those under any 
contracts executed on or after the open access tariffs required by this 
proposed rule become effective. Non-discriminatory service requires 
that the utility charge itself the same price for these services that 
it charges its third-party wholesale transmission customers. We seek 
comment as to the appropriate means to enforce this requirement, such 
as a revenue crediting mechanism.
    Second, functional unbundling means that a transmission owner must 
include in its open access tariffs separately stated rates for the 
transmission and ancillary service components of each transmission 
service it provides.<SUP>184 The rates must satisfy the Commission's 
Transmission Pricing Policy Statement. Third, functional unbundling 
means that the public utility, in order to provide non-discriminatory 
open access to transmission and ancillary services information, must 
rely upon the same electronic network that its transmission customers 
rely upon to obtain transmission information about its system when 
buying or selling power.

    \184\This means that a customer who buys both generation and 
transmission services from the utility will have a separately stated 
rate for the generation, transmission, and ancillary services that 
it purchases. The rates for transmission and ancillary services 
would be stated in the open access tariff. The rates for the 
generation service would be under a separate rate schedule.
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    For example, the proposed rule requires that a public utility 
unbundle its new wholesale requirements service contracts, and its new 
wholesale coordination purchase transactions, and take the firm network 
transmission component of those services under its own firm network 
transmission tariff. Similarly, the proposed rule requires that a 
public utility unbundle any new wholesale coordination sales 
transactions and take the point-to-point transmission component of that 
service under its own point-to-point transmission tariff. Finally, the 
proposed rule requires that a utility unbundle ancillary services and 
take these services under its network and point-to-point tariffs.
    Public utilities also must authorize their power pool agents to 
offer any transmission service available under power pool arrangements 
to all transmission customers. In addition, public utilities that 
participate in a power pool that acts as a control area must authorize 
the power pool's control center to offer ancillary services under a 
filed tariff, and must take all of their control area services from 
that tariff.<SUP>185 A public utility must take dispatch service and 
other ancillary transmission services on the same terms and conditions 
as those offered to its transmission customers.<SUP>186

    \185\Similarly, public utilities that own transmission, but get 
their ancillary services from another entity must authorize that 
entity to provide ancillary services under a filed tariff and must 
take their ancillary services from that tariff.
    \186\The Commission recognizes that the proposal here overlaps 
with the pending Pooling Notice of Inquiry. However, the fundamental 
non-discrimination requirements of the FPA, and therefore the basic 
requirements of the proposed rule, must be applied to power pools in 
which public utilities participate. This issue is discussed further 
in the Implementation Section, infra.
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    The requirement to provide ancillary services and to take those 
services under a tariff is not intended to mandate any federal rules 
that would prescribe the actual merit order of dispatch. Rather, it is 
a requirement that public utilities ensure that dispatch practices and 
procedures applicable to them are also applied to third-party 
transmission customers.
    The proposed requirement that a public utility take transmission 
service used for wholesale requirements service and wholesale 
coordination transactions under its own filed tariff means that all 
wholesale trade, both that of the public utility and its competitors, 
would be taken under a single wholesale transmission tariff. Our 
preliminary view is that such a requirement places the correct 
incentives on the public utility to file a fair tariff since it must 
live under those terms for wholesale purposes. The Commission invites 
comment on its approach to functional unbundling. Will it provide 
strong enough incentives for non-discriminatory access without some 
form of corporate restructuring? If utilities restructure, how will our 
proposed rules apply to different types of corporate structures?
    While this approach to unbundling creates good incentives with 
respect to wholesale service, it omits retail service. In other words, 
it does not require the transmission owner to take unbundled 
transmission service under the same tariff as third parties in order to 
serve its retail customers. This will result in 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. It also raises the possibility that the 
quality of transmission service for retail purposes will be superior to 
the quality of transmission service offered for wholesale purposes.
    We seek comment on how this bifurcated approach would affect the 
public utility's incentives to provide non-discriminatory open access 
wholesale transmission service. For example, will planning of 
incremental transmission facilities be comparable or will the 
transmission provider's retail customers retain an advantage from 
having expansion costs placed on third parties? What would be the 
benefits of an approach that required the transmission provider to take 
unbundled transmission service for both wholesale and retail purposes 
under the same tariff used by third-party transmission customers? Is 
such an approach necessary to ensure that all participants have the 
same incentives to achieve non-discriminatory open access transmission 
service and competitive power markets? What would be the disadvantages, 
if any, of such an approach?
    The Commission recognizes that the unbundling of transmission for 
retail purposes would intrude upon matters that state commissions have 
traditionally regulated. One possible approach that would unify service 
standards for wholesale and retail [[Page 17682]] service would be for 
each vertically integrated utility to establish a distribution function 
that would be responsible for obtaining transmission service on behalf 
of retail customers. This distribution function then could be treated 
just as any other wholesale customer. The distribution function of the 
utility would take service under the single Commission filed tariff. 
This could change the traditional approach of state-federal allocation 
of transmission costs. The Commission seeks comment on the merits of 
such an approach. How could the Commission cooperate with state 
commissions if it were to adopt such an approach?
    Finally, we address a specific type of retail service that we 
believe to be ``bundled'' retail service in name only: a so-called 
``buy-sell'' transaction 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 ``bundled'' retail sale to the end user. We have determined that in 
these types of transactions the retail ``bundled'' sale is actually the 
functional equivalent of two unbundled retail sales: (1) A voluntary 
sale of unbundled transmission at retail in interstate commerce, 
subject to our exclusive jurisdiction;<SUP>187 and (2) a sale of 
unbundled generation at retail, subject to the state's 
jurisdiction.<SUP>188 For these types of sales, public utilities will 
have to provide the voluntary retail transmission component of the sale 
under a FERC-filed tariff consistent with the substantive requirements 
of this proposed rule.

    \187\As discussed infra, there would be a component of local 
distribution in such a transaction, subject to the state's 
jurisdiction.
    \188\This determination is consistent with our findings 
regarding similar types of transactions in the natural gas area. See 
El Paso Natural Gas Company, 59 FERC para.61,031 (1992), dismissed 
sub nom. Windward Energy and Marketing Company v. FERC, No. 92-1208 
(D.C. Feb. 2, 1994).
---------------------------------------------------------------------------

    We are aware that some public utilities are already contemplating 
initiating this type of ``buy-sell'' service. Similar services occurred 
in the natural gas area, but the Commission did not address the 
jurisdictional issue until a substantial number of transactions had 
been negotiated and implemented. When the Commission ultimately 
addressed the natural gas buy-sell programs, we concluded that we have 
jurisdiction over buy-sell transactions since such agreements utilize 
interstate transportation.<SUP>189 We were concerned then, just as we 
are concerned now, that interstate and intrastate programs operate 
together in an appropriately integrated way.<SUP>190 It is our 
preliminary view that the interstate transmission aspect of the buy-
sell program must take place under a FERC-filed tariff.

    \189\Id.
    \190\56 FERC para.61,289 at 62,133 (1991).
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    In imposing this requirement we wish to stress that the state has 
jurisdiction to determine which group of retail customers may 
participate in such a program. We also recognize that state regulatory 
commissions will be called upon to determine whether they have 
jurisdiction under state law over retail wheeling or direct access 
programs and, if so, whether to authorize such programs.<SUP>191 
However, the rates, terms, and conditions for the interstate 
transmission aspects of the program are jurisdictional to this 
Commission.

    \191\This Commission does not have authority to order retail 
wheeling. Section 212(h) of the Federal Power Act, as amended by the 
Energy Policy Act of 1992, Pub. L. 102-486, 106 Stat. 2776.
---------------------------------------------------------------------------

    The Commission did not address this jurisdictional issue at an 
early state in the evolution of competition in the natural gas market. 
Consequently, when we finally acted we chose to grandfather ongoing 
programs so that energy supply arrangements would not be 
disrupted.<SUP>192 We do not want to face that difficulty again. Thus, 
we are addressing the issue at an early stage so that public utilities 
and their customers will be on notice of the jurisdictional 
implications of their actions, and can make plans accordingly.

    \192\59 FERC para.61,031 (1992); reh'g denied, 60 FERC 
para.61,117 (1992).
3. Real-Time Information Networks
    With this proposed rule, the Commission is issuing a Notice of 
Technical Conference and Request for Comments on a proposal to require 
that public utilities provide all transmission users, including the 
transmission owner or controller, simultaneous access to transmission 
and ancillary services information through real-time information 
networks that would operate under industry-wide standards. Based upon 
the lessons we have learned from our experience with gas pipeline EBBs, 
we believe the proposed approach is necessary and can work.
4. Non-Discriminatory Open Access Tariff Provisions
    It is important that the tariffs filed to meet the non-
discriminatory open access service requirement contain terms and 
conditions necessary to ensure a certain minimum level of service 
quality and to provide a level of certainty to both customers and 
transmission service providers as to procedures and obligations. The 
discussion in this section is intended to give guidance about our 
proposed non-discriminatory open access requirements. The terms and 
conditions discussed here are reflected in the pro forma tariffs in 
Appendices B and C.<SUP>193

    \193\These Appendices will not appear in the Federal Register.
---------------------------------------------------------------------------

    We note at the outset two basic principles proposed to be used when 
evaluating tariff terms. First, the terms and conditions governing 
service should be clear and specific. Vague or general tariff terms 
introduce uncertainty, controversy and delay. In many situations, 
delaying access or increasing the transaction cost of access is, for 
all practical purposes, denying access. Second, any restrictions or 
limitations on service or procedures must be limited to technical or 
operational needs that can be verified, and they must be the least 
restrictive way to meet those needs.<SUP>194

    \194\However, as discussed infra, in determining the level of 
capacity that must be made available for new transmission service 
requests, we have proposed that capacity needed to meet current and 
reasonably forecasted native load and to meet existing contractual 
obligations may be excluded from capacity made available for new 
transmission service requests.
---------------------------------------------------------------------------

    The Commission invites comment on the terms and conditions proposed 
as well as whether others may be necessary.
    a. Customer eligibility. A non-discriminatory open-access tariff 
must be available to any entity that can request transmission services 
under section 211.<SUP>195

    \195\Under 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.
---------------------------------------------------------------------------

    b. Expansion obligation. A public utility must offer to enlarge its 
transmission capacity (or expand its ancillary service facilities) if 
necessary to provide transmission services. This provision is necessary 
to mitigate the utility's transmission market power that could be 
exercised by restricting capacity. The customer must agree to 
reasonable terms, conditions and prices, including the financial 
responsibility for its share of the incremental expansion 
costs.<SUP>196

    \196\See, e.g., Northeast Utilities Service Company, 56 FERC 
para.61,269 at 62,022 (1991), order on reh'g, 58 FERC para.61,070, 
reh'g denied, 59 FERC para.61,042 (1992), remanded, 993 F.2d 937 
(1st Cir. 1993), order on remand, 66 FERC para.61,332 (1994) 
(Northeast Utilities) (wheeling customer must provide reasonable 
financial assurance before the public utility undertakes substantial 
investments in new facilities for that customer).
---------------------------------------------------------------------------

    The Commission recognizes that a utility may not be able to enlarge 
transmission capacity because it cannot obtain the necessary approvals 
or property rights under applicable [[Page 17683]] Federal, state and 
local laws. If the utility has failed after making and documenting a 
good faith effort to obtain the necessary approvals or property rights, 
it can request to be relieved of its expansion obligation by an 
appropriate filing at the Commission.<SUP>197 This will result in 
consistent treatment under FPA sections 205 and 206 and FPA section 
211.

    \197\However, we have previously noted that a utility may bear a 
heavy burden in demonstrating that it cannot enlarge its 
transmission capacity to meet a new transmission request. See 
Northeast Utilities, 58 FERC at 61,209.
---------------------------------------------------------------------------

    c. Service obligation. The transmission tariff must offer non-
discriminatory transmission services (including related ancillary 
services that the utility can provide) to eligible transmission 
customers. For example, a tariff should make available both flexible 
(i.e., firm and non-firm) point-to-point transmission service and 
network transmission service, as well as those ancillary services 
necessary to accomplish such transmission services.
    (1) Network Transmission Service. Network transmission service 
allows a transmission customer to use the entire transmission network 
to provide generation service for specified resources and specified 
loads without having to pay a separate charge for each resource-load 
pairing. Such service allows a transmission customer to integrate, 
plan, commit, economically dispatch, and regulate its resources to 
serve its consolidated load. Network service provides the customer with 
the same flexible network usage needed to optimize its resources to 
meet its customers' needs that transmission owners have to optimize 
their resources to meet their customers' needs. Network service 
includes the ability to import power from other control areas to 
economically and reliably serve the customers' load. Non-discrimination 
requires that network service be made available in an open access 
tariff.
    Network service would be valuable to customers such as municipals, 
cooperatives, and municipal joint action agencies that supply the long-
term firm power needs of members with multiple loads that are wholly or 
partly within a single transmission system. Indeed, network service is 
essential for the resource integration that is needed for efficient 
operation. For example, a generation and transmission cooperative whose 
generating facilities and member cooperatives are widely dispersed may 
not own all of the transmission facilities needed to link the 
generators with the members' distribution systems. In this case, the 
cooperative must rely on a transmission-owning utility to provide 
network service. Without such service, the cooperative would have 
difficulty supplying reliable, efficient power to its own members.
    (2) Flexible Point-to-Point Service. The second required service in 
a non-discriminatory open access tariff is point-to-point transmission 
service. Both firm and non-firm service must be available on a point-
to-point basis. Under firm point-to-point service, the transmission 
owner would provide firm deliveries of power from designated points of 
receipt to designated points of delivery. Each point of receipt would 
be set forth in a service agreement along with a corresponding capacity 
reservation for that point of receipt. Each point of delivery would be 
set forth in the service agreement along with a corresponding capacity 
reservation for that point of delivery. The greater of (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 would be the firm 
capacity reservation for which the transmission customer would be 
charged.
    However, firm point-to-point service must have the same flexibility 
in use as that available to the transmission provider and obligate the 
transmission provider to supply non-firm transmission service, if 
available, over non-designated receipt and delivery points (or over 
designated receipt and delivery points in excess of its firm 
reservation at those points) without incurring any additional charges 
(or executing a new service agreement) so long as the customer's use 
does not exceed its total firm capacity reservation. Any use by a 
customer in excess of its firm capacity reservation at each point of 
receipt or point of delivery will be on an as-available basis and will 
be treated as non-firm service. A customer may also request non-firm 
point-to-point transmission service on a stand-alone basis.
    Transmission customers may be willing to trade off the higher risk 
of interruption with non-firm service for the lower non-firm 
transmission rate. Customers should be able to make that choice, which 
will depend on their own balancing of the risk of transmission service 
interruption with the interruptibility of, and trade gains associated 
with, the power resource. It is important that the customer, not the 
transmission provider, make this choice. The tariff should not restrict 
non-firm transmission service to the transporting of only non-firm 
power transactions.<SUP>198

    \198\See Entergy Services, Inc., 58 FERC para.61,234 at 61,767, 
order on reh'g, 60 FERC para.61,168 (1992), rev'd on other grounds 
sub nom. Cajun Electric Power Cooperative, Inc. v. FERC, 28 F.3d 173 
(D.C. Cir. 1994).
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    Tariffs should offer flexible point-to-point transmission service 
for transactions that involve power flows into, out of, within or 
through the control areas. Whether or not a transmission provider 
actually undertakes such specific services on its own behalf, it has 
the flexibility to do so. Therefore, if service to third parties is to 
be non-discriminatory, they, too, must have such flexibility. In 
addition, tariff restrictions on receipt and delivery points should not 
preclude particular types of transactions. For example, a transmission 
provider should not limit receipt and delivery points to points of 
interconnection with other transmission systems because such a 
restriction may preclude transactions that originate or terminate with 
generation or particular loads within a transmission provider's control 
area.
    (3) Ancillary Services. Ancillary services are those services 
necessary to support the transmission of electric power from seller to 
purchaser given the obligations of control areas and transmitting 
utilities within those control areas to maintain reliable operations of 
the interconnected transmission system. Basic transmission service 
without ancillary services may be of little or no value to prospective 
customers. A variety of ancillary services is needed in conjunction 
with providing 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 (such as load following, 
reactive power support, and system protection services). Other 
ancillary services are needed to correct for the effects associated 
with undertaking a transaction (such as loss compensation and energy 
imbalance services). Due to the nature of certain ancillary services 
(such as scheduling and dispatching service), the transmission provider 
may be uniquely positioned to provide these services. However, for 
other ancillary services (such as loss compensation service), the 
customer may wish to provide the service itself or purchase the service 
from a party other than the transmission owner or its agent.
    If the transmission provider provides the ancillary services for 
its own use of the transmission system, the public utility should offer 
in the tariff to provide ancillary services for transmission customers. 
Tariffs should [[Page 17684]] commit to provide specific ancillary 
services at specific prices or under specific compensation methods that 
are clearly described.
    If the transmission provider obtains ancillary services from a 
third party, e.g., does not operate its own control area or obtains 
ancillary services from a pool, the transmission provider should offer 
in the tariff to secure ancillary services for transmission customers 
from that third party. Examples of such third-party arrangements may 
include a public utility obtaining ancillary services from a power pool 
or from a control area operator.
    Based on our experience to date, we propose that the following 
ancillary services should be offered in the tariff:
1. Reactive Power/Voltage Control Service
    In order to maintain transmission voltages on the transmission 
provider's transmission facilities within acceptable limits, 
transmission facilities and some or all generation facilities (in the 
service area where the transmission provider's transmission facilities 
are located) are operated to produce (or absorb) reactive power. Thus, 
the need for reactive power/voltage control service must be considered 
for each transaction on the transmission provider's transmission 
facilities. The amount of reactive power/voltage control 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.
    The transmission provider will be responsible for providing the 
necessary transmission-related reactive power support. A transmission 
customer may elect (or arrange through a third party) to supply some or 
all of the necessary generation-related reactive power/voltage control 
support to the extent that it (or the third party) has the ability to 
supply such reactive power. If the transmission customer elects (or 
arranges through a third party) to provide reactive power/voltage 
control support, such service must be coordinated with the transmission 
provider (or the entity that is responsible for the operation of the 
transmission provider's transmission facilities). Alternatively, the 
transmission provider will supply the necessary generation-related 
reactive power/voltage control support.
2. Loss Compensation Service
    Capacity and energy losses occur when a transmission provider 
delivers electricity across its transmission facilities for a 
transmission customer. A transmission customer may elect to (1) supply 
the capacity and/or energy necessary to compensate the transmission 
provider for such losses, (2) receive an amount of electricity at 
delivery points that is reduced by the amount of losses incurred by the 
transmission provider, or (3) have the transmission provider supply the 
capacity and/or energy necessary to compensate for such losses.
3. Scheduling and Dispatching Services
    Scheduling is the control room procedure to establish a pre-
determined (before-the-fact) use of generation resources and 
transmission facilities to meet anticipated load (including 
interchange). Dispatching is the control room operation of all 
generation resources and transmission facilities on a real-time basis 
to meet load within the transmission provider's designated service area 
(or other larger area of coordinated dispatch operation). Scheduling 
and dispatching services are to be provided by the transmission 
provider or other entity that performs scheduling and dispatching for 
the transmission provider's service territory.
    In certain regions, dynamic scheduling is also allowed. Dynamic 
scheduling involves responding to load changes or controlling 
generation within one transmission provider's service territory (or 
other larger area of coordinated dispatch operation) through the real-
time control and dispatch of another transmission provider. Under 
dynamic scheduling, the operator of an area of coordinated dispatch 
(control area) agrees to assign certain customer load or generation to 
another area of coordinated dispatch, and to send the associated 
control signals to the respective control center of that area. Dynamic 
scheduling is implemented through the use of special telemetry and 
control equipment. The transmission customer must be allowed to use 
dynamic scheduling when it is feasible and reliable.
4. Load Following Service
    Load following service is necessary to provide for the continuous 
balancing of resources (generation and interchange) with load under the 
control of the transmission provider (or other entity that performs 
this function for the transmission provider). Load following service is 
accomplished by increasing or decreasing the output of on-line 
generation (predominantly through the use of automatic generating 
control equipment) to match moment-to-moment load changes. The 
obligation to maintain this balance between resources and load lies 
with the transmission provider (or other entity that performs this 
function for the transmission provider). Because of the nature of this 
service, the transmission provider (or other entity that performs this 
function for the transmission provider's facilities) may be uniquely 
positioned to provide load following service. Therefore, unless the 
transmission customer is able to obtain such service from its own 
generation or from third-party generation that is capable of supplying 
such service in accordance with conditions generally accepted in the 
region and consistently adhered to by the transmission provider, the 
transmission provider will supply load following service.
5. System Protection Service
    A transmission provider must have adequate operating reserves or 
other system protection facilities available in order to maintain the 
integrity of its transmission facilities in the event of (1) 
unscheduled outages of a portion of its transmission facilities or 
facilities connected to the transmission provider's service territory 
or (2) unscheduled interruption of energy deliveries to the 
transmission provider's transmission facilities. The amount of system 
protection service that must be supplied with respect to the 
transmission customer's transaction will be determined based on 
operating reserve margins or other relevant criteria that are generally 
accepted in the region and consistently adhered to by the transmission 
provider.
    The transmission customer may elect or arrange through a third 
party to provide resources that are sufficient to satisfy the system 
protection needs of the transmission provider. Operation and dispatch 
of such resources must be coordinated with the transmission provider or 
other entity that maintains operating reserves and other system 
protection facilities for the transmission provider's service 
territory.
6. Energy Imbalance Service
    Energy Imbalance Service is provided when a difference occurs 
between the hourly scheduled amount and the hourly metered (actual 
delivered) amount associated with a transaction. Typically, an energy 
imbalance is eliminated during a future period by returning energy in-
kind under conditions similar to those when the initial energy was 
delivered. [[Page 17685]] 
    The transmission provider shall establish a deviation band (e.g., 
+/-1.5 percent 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 30 days or a reasonable period of time that is generally 
accepted in the region and consistently adhered to by the transmission 
provider. If an energy imbalance is not corrected within 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. To the extent another 
entity 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 entity.
    We seek comment on our proposed treatment of ancillary services. 
Are there alternative ways to ensure the non-discriminatory provision 
of ancillary services? We also seek comment on the above-described 
ancillary services. Are they the appropriate ancillary services for the 
needs of entities seeking transmission service? Are the descriptions of 
the ancillary services appropriate? Should any of the described 
services not be offered, and if so, why? Are there other ancillary 
services that should be offered? Should all ancillary services be 
offered as discrete services with separate prices, or should certain 
ancillary services be offered as a package? Additionally, we seek 
comment on whether the additional complexity of obtaining ancillary 
service externally from the host control area with the use of dynamic 
scheduling is the appropriate course to follow.
    d. Service Periods. The duration of service reservations should not 
be unduly limited. Non-discriminatory service requires any such limits 
on third-party service to be the same as those the transmission 
provider or controller faces. In particular, the tariff should allow 
firm service contracts to extend at least for the life of a customer's 
power plant or purchase contract. Power developers are unlikely to 
build new plants if they cannot secure firm transmission services for 
the plant's life. Integrated transmission owners plan their 
transmission systems to ensure capacity to deliver the output of their 
own planned generation units. Non-discriminatory service requires the 
same for transmission-only customers. Likewise, the minimum duration 
for service should be the same as the minimum scheduling period of the 
transmission owner. All minimum or maximum restrictions must be 
justified on a technical or operational basis.
    e. Reassignment Rights. A tariff must explicitly permit 
reassignment of firm service entitlements. Capacity reassignment rights 
can have a number of benefits. First, reassignment rights are important 
in helping transmission users manage the financial risk associated with 
long-term commitments to take transmission service. A robust 
reassignment market would aid, among others, customers who can get or 
must take transmission capacity now but do not actually need it until 
some time in the future, and customers whose need for capacity they 
have under contract is intermittent or suddenly declines. Transmission 
owners have the flexibility to manage this sort of risk by offering 
transmission capacity to others. Non-discriminatory service demands 
that non-owner holders of rights to transmission capacity have the same 
flexibility to manage their risk as owners have.
    Second, capacity reassignment, combined with assured access to firm 
transmission service, reduces the transmission provider's market power 
by enabling transmission customers to compete with the owner to some 
extent in the firm transmission market. To promote competition in such 
a secondary market, firm service rights should be defined as broadly as 
possible, consistent with reliable operation of the system. In 
particular, using firm transmission capacity to deliver non-firm power 
or repackaging firm transmission capacity for sale as non-firm capacity 
should not be unduly restricted.
    Third, the ability to reassign capacity rights can also improve 
capacity allocation. When capacity is constrained and some market 
participants value capacity more than current capacity holders, the 
current holders may be willing to reassign their capacity rights at 
rates below the opportunity costs of the transmission provider, thereby 
lowering rates to the new customer. We note that the prices of 
reassignments are currently capped at the price the public utility sold 
the transmission.<SUP>199 The Commission invites comments on whether 
the current price cap on resale should be modified or eliminated.

    \199\See Florida Power & Light Company, 66 FERC para.61,227 at 
61,524 (1994), order on reh'g, 70 FERC para.61,150 (1995). The 
Commission has required a similar cap for released pipeline 
capacity. See Order No. 636-A, Pipeline Service Obligations and 
Revisions to Regulations Governing Self-Implementing Transportation 
Under Part 284 of the Commission's Regulations, Regulation of 
Natural Gas Pipelines After Partial Wellhead Decontrol and Order 
Denying Rehearing in Part, Granting Rehearing in Part, and 
Clarifying Order No. 636, Ferc Stats. & Regs. para.30,950 at 30,560 
(1992), appeal pending.
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    In addition, the service agreement must state clearly the 
respective obligations of the original right holder and any subsequent 
purchaser of the right. In particular, it should state the conditions, 
if any, under which the original right holder can be released from its 
obligations under the service agreement if the right is reassigned or 
sold. Any reassignments must be done in a not unduly discriminatory 
manner. We invite comment on these reassignment issues.
    Given the current specification of basic transmission services 
(network, flexible point-to-point, and ancillary), some services may be 
more reassignable than others. The ease with which rights can be 
reassigned depends on two factors: the ability of ensuring operational 
feasibility and the specificity of contract rights. Point-to-point 
service involves a well-specified right to transfer a given amount of 
power between specific points or across an interface under certain 
conditions. The transmission provider is operationally indifferent as 
to who wants to transfer the power that flows between those points. 
Thus, point-to-point service is well-suited to reassignment.
    Network service, as currently defined, is idiosyncratic because it 
is unique to the transmission user receiving the service. This service 
is purchased to integrate a set of resources into a set of loads given 
specific dispatch parameters and load profiles. The transmission 
provider has to plan and operate its system for this specific service. 
It is not clear that such service could be of any value to an entity 
other than the original buyer. It is also not clear precisely what 
would be resold because network customers do not have rights to a 
specific amount of transmission capacity, but have rights only to a 
varying amount of capacity needed to integrate load with their 
dispersed power resources.<SUP>200 Such indeterminate rights may not be 
amenable to reassignment. We seek comments on reassigning network 
service. Can network service be structured such that 
[[Page 17686]] capacity rights could be specified and reassigned?

    \200\In FP&L, the Commission approved network service billing 
based on a load ratio method of cost allocation, instead of on 
contract demand.
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    Ancillary services also may not be suitable for reassignment. We 
seek comments on these reassignment issues.
    e. Reciprocity provision. The Commission proposes to require that 
transmission tariffs contain a reciprocity provision.<SUP>201 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.

    \201\The Commission previously accepted tariffs that contain 
reciprocity provisions. See, e.g., El Paso Electric Company and 
Central and South West Services Inc., 68 FERC para.61,181 at 61,916 
(1994), reh'g pending; Southwestern Electric Power Company and 
Public Service Company of Oklahoma, 65 FERC para.61,212 at 61,981-82 
(1993), reh'g denied, 66 FERC para.61,099 (1994).
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    f. Available Transmission Capacity (ATC). ATC is capacity that must 
be made available for new firm transmission service requests. 
Basically, it is the capacity not committed to other firm uses during 
the scheduling interval(s) for which service is requested. The tariff 
must clearly specify the other uses for which capacity will be excluded 
from ATC. Acceptable other uses may include:
    <bullet> A requirement to meet generally applicable reliability 
criteria.
    <bullet> Meeting current and reasonably forecasted load (retail 
customers and network transmission customers) on the transmission 
provider's system. The term ``reasonably forecasted'' should be defined 
in terms of the utility's current planning horizon. Capacity needed to 
serve reasonably forecasted load must be made available until the 
forecasted load develops.
    <bullet> Fulfilling the transmission provider's current firm power 
and firm transmission contracts.
    <bullet> Meeting pending firm transmission service requests.
    In the tariff, the utility must commit to provide an index of other 
holders of firm transmission entitlements and describe the method used 
to estimate ATC in sufficient detail to allow others to do the same 
analysis. The utility must make all data used in calculating the ATC 
publicly available. The methodology and the data used to develop the 
ATC must be consistent with the information submitted in the FERC Form 
No. 715, Annual Transmission Planning and Evaluation Report.<SUP>202

    \202\See Order Nos. 558 and 558-A, supra note 92.
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    Capacity can be withheld from ATC only if it is to be used during 
the scheduling period for which service is requested. For example, if a 
customer requests firm service for ten years and the utility needs that 
capacity to serve native load during years six to ten, the utility must 
provide service using the existing capacity for the first five years 
and then use expanded capacity or some other alternative arrangement 
for the third-party service during the remainder of the term.
    Under the proposed rule, ATC information will be required to be 
made available in the public utility's information system. The nature 
of the ATC information to be made available and the manner in which it 
is made available will be the subject of the real-time information 
networks technical conference that we are concurrently initiating.
    g. Procedures for obtaining service. This section must clearly 
describe all notice and response requirements, including deadlines for 
each step in the process, the information required in a valid request 
for service, the procedure for obtaining service from existing capacity 
and the additional steps to follow when capacity expansion is required. 
The discussion below highlights some particularly important aspects of 
procedures for obtaining service.
    The tariff must specify minimum notice periods. Notice for 
accepting requests for short-term service is particularly important. 
Because market opportunities may be short-lived, the advance notice 
required for short-term service should be as brief as possible and 
should be able to be secured through the real-time information network. 
Similarly, the tariff also should specify the minimum time needed to 
accommodate customers' needs to plan and construct new generating units 
or to enter into long-term power supply contracts.
    A tariff must specify the information that must accompany a service 
request. This information should generally track that specified in the 
Commission's Policy Statement Regarding Good Faith Requests for 
Transmission Services.<SUP>203 The tariff should require only 
information that is clearly necessary to determine whether capacity is 
available, the price for the service requested and other information 
necessary to process the service request.

    \203\See supra note 91.
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    A tariff may require scheduling of receipt and delivery points and 
amounts of energy flows but not require disclosure of power contract 
terms as part of the request process. While the Commission has accepted 
such a requirement in some tariffs, our preliminary view is that there 
are less intrusive and less ambiguous ways of dealing with transmission 
owner concerns. If the concern is the need to know intended power 
flows, the needed information of the anticipated transaction can be 
specified in a service request.
    The concern may be that a customer will reserve scarce capacity and 
then hold it without using it (for whatever reason). While reservation 
holders as well as transmission providers should not be allowed to 
withhold capacity, there are less restrictive options for dealing with 
this concern. One is to allow the transmission provider to use or sell 
the capacity for so long as the reservation holder is not using it. 
Another is to have a pool that clears the short-term market. Of course, 
the reservation holder would be compensated. Another option is to 
require the customer to begin using the capacity within some period or 
lose its reservation rights for that capacity. Any of these 
alternatives can allay legitimate concerns without forcing customers to 
reveal unnecessary details of the transaction. The Commission requests 
comments on these and other approaches. Could pooling help address 
these issues? In particular, how would a use-it-or-lose-it rule work? 
How would a utility know which reservation holder to compensate with 
non-firm revenues if network service customers hold no reservation 
rights? Non-firm revenues could be shared among load-ratio customers 
and reservation customers on the basis of the non-use of the firm 
entitlements.
    With respect to network service, our preliminary view is somewhat 
different. Because network service is billed on a load ratio basis, 
customers would have the incentive to specify unlimited generation 
resources to be integrated into their load without any commensurate 
financial obligation. The transmission provider would nevertheless have 
to plan its system to dispatch those resources. Thus, network 
customers, when designating their network resources, must show that 
they own or have contracted for those resources. We seek comment on 
this issue. Are there alternative ways of dealing with this problem for 
network service?

[[Page 17687]]

    The tariff should provide that, if service can be provided using 
existing capacity, a service agreement will be tendered in time for the 
customer to execute it so that service can begin at the time requested. 
The tariff should clearly state the applicable rates for service from 
existing capacity. In addition, the tariff should contain provisions, 
as well as rates, for reserving capacity now for use at a later time. 
Also, the tariff should contain a standardized service agreement that 
applies to all service provided from existing capacity.
    When existing capacity is not adequate to provide additional firm 
service, the tariff should require the transmission provider to 
prepare, if needed, an engineering study of options for expanding 
capacity, including the costs of each option, within a specified 
period. The customer should be required to pay the reasonable costs of 
performing the study. If the customer elects to take service after 
reviewing the engineering study and cost estimates, including 
supporting documentation, the transmission provider may require the 
customer to enter into a contract, provide a security deposit, and 
agree to take service at rates calculated in accordance with the 
pricing provisions of the tariff.<SUP>204 The tariff should allow the 
customer to specify the contract term.

    \204\See Energy Services, Inc., 58 FERC para.61,234 at 61,766 
and 61,768 (1992) (security deposit or some other form of assurance 
permitted; approval of provision requiring transmission customers to 
have ``suitable interconnection agreement'' with transmission-owning 
utility).
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    h. Service priority. Service priority becomes important when 
capacity is constrained (i.e., demand exceeds supply). This, in turn, 
has two aspects: when new service requests are considered and when, 
after service has begun, interruptions are required.
    (1) Considering new service requests. A tariff should specify a 
reasonable basis upon which service requests will be considered. As 
long as transmission capacity is available for all requests, they can 
all be accommodated. When capacity is short, however, the priority of 
requests is important because the determination as to which requests 
are met from existing capacity and which require expanded facilities 
will affect pricing. However, firm service requests should always 
receive priority over non-firm service requests, and firm service 
requests from third-party transmission customers should have the same 
priority as new transmission services for the public utility's native 
load.
    The industry currently operates under a contract rights regime 
whereby customers are given contract rights for a specific period at a 
set price. Under this regime, requests are generally processed under a 
first-in-time rule. Capacity is allocated in the order in which the 
requests were made. If available transmission capacity is exhausted, a 
requester may be required to pay the incremental cost of relieving the 
constraint. Incremental cost could be either the redispatch cost of 
unloading a line or the cost of expanding capacity. Thus, the position 
of the requester in the queue may affect price and possibly determine 
when service is provided. Alternatively, all requesters during a given 
period could be treated as making one request for a large increment of 
capacity and pay the same average incremental cost. We seek comments on 
appropriate ways to process requests.
    (2) Allocating interruptions. After service has begun, priority is 
important if capacity becomes unexpectedly constrained and service must 
be interrupted.<SUP>205 Contracts must spell out the obligations and 
priorities in dealing with operating and reliability procedures. 
Priorities will affect the order in which services are interrupted. A 
tariff must specify that firm transmission service always has priority 
over non-firm transmission service. Non-discriminatory service requires 
that firm transmission customers have the same assurance of 
uninterrupted use of the grid, within their contractual commitments and 
obligations, as the transmission provider. That is, the public 
utility's personnel who trade wholesale power should have the same firm 
transmission service as does a firm transmission customer. Both have 
the same standing when the control area operator deals with 
emergencies. That is, both must recognize that the operator is 
authorized to interrupt scheduled power transfers as needed in order to 
maintain reliability. Operators must be allowed to maintain safe and 
reliable service on the overall system.

    \205\Of course, the utility always may curtail if necessary to 
maintain the reliability of the system. For example, if a major 
transmission line fails, the utility may quickly have to interrupt 
transactions without regard to priority of service in order to 
stabilize the system. Once the system is stabilized, however, the 
utility should allocate remaining capacity on the basis of 
contractual priorities.
    Generally, interruption of firm transmission service should occur 
only because of: (1) Emergencies or force majeure; or (2) the need to 
maintain overall reliability or to protect equipment as prescribed in 
industry operating guidelines. The specific reasons for interruptions 
will have to be determined in accordance with the characteristics of 
each transmission provider's system. The tariff should require the 
provider to notify all customers in a timely manner of any scheduled 
interruptions, while recognizing the right to take appropriate actions 
under operating procedures to deal with unscheduled emergency 
conditions.
    i. Security deposits and creditworthiness. A tariff may require 
that a reasonable, returnable deposit accompany the request for 
service, and that the customer demonstrate basic creditworthiness. A 
creditworthiness investigation (including a security deposit 
requirement) must be applied on a non-discriminatory basis.
    j. Short-term and interruptible service agreements. A copy of 
standard transmission service agreements for short-term and 
interruptible transmission services must be included in the tariff in 
order to expedite service and limit the possibility of undue 
discrimination or other abuse. The tariff must list all information 
needed from the customer.
    k. Dispute resolution. The tariff must clearly set forth the steps 
to be followed to resolve disputes. Procedures should be designed to 
resolve conflicts quickly. This suggests the use of some type of 
alternative dispute resolution (ADR) process, such as mediation or 
arbitration. ADR would be especially useful when the dispute is over 
response times, capacity additions, a highly technical matter, or any 
matter that applies, but does not extend, existing Commission policy. 
The tariff should specify which types of disputes must go to ADR and 
which disputes must be taken directly to this Commission.
    A tariff should provide that capacity expansion proceed while cost 
disputes are pending, provided the customer agrees to pay the costs 
actually incurred and the rate ultimately determined by the Commission. 
This is needed to minimize delays when the customer wants the service 
but disputes the cost. Such a provision would require the transmission 
owner to proceed with whatever steps are necessary to provide service 
to the customer, as long as the customer agrees to furnish a deposit 
and state in writing that it will take service at the rates, terms and 
conditions that are ultimately found just and reasonable by the 
Commission, or to pay all out-of-pocket costs incurred in processing 
the request up to the date of cancellation of the request.
    l. Pricing. Transmission pricing must be consistent with the 
Commission's Transmission Pricing Policy 
[[Page 17688]] Statement.<SUP>206 We especially note that the 
transmission public utility must charge itself the same price for 
transmission services that it charges its third-party wholesale 
transmission customers.

    \206\See supra note 124.
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5. Pro Forma Tariffs
    Appendices B and C to this proposed rulemaking contain pro forma 
tariffs that contain the minimally acceptable terms and conditions of 
service for point-to-point and network transmission services. They 
contain tariff language that assures acceptable levels of service 
quality for non-price terms and conditions. For the most part, we have 
avoided specifying pricing provisions. The pro forma tariff provisions 
would of course be subject to case specific scrutiny to ensure that 
services are provided on a non-discriminatory open access basis. We 
seek comment on whether these tariffs provide a good basis for defining 
the minimum acceptable non-price terms and conditions of service.
6. Broader Use of Section 211
    The Commission intends to exercise its authority under sections 205 
and 206, as described in this proposed rule, in a complementary manner 
with its authority under section 211. Requiring all public utilities to 
file non-discriminatory open access tariffs, as set forth in this NOPR, 
will not alone ensure competitive bulk power markets in all regions of 
the United States. Many utilities providing transmission services are 
not public utilities subject to our full jurisdiction.<SUP>207

    \207\For example, there are approximately 56 electric utilities 
operating control areas in the United States that are not public 
utilities.
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    Section 211, however, permits entities to seek open access to all 
transmission facilities, including those owned by non-public utilities. 
Thus, to further eliminate unduly discriminatory practices in the 
industry, the proposed rule encourages the broad use of section 211.
    While the Commission cannot order transmission sua sponte under 
section 211, nothing in section 211 prohibits groups of qualified 
applicants from simultaneously or jointly filing applications for the 
same service. <SUP>208 Such group or joint action would permit the 
Commission to order tariffs of broader applicability.

    \208\This assumes, of course, that all have made the requisite 
request to the transmitting utility 60 days prior to filing. FMPA, 
for example, filed on behalf of numerous Florida municipals in the 
FP&L section 211 case. See Florida Municipal Power Agency v. Florida 
Power & Light Company, 65 FERC para. 61,125 (1993).
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    Moreover, sections 211 and 212 require that applicants specify only 
rates, terms, and conditions of service, not specific transactions. 
Thus, applicants can file requests for tariffs to accommodate future, 
currently unspecified, short-notice transactions, similar to the type 
of tariff filed by many utilities seeking approval of market-based 
rates or mergers.<SUP>209

    \209\See CSW, supra, 68 FERC at 61,916. Section 211 bars the 
Commission from ordering service that would unreasonably impair the 
continued reliability of electric systems affected by the order. To 
meet this requirement, the transmission owner and the applicant (or 
the Commission if necessary) can craft provisions in the general 
tariffs discussed above to assure that service will comply with 
standard industry operating practices and, thus, not have an 
unreasonable impact on reliability.
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    Section 211 bars the Commission from ordering service that would 
unreasonably impair the continued reliability of electric systems 
affected by the order. To meet this requirement, the transmission owner 
and the applicant (or the Commission if necessary) can craft provisions 
in the general tariffs discussed above to assure that service will 
comply with standard industry operating practices and, thus, not have 
an unreasonable impact on reliability.
    Finally, section 211 permits an opportunity for an evidentiary 
hearing.<SUP>210

    \210\Such a hearing is required only if there are material 
issues of fact in dispute. See Citizens for Allegan County, Inc. v. 
FPC, 414 F.2d 1125, 1128 (D.C. Cir. 1969).
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    Section 211 does not preclude applicants from lodging the record 
from a section 205 undue discrimination case involving the same 
service, nor does it preclude the Commission from incorporating and 
relying on the record and findings in a section 205 proceeding if the 
section 211 applicant, the transmitting utility, and the service 
requested are the same. In sum, sections 211 and 212 provide the 
Commission and the electric industry a much broader means to attain 
wider transmission access than has been achieved so far. In this 
regard, the Commission invites comment on further avenues the 
Commission can pursue to facilitate and expedite 211 applications.
    Section 211 also complements our section 205 and 206 authority in 
that it allows customers to request unique services not available in 
the non-discriminatory open access tariff. While our objective in this 
proposed rule is to implement a very broad service commitment in the 
non-discriminatory open access tariff, customers may have unique 
service needs that are not contemplated in the open access tariff.
7. Status of Existing Contracts
    There are three general types of existing wholesale contracts that 
could be affected by the proposed rule: (1) Requirements and other firm 
service contracts under which customers take bundled transmission and 
generation services; (2) coordination contracts for purchases or sales 
of economy energy; and (3) transmission-only contracts. The Commission 
believes that it can eliminate unduly discriminatory practices and 
achieve more competitive bulk power markets without abrogating existing 
contracts. Accordingly, as discussed supra, we have proposed to apply 
the unbundling requirement only to transmission services under new 
requirements contracts and new coordination transactions. In addition, 
although the open access tariffs must be open to all entities that 
could request transmission service under section 211, i.e., all non-
sham wholesale purchasers, we are not proposing to abrogate any 
existing power or transmission contracts. However, there may be 
situations in which it would be contrary to the public interest to 
allow existing wholesale power or transmission contracts to remain in 
effect. Accordingly, we 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.
8. Effect of Proposed Rule on Commission's Criteria for Market-Based 
Rates
    As stated above, one of the primary reasons for this rulemaking is 
to foster increased wholesale competition, in order to reduce prices 
for consumers. Moreover, the increased competition allowed by non-
discriminatory open access may allow lighthanded regulation of 
wholesale sales for many more transactions and perhaps throughout many 
regions.
    The Commission's standards for allowing market-based rates for 
wholesale power sales require an applicant and its affiliates to 
demonstrate that they lack or have mitigated market power in generation 
and transmission, that they cannot erect other barriers to 
entry,<SUP>211 and that there is no affiliate abuse or reciprocal 
dealing. In KCP&L,<SUP>212 the Commission [[Page 17689]] determined 
that it no longer needed to examine generation dominance in analyzing 
market-based rate proposals for sales from new generation facilities. 
However, the Commission has continued to evaluate generation dominance 
in analyzing market-based rate proposals for sales from existing 
generation capacity.<SUP>213

    \211\For applicants with transmission market power, the 
Commission has required the mitigation of such power through the 
filing of a non-discriminatory open access tariff. The Commission 
also has examined an applicant's control over potential barriers to 
entry, e.g., ownership or control of sites for generation 
facilities, generation equipment, or pipelines for supplying fuel.
    \212\67 FERC at 61,557.
    \213\See Entergy Services Inc., 58 FERC para.61,234 at 61,755 
(1992).
    If this rulemaking achieves the Commission's goals, and competition 
fueled by open access increases in the wholesale bulk power markets to 
the extent we expect, the increased competition may reduce or even 
eliminate generation-related market power in the short-term market. 
Increased wholesale competition could reduce the need for cost-based 
regulation of bulk power sales and allow broader use of market-based 
rates. For example, more competitive markets may allow us at some point 
to drop the generation dominance standard for existing capacity. We 
believe that the increased competition expected to result from this 
rulemaking may allow us to consider innovative approaches to 
authorizing market-based rates for generation. One suggestion in this 
regard has been that the Commission ought to consider filings made 
pursuant to section 205 seeking authorization of market-based rates for 
all sellers in a defined region. For example, such a region conceivably 
could be defined by the boundaries of an RTG, a power pool, a 
reliability council, or the less formal boundaries of an economic 
market. However, before proceeding to consider this suggestion, or any 
other innovative proposal for dealing with market-based rates for 
existing wholesale generation, the Commission must address certain 
threshold questions. Therefore, the Commission solicits comments on the 
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following questions:

    (1) Assuming that a final rule in this proceeding mandates that 
all public utilities must file generally applicable non-
discriminatory open access tariffs, would wholesale sellers of 
generation from existing generating facilities still possess market 
power?
    (a) Can we eliminate our generation dominance standard based on 
before-the-fact predictions of changes to come from our rulemaking, 
or must we rely on after-the-fact evidence of the changes that did 
occur?
    (2) For purposes of assessing whether existing wholesale 
generators still possess market power, how ought the relevant market 
be defined in an open access transmission environment? To what 
extent do the boundaries of a regional transmission group, a power 
pool, or a reliability council lend themselves to being used to 
define the relevant market in an open access environment?
    (3) Should it be determined that, notwithstanding non-
discriminatory open access transmission, existing generators still 
possess market power, can such market power be mitigated effectively 
to permit market-based rates for existing generation? And, if so, 
what are the Commission's options? For example:
    (a) Ought the Commission rely on rules of conduct, market 
mechanisms intended to ensure competition in wholesale power sales 
(such as bidding procedures) and monitoring as the means to curb 
such market power; or
    (b) Ought the Commission rely on structural reforms as the means 
to curb such market power?
    (4) Once the Commission has determined how to define the 
relevant market in an open access environment, ought the Commission 
entertain requests that all wholesale sellers within such a market 
be authorized to charge market-based rates?
9. Effect of Proposed Rule on Regional Transmission Groups
    In the Commission's Policy Statement Regarding Regional 
Transmission Groups (RTGs) we expressed support for the development of 
voluntary transmission associations and encouraged their formation. 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.
    Since the issuance of the Policy Statement, the Commission has 
given conditional approval to the bylaws of two RTGs.<SUP>214 Both 
approvals were conditioned on the members agreeing to offer comparable 
transmission services at least to other members, through either 
individual transmission tariffs or a generic regional tariff. For 
public utilities, that condition would be superseded by fulfillment of 
the requirements of the proposed rule.

    \214\See SWRTA and WRTA, supra.
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    To the extent public utilities view the comparability requirement 
in our two RTG orders as a disincentive to joining an RTG, that 
disincentive would be mooted. All such utilities will be required to 
file tariffs. Moreover, we will continue to provide substantial 
latitude for innovative pricing proposals by an RTG, as indicated in 
the Transmission Pricing Policy Statement.
    Some transmission users might conclude that the availability of 
comparability tariffs makes membership in an RTG less necessary. But, 
this conclusion would ignore the comparative benefit of a member having 
its needs planned for on a region-wide basis under an RTG instead of on 
a system-by-system basis. Coordination of planning that results in a 
more efficient system creates economies for both transmitting utilities 
and users.
    Also, the reduction in administrative burden for all parties 
involved in an RTG would remain. RTG members can work out their own 
disputes without incurring the substantial costs and delays involved in 
litigating at the Commission or in the courts. This fact alone makes 
for more flexible and responsive markets and reduces costs. Moreover, 
the Commission has stated its willingness to give deference to 
decisions resolved through RTG dispute resolution procedures.
    In short, RTGs are still a valuable tool in promoting wholesale 
competition and in achieving other Commission goals. RTGs are 
structures to reflect the interests of all of the grid's users, not 
just some. RTGs allow for consensual solutions to local or regional 
issues, instead of solutions imposed by FERC. RTGs can function as 
regional laboratories for experimentation on transmission issues. And, 
RTGs will provide a regional forum, a necessary predicate to regional 
cooperation. The potential benefits of RTGs would in no way be 
undermined by the rules proposed in this Open Access NOPR.

F. Stranded Costs and Other Transition Costs

1. Supplemental Notice of Proposed Rulemaking on Stranded Costs by 
Public Utilities and Transmitting Utilities
    a. Introduction. The Commission's Open Access NOPR would impose 
significant new requirements on public utilities--requirements that 
would help us to achieve the goal of robust competitive wholesale power 
markets, and that would result in a new way of doing business for 
utilities. The Open Access NOPR would give a utility's historical 
wholesale customers enhanced opportunities to reach new suppliers and, 
therefore, would affect the way in which utilities traditionally have 
recovered costs. We believe it is essential to address the transition 
issues associated with the move toward competition responsibly. The 
most significant of these issues is stranded cost recovery.
    The recovery of legitimate and verifiable stranded costs is 
critical to the successful transition of the electric utility industry 
from a tightly regulated, cost-of-service industry to an open 
[[Page 17690]] transmission access, competitively priced industry. 
Public utilities have invested billions of dollars in facilities built 
under a regulatory regime in which they have been permitted to recover 
all prudently incurred costs, plus the opportunity to earn a reasonable 
rate of return on their investment. <SUP>215 At the wholesale level 
(and in some instances the retail level), they are now entering a 
regulatory era in which they will have to compete to supply electric 
service. We believe that utilities should be allowed to recover the 
costs incurred under the old regulatory regime according to the 
expectations of cost recovery established under that regime.

    \215\Many also have committed millions of dollars to purchase 
power under long-term power supply contracts.
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    The primary goal of the Open Access NOPR is to promote competitive 
wholesale markets by assuring that all wholesale sellers of generation 
have the opportunity to compete on a fair basis and that all wholesale 
purchasers can reach alternative sellers. Ultimately, this should 
result in lowering electricity prices for the Nation's consumers. In 
the meantime, however, if a wholesale customer is able to leave its 
existing generation supplier to shop for power elsewhere, we do not 
believe the existing supplier's shareholders or its remaining customers 
should have to bear costs that were prudently incurred under the old 
regulatory system to serve the departing customer.
    We cannot successfully and fairly encourage the development of 
competitive wholesale markets as envisioned by the Open Access NOPR 
until we have made provision for electricity suppliers to seek recovery 
of existing uneconomic costs (primarily generation) which they already 
have incurred (i.e., those that could not earn a reasonable return in a 
competitive market). Recovery of legitimate and verifiable transition 
costs will permit all sellers, including the utilities who prudently 
incurred these costs, to compete on a more equal footing in competitive 
bulk power markets. In addition, while stranded cost recovery may delay 
some of the benefits of competitive bulk power markets for some 
customers, the Commission learned from its experience in the 
restructuring of the natural gas industry that these types of 
transition costs must be addressed at an early stage if we are to 
fulfill our regulatory responsibilities in moving to competitive 
markets. <SUP>216

    \216\See AGD, supra note 9, 824 F.2d at 1021-30. However, our 
mechanisms for addressing stranded costs in the electric industry 
differ from those used in the gas industry for the reasons discussed 
below.
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    The Commission believes that the approach proposed in the Stranded 
Cost NOPR issued on June 29, 1994 <SUP>217 should adequately cover 
most, if not all, costs that could be stranded in an environment where 
transmission access is more widely available, including the access 
environment that the Commission expects if the provisions of the Open 
Access NOPR are adopted. Some of the mechanisms proposed in the initial 
NOPR have been revised in this Supplemental NOPR to reflect submitted 
comments. In addition, there may be implementation or other issues 
raised by the open access requirements that were not contemplated when 
the Stranded Cost NOPR was originally proposed. Accordingly, we are 
issuing a Supplemental Notice of Proposed Rulemaking on Stranded Costs. 
In this Supplemental NOPR, we make preliminary determinations <SUP>218 
on certain issues and seek additional comments limited to the new 
matters proposed in this document, including the proposed open access 
requirements. We also propose to permit public utilities and 
transmitting utilities to seek recovery through transmission rates of 
stranded costs associated with a discrete set of existing wholesale 
requirements contracts.

    \217\See supra note 5.
    \218\If we were not issuing the Open Access NOPR, we would be 
inclined to adopt a final rule on stranded costs at this time. 
However, we are concerned that the Stranded Cost NOPR might not 
provide appropriate mechanisms to address transition costs that 
could result from the open access environment envisioned by this 
NOPR. Accordingly, our findings here are interlocutory in nature, 
and rehearing does not lie.
    b. Summary of Major Preliminary Determinations. In response to the 
June 29 Stranded Cost NOPR, the Commission received initial and/or 
reply comments from 128 entities, representing a broad cross-section of 
parties that participate in, or are affected by, the electric utility 
industry.<SUP>219 The Commission has carefully reviewed all of the 
comments, and made several preliminary determinations. First, we have 
determined that recovery of legitimate and verifiable stranded costs 
should be allowed, and that direct assignment of stranded costs to 
departing customers, as proposed in the Stranded Cost NOPR, is the 
appropriate method for recovery.<SUP>220

    \219\A list of commenters is attached as Appendix D.
    \220\As discussed infra, section III.F.1.c(13), however, this 
does not foreclose case-specific proposals for dealing with stranded 
costs in the context of voluntary corporate restructuring 
proceedings.
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    Second, with respect to stranded costs associated with new 
wholesale requirements contracts, <SUP>221 we reaffirm our proposal 
that a public utility may not seek recovery of such costs except in 
accordance with an exit fee or other explicit provision contained in 
the contract. The public utility may seek recovery in accordance with 
the contract. However, no public utility or transmitting utility may 
seek recovery of stranded costs associated with new requirements 
contracts through any transmission rate under section 205, 206 or 
211.<SUP>222

    \221\For recovery of wholesale stranded costs, the proposed rule 
distinguishes between stranded costs associated with wholesale 
requirements contracts executed after July 11, 1994, the date the 
proposed rule was published in the Federal Register (``new'' 
contracts) and stranded costs associated with wholesale requirements 
contracts executed on or before that date (``existing'' contracts). 
Stranded Cost NOPR at 32,860.
    \222\As we indicated in the Stranded Cost NOPR, if the seller 
under a new wholesale requirements contract is a transmitting 
utility subject to the Commission's jurisdiction under section 211 
of the FPA, but not also a public utility subject to the 
Commission's section 205-206 jurisdiction, there will be no 
Commission forum for addressing wholesale stranded costs associated 
with the new contract. Such utilities will not be able to seek 
recovery of wholesale stranded costs associated with such new 
contracts through rates for transmission services ordered under 
section 211, and the Commission does not have jurisdiction over 
their power sales contracts. Therefore, these utilities must address 
recovery of stranded costs through their new wholesale requirements 
contracts subject to the appropriate regulatory authority approval. 
Stranded Cost NOPR at 32,860-61.
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    Third, with respect to stranded costs associated with existing 
wholesale requirements contracts <SUP>223 that are not renewed and that 
do not contain exit fees or other stranded cost provisions, if the 
seller can demonstrate that it had a reasonable expectation that the 
contract would be renewed and can meet other evidentiary criteria, we 
believe that stranded cost recovery should be allowed. We encourage the 
parties to such contracts to attempt to negotiate a mutually agreeable 
stranded cost amendment. We have determined, however, that the three-
year negotiation period proposed in the initial Stranded Cost NOPR 
should be abandoned. We propose instead that: (1) A public utility or 
its customer under the contract may, at any time prior to the 
expiration of the contract, file a proposed stranded cost amendment to 
the contract under section 205 or section 206; or (2) a public utility 
may, at any time prior to the expiration of the contract, file a 
proposal to recover stranded costs through transmission rates for a 
departing customer.<SUP>224 We believe it is [[Page 17691]] in the 
public interest to permit public utilities to seek recovery of stranded 
costs associated with existing contracts that do not explicitly address 
stranded costs, and that they be permitted to do so either through 
transmission rates or through amendment to the existing power sales 
contracts. However, for a utility to be eligible for stranded cost 
recovery, it must meet the evidentiary demonstration required by this 
rule.

    \223\Existing wholesale power sales contracts are those 
contracts executed on or before July 11, 1994. Stranded Cost NOPR at 
32,860, 32,881.
    \224\If the selling utility under the 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. Nevertheless, we do encourage such a 
transmitting utility to attempt to negotiate a mutually agreeable 
stranded cost amendment with its customer. In addition, we will 
allow such a transmitting utility to file a request to recover 
stranded costs in transmission rates under FPA sections 211-212. 
However, such transmitting utility would be required to make the 
same evidentiary demonstration as that required of public utilities 
seeking extra-contractual stranded cost recovery.
    In examining proposals to recover stranded costs, we propose to 
apply a ``reasonable expectation'' standard and a rebuttable 
presumption that if contracts contain notice provisions, the utility 
had no reasonable expectation of continuing to serve the customer 
beyond the term of the notice provision. We further propose to retain 
the requirement in the initial Stranded Cost NOPR that utilities 
attempt to mitigate stranded costs. In addition, we are proposing that 
public utilities be required to follow certain procedures specified 
herein that permit a customer to obtain advance notice of its maximum 
possible stranded cost exposure without mitigation.<SUP>225

    \225\The customer's maximum possible stranded cost exposure 
without mitigation would be the revenues that the utility would have 
received from the customer had the customer continued to take 
service from the utility. This is the amount from which the 
competitive market value of the power that the customer would have 
purchased would be deducted to compute the amount of recoverable 
stranded costs (using the ``revenues lost'' approach for calculating 
stranded costs that this rule proposes to adopt (see section 
III.F.1.c(8) infra)). The utility will be required to make every 
effort to mitigate the amount of the stranded cost charge. See 
section III.F.1.c(9).
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    Fourth, with respect to costs stranded as a result of retail 
wheeling, or as a result of wholesale wheeling obtained by a retail-
turned-wholesale customer, the Stranded Cost NOPR explored the issue of 
whether we should assume some responsibility for addressing such costs. 
The vast majority of those commenting on our proposed rule urged us not 
to get involved or otherwise assume responsibility for those types of 
stranded costs, except in certain very limited circumstances. At this 
juncture, we have concluded that it is appropriate to leave it to state 
regulatory authorities to assume the responsibility for any stranded 
costs occasioned by retail wheeling, except in the narrow circumstance 
in which the state regulatory authority does not have authority under 
state law, at the time retail wheeling is required, to address recovery 
of such costs. The Commission holds the strong expectation that states 
will provide procedures for, and the full recovery of, legitimate and 
verifiable stranded costs.
    We also have determined that this Commission should be the primary 
forum for public utilities to seek recovery, through FERC 
jurisdictional transmission rates, of stranded costs resulting from 
wholesale wheeling for newly created wholesale customers who leave 
their franchised utility's supply system (e.g., through 
municipalization).<SUP>226

    \226\Although the Commission's June 29 NOPR characterized these 
types of stranded costs as ``retail'' stranded costs, we believe 
they are more appropriately characterized as ``wholesale'' stranded 
costs, since it is not only state or local authority that permits 
the costs to be stranded, but also the availability of wholesale 
transmission that causes the costs to be stranded.
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    In deciding that states are the more appropriate entities to 
address stranded costs resulting from retail wheeling, we are relying 
on assurances from our state colleagues, as evidenced, for example, in 
NARUC's comments on the proposed rule, that they will address and 
resolve this difficult issue. We continue to be of the opinion that 
utilities are entitled, from both a legal and policy perspective, to an 
opportunity to recover their past prudently incurred costs, including 
costs incurred to serve retail customers who obtain retail wheeling in 
interstate commerce. We emphasize that we will not allow states to use 
rates for transmission in interstate commerce as the vehicle for 
passing through any stranded costs resulting from retail wheeling, 
except in the narrow circumstance described. Thus, these costs must be 
recovered in rates in a manner that does not involve ``transmission of 
electric energy in interstate commerce'' as that phrase is used in the 
FPA.<SUP>227 This approach ensures that the wholesale market will not 
be burdened by retail costs. It also ensures that one state will not be 
able to place costs stranded by its ordering of retail wheeling<SUP>228 
on customers in another state.

    \227\See 16 U.S.C. Sec. 824(c).
    \228\We do not address whether states have the lawful authority 
to order retail wheeling in interstate commerce.
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    As discussed infra, we believe the states have a number of 
mechanisms to provide for recovery of retail stranded costs in retail 
rates. One of those mechanisms is a surcharge to state-jurisdictional 
rates for local distribution. Accordingly, we are proposing to define 
``facilities used in local distribution'' under section 201(b) of the 
FPA.<SUP>229 We believe states may impose retail stranded costs on 
facilities or services falling under this definition.<SUP>230

    \229\16 U.S.C. 824(b).
    \230\States may also use their jurisdiction over local 
distribution facilities to address potential ``stranded benefits,'' 
e.g., environmental benefits associated with conservation, load 
management, and other demand side management (DSM) programs. See 
NARUC Resolution on Competition, the Public Interest, and 
Potentially Stranded Benefits, November 16, 1994 (Appendix C to 
NARUC's comments).
    We set out our preliminary findings here for the limited purpose of 
reopening the comment period of the Stranded Cost NOPR as to whether 
the requirements proposed in the Open Access NOPR raise additional 
implementation or other issues pertaining to stranded cost recovery 
that were not addressed in the initial Stranded Cost NOPR and, if so, 
whether the mechanisms we propose based on our preliminary 
determinations are adequate to allow recovery of stranded costs. 
Additional issues on which we seek comment are delineated below.
    c. The Proposed Regulations. (1) Justification for Allowing 
Recovery of Stranded Costs and Estimates of the Magnitude of Stranded 
Costs. (a) Comments
    Virtually all of the investor-owned utility commenters support the 
NOPR's basic assumption that stranded costs can be created when a 
customer switches suppliers. Many commenters, including Electric 
Generation Association and Public Power Council, applaud the Commission 
for timely ``addressing the difficult and controversial stranded cost 
issue and for recognizing that this issue must be resolved in order for 
all parties to harvest fully the benefits of a competitive electric 
industry.''<SUP>231 Edison Electric Institute (EEI) strongly endorses 
the recovery of stranded costs.

    \231\Electric Generation Association comments at 1.
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    A number of commenters, primarily representing customer groups, 
disagree that the risk that a utility could lose customers (and thereby 
incur stranded costs) is a new phenomenon created by regulatory and 
statutory initiatives that utilities could not anticipate. These 
commenters argue that utilities have long been aware that they risk 
losing customers to competition and that utilities should have planned 
for this eventuality.
    In support of this argument, American Forest and Paper Association 
(American Forest) and others argue that utilities have known for some 
time that wholesale customers can--and in the [[Page 17692]] general 
course of business, in fact, do--leave utilities' systems for other 
suppliers without being obligated to pay for stranded costs. Several 
commenters also argue that Congress put the industry on notice through 
PURPA and then EPAct that utilities are at risk of losing customers as 
a result of the pro- competitive provisions of these statutes. Numerous 
parties<SUP>232 note that the courts and the Commission have, in 
various cases, provided notice that, as a result of competitive forces 
in the industry, utilities have had no reasonable expectation that 
customers will remain on their systems after contract expiration. 
Commenters cite, among other cases, the Supreme Court's 1973 decision 
in Otter Tail<SUP>233 (in which the Court held that the refusal to 
wheel power could place a utility at risk of antitrust liability), the 
Commission's 1968 decision in Village of Elbow Lake v. Otter Tail Power 
Company<SUP>234 (in which utilities were alerted to the threat of 
municipalization), and the Commission's 1983 decision in Kentucky 
Utilities Co.<SUP>235 (in which a notice of termination provision was 
deemed to constitute the extent of the utility's protection of its 
investment incurred to support the contract service).

    \232\E.g., American Power Association (APPA), Florida Municipal 
Power Agency, Michigan Municipal Cooperative Group and Wolverine 
Power Supply Cooperative (Florida and Michigan Municipals), the 
Illinois Commerce Commission (Illinois Commission), Electricity 
Consumers Resource Council, the American Iron and Steel Institute an 
the Chemical Manufacturers Association (Industrial Consumers), and 
TDU Customers.
    \233\See Otter Tail, supra note 15.
    \234\Village of Elbow Lake v. Otter Tail Power Company, 40 FPC 
1262 (1968).
    \235\Kentucky Utilities Co., Opinion No. 169, 23 FERC 
Sec. 61,317, aff'd on reh'g in relevant part, 25 FERC Sec. 61.205 
(1983), reversed on other grounds, 766 F.2d 239 (6th Cir. 1985).
    Some commenters<SUP>236 argue that the Stranded Cost NOPR 
incorrectly assumes the existence of a wholesale service obligation. 
These commenters argue that the NOPR improperly assumes that a utility 
has had an obligation to serve a wholesale requirements customer beyond 
the term set forth in the contract unless the contract contained a 
notice of termination provision or other more explicit stranded cost 
provisions. According to these commenters, the wholesale service 
obligation is purely contractual, and utilities could not reasonably 
have expected to continue to provide service after the expiration of a 
particular contract.

    \236\E.g., American Forest, Industrial Consumers, the Municipal 
Resale Service Customers of Ohio, and the Stranded Cost Order 
Opponent Parties (SCOOP). SCOOP consists of Delaware Municipal 
Electric Corporation, Village of Freeport, New York, City of 
Jamestown, New York, Town of Massena, New York, Modesto Irrigation 
District, M-S-R Public Power Agency, City of Santa Clara, 
California, and Southern Maryland Electric Cooperative, Inc.
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    Some state commissions (e.g., Illinois Commission) also find the 
NOPR's notion of wholesale stranded costs to be misplaced. These state 
commission commenters note that competition and notice provisions have 
existed for decades and that a customer leaving the system for another 
supplier is no different from a customer leaving due to an economic 
downturn (e.g., a plant closing or relocation). Under the latter 
circumstance, they note that the costs are allocated among the 
remaining customers, or, in some instances, shareholders. A number of 
other state commissions (e.g., Indiana Utility Regulatory Commission 
(Indiana Commission)) urge that stranded cost recovery exclude costs 
associated with normal business risk, such as poor planning, customer 
relocation, self-generation, or cogeneration.
    With regard to the magnitude of the level of total industry 
stranded costs, while estimates vary widely, most commenters agree that 
the level of potential wholesale stranded costs is small relative to 
that of retail stranded costs. Several state commissions and customer 
groups (e.g., Florida Public Service Commission (Florida Commission), 
APPA, Industrial Consumers, Illinois Commission, and SCOOP) argue that 
the potential level of wholesale stranded costs is largely exaggerated. 
For example, SCOOP claims that ``[s]eparating out only the wholesale 
exposure to stranded costs, and critically analyzing the extent of that 
exposure, will permit the Commission to recognize that wholesale 
stranded costs are little more than the `flea on the tail of the dog' 
and not the dog itself.''<SUP>237 Many of these commenters, including 
the Illinois Commission, note that wholesale stranded costs are likely 
to be minimal because wholesale requirements sales for major investor-
owned utilities account for roughly 6 percent of their total net energy 
generated and received. Furthermore, these commenters contend that it 
is ridiculous to suggest that all of the generation assets associated 
with serving this wholesale load suddenly would become stranded. In 
fact, some commenters expect the investor-owned utilities with lower-
cost generation to benefit from increased competition.

    \237\SCOOP comments at 2.
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    Additionally, the Environmental Action Foundation (Environmental 
Action) notes that some industry estimates assume a zero asset (or 
salvage) value for any stranded assets. Environmental Action claims 
that this assumption grossly overestimates the claimed industry level 
of stranded costs by failing to recognize that a utility with a 
stranded generating asset will likely lower its power prices to market 
levels to mitigate the total level of stranded costs. Accordingly, 
Environmental Action suggests that estimated levels of potential 
wholesale stranded costs may, in fact, be lower after accounting for 
costs recovered by the utility as a result of aggressively marketing 
any stranded generating assets.
    EEI indicates that, based on an informal survey of its members, the 
number of cases likely to be filed at the Commission seeking to recover 
stranded costs from wholesale requirements customers under existing 
contracts will be far less than those filed during restructuring of the 
natural gas pipeline industry.<SUP>238 However, EEI states that, while 
the number of filings may be relatively small, the dollar amounts and 
the significance to the parties are great. EEI indicates that the 
magnitude of potential wholesale and retail stranded cost liability to 
the industry is in the upper range of the NOPR's tens of billions of 
dollars to $200 billion estimate.

    \238\For example, a number of utilities (e.g., Allegheny Power 
Service Corporation (Allegheny Power), Consumers Power Company, and 
Wisconsin Power & Light Company (Wisconsin Power)) indicate that 
their total potential wholesale exposure is minimal.
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    (b) Preliminary Findings. The electric utility industry has 
billions of dollars invested in utility assets and contracts that, in 
today's markets, may become uneconomic.<SUP>239 If wholesale or retail 
customers leave their utilities' systems without paying a share of 
these costs, the costs will become stranded unless they can be 
recovered either from the departing customers or other customers. These 
are very real costs that, as previously discussed, were incurred under 
a regulatory system that imposed an obligation to serve on utilities 
(an explicit obligation at retail and arguably an implicit obligation 
at wholesale)<SUP>240 [[Page 17693]] and also permits recovery of all 
prudently incurred costs. Moreover, while we recognize that there has 
always been some risk of a utility losing a customer, that risk has 
been greatly increased by significant statutory, regulatory, 
technological, and structural changes, including this rule, that 
utilities may not have reasonably foreseen at the time their 
investments were made.

    \239\As discussed in section III.C.2 supra, new generation 
facilities can produce power on the grid at a cost of 3 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 per kWh for nuclear plants.
    \240\The Commission has never determined whether there is an 
actual obligation in the FPA to serve requirements customers. 
Construction Work In Progress, Order No. 474, III FERC Stats. & 
Regs. para.30,751 at 30,718 (1987). The Commission's regulations, 
however, do require a rate filing to terminate a jurisdictional 
contract. 18 C.F.R. Sec. 35.15 (1994). Moreover, in a few cases, the 
Commission has required service beyond the contract term. E.g., 
Tapoco, Inc., et al., 39 FERC para.61,363 (1987); Florida Power & 
Light Company, 8 FERC para.61,121, reh'g denied, 9 FERC para.61,015 
(1979)).
    As discussed in the introduction of this document, the wholesale 
bulk power segment of the electric industry is undergoing a fundamental 
transformation from a monopolistic industry regulated on a cost-of-
service basis to an open access, competitively priced industry. The 
transformation will accelerate if the Commission adopts the open access 
transmission requirements it is proposing in Docket No. RM95-8-000. We 
do not believe that utilities that made large capital expenditures or 
long-term contractual commitments to buy power many years ago should 
now be held responsible for failing to foresee such fundamental changes 
in the industry. The Commission will not ignore the effects of 
regulatory and statutory changes on the past investment decisions of 
utilities. We believe that equity requires that utilities have an 
opportunity to recover legitimate and verifiable stranded costs 
associated with the development of competitive wholesale markets.
    This belief is bolstered by our experience during the restructuring 
of the natural gas industry. During the 1980s and early 1990s, the 
Commission undertook a series of actions that eventually led to the 
restructuring of the gas pipeline industry. The restructuring of the 
industry and the introduction of competitive forces in the gas supply 
market left many pipelines holding uneconomic take-or-pay contracts 
with gas producers.<SUP>241

    \241\The costs of gas supply contracts in the gas industry can 
be viewed as somewhat analogous to the costs of generation resources 
in the electric industry.
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    In Order No. 436, the Commission declined to take direct action to 
alleviate the burden that the uneconomic take-or-pay contracts placed 
on pipelines. The Commission based its decision on a number of 
considerations, including its concern ``regarding the ability of 
private parties in the gas production industry to rely on private 
contracts as a tool for structuring basic economic 
relationships.''<SUP>242

    \242\Order No. 436, supra note 12 at 31,492-93; see also AGD, 
supra note 9, 824 F.2d at 1026.
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    However, in AGD, the U.S. Court of Appeals for the District of 
Columbia Circuit noted that the pipelines were ``caught in an unusual 
transition'' as a result of regulatory changes beyond the pipelines' 
control.<SUP>243 The court faulted the Commission for failing to take 
direct action to address the effect of such regulatory changes on the 
uneconomic take-or-pay contracts.<SUP>244

    \243\824 F.2d at 1027.
    \244\Id. at 1021.
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    The court's reasoning in AGD concerning the restructuring of the 
gas industry is also applicable to the current move to competitive bulk 
power markets in the electric industry. Once again, a regulated 
industry is faced with an ``unusual transition'' to a more competitive 
market. Once again, one result of the transition is the possibility 
that utilities will be left with large unrecoverable costs. In these 
circumstances, we believe that we must directly address the costs of 
the transition to a competitive industry by allowing utilities to 
recover their legitimate and verifiable stranded costs, and that we 
must do so simultaneously with any final rule we adopt concerning open 
access transmission.
    (2) The D.C. Circuit Court of Appeals Decision in Cajun Electric 
Power Cooperative, Inc. v. FERC. In the Cajun case,<SUP>245 the D.C. 
Circuit found that the Commission should have held an evidentiary 
hearing to determine whether the recovery of stranded investment costs, 
as permitted in an open access transmission tariff approved by the 
Commission, was anticompetitive and would preclude mitigation of 
Entergy Corporation's (Entergy) market power. The transmission tariff 
under review in that case was intended to mitigate Entergy's market 
power by providing open access to its transmission system.<SUP>246 The 
open access transmission tariff provided that Entergy's subsidiaries 
could seek to recover their stranded investments from a departing 
generation customer by including in the departing customer's 
transmission rate the cost of Entergy's generation capacity that was 
stranded when the former customer switched suppliers. The court 
expressed concern that this provision might constitute a tying 
arrangement whose purpose is to ``cabin'' Entergy's market power, 
stating: ``If a company can charge a former customer for the fixed 
costs of its product whether or not the customer wants that product, 
and can tie this cost to the delivery of a bottleneck monopoly product 
that the customer must purchase, the products are as effectively tied 
as they would be in a traditional tying arrangement.''<SUP>247

    \245\Cajun Electric Power Cooperative, Inc. v. FERC, 28 F.3d 173 
(D.C. Cir. 1994) (Cajun).
    \246\The two other electric power tariffs under review in that 
case provided for the sale of wholesale power by various Entergy 
public utility subsidiaries at negotiated, market-based rates. As 
the court indicated, these tariffs, in combination with the open 
access transmission tariff, ``were designed to permit Entergy--a 
monopolist of transmission services in the relevant market--to 
engage in market-based pricing in the generation market, while 
simultaneously introducing competition to that market through the 
unbundling of generation sales from transmission services.'' Id. at 
175.
    \247\Id. at 178.
    The court noted that central to the Commission's approval of 
Entergy's open access transmission tariff was the Commission's finding 
that Entergy's market power would be mitigated upon the implementation 
of the tariff. <SUP>248 However, the court suggested that permitting a 
transmission monopolist such as Entergy to impose generation-related 
charges on competitors who only seek transmission services might serve 
to increase, not mitigate, Entergy's market power because ``Entergy can 
compete for generation sales outside its transmission grid without 
concern for a stranded investment charge [but] Entergy's competitors 
cannot compete for the customers on its transmission system on the same 
basis.''<SUP>249 Thus, the court held that ``[t]he Commission must 
address whether the [transmission tariff's] provision of a process for 
recovery of stranded investment costs * * * precludes genuine open 
access to Entergy's transmission system. In short, the question that 
must be asked now is whether the [transmission tariff] allows for 
`meaningful access to alternative suppliers.'''<SUP>250 The court went 
on to identify other provisions of the transmission tariff (in addition 
to the stranded cost provision) that might lessen the mitigation of 
Entergy's market power, including Entergy's retention of sole 
discretion to determine the amount of transmission capability available 
for its competitors' use; the point-to-point service limitation; the 
failure to impose reasonable time limits on Entergy's response to 
requests for transmission service; and Entergy's reservation of the 
right to cancel service in certain instances even where a customer has 
[[Page 17694]] paid for transmission system modifications.<SUP>251

    \248\The court noted that although the Commission suggested that 
the stranded investment provision is necessary to lure Entergy into 
competition and provides an equitable recovery of costs from the 
parties for whom the costs were incurred, this is irrelevant if the 
Entergy tariffs do not sufficiently mitigate Entergy's market power. 
Id. at 180.
    \249\Id.
    \250\Id. at 179 (emphasis in original).
    \251\Id. at 179-80.
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    The court concluded that the transmission tariff as a whole ``seems 
to provide Entergy with the means to stifle the very competition it 
purports to create.''<SUP>252 The court determined that the Commission 
erred in approving Entergy's tariffs without conducting hearings on 
whether, notwithstanding the purpose of the transmission tariff to 
mitigate market power, Entergy might retain market power. 
Significantly, however, the court did not hold that stranded cost 
recovery could not be justified; its objection was to the Commission's 
procedures in that particular case and lack of explanation for its 
substantive decision to approve the stranded cost provision.

    \252\Id. at 180.
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    (a) Comments. Most customer groups and many state representatives 
(e.g., APPA, Blue Ridge,<SUP>253 National Association of Regulatory 
Utility Commissioners (NARUC) and the Vermont Department of Public 
Service (Vermont Department)) contend that the Cajun decision either 
prevents the Commission from allowing the recovery of stranded costs 
through transmission charges, or, at best, raises questions concerning 
the scope of the Commission's legal authority to do so. In light of 
Cajun, some commenters, such as the National Rural Electric Cooperative 
Association (NRECA), urge the Commission to terminate the NOPR.

    \253\Blue Ridge consists of Blue Ridge Power Agency, Northeast 
Texas Electric Cooperative, Sam Rayburn G & T Electric Cooperative 
and Tex-La Electric Cooperative.
---------------------------------------------------------------------------

    Environmental Action contends that a transmission adder does not by 
itself constitute tying or leveraging. It submits that if the 
transmission adder consists of costs that a customer is obligated to 
pay in any event, the adder merely holds the customer to its existing 
bargain. Environmental Action argues that in Cajun, however, the 
transmission adder was not being used to recover costs for which the 
transmission customer was already obligated, but had the effect of 
penalizing the customer for entering into a new obligation. According 
to Environmental Action, the NOPR ``makes the same error'' to the 
extent that the costs proposed to be recovered in the transmission 
adder are not part of the contractual quid pro quo.<SUP>254

    \254\Environmental Action comments at 79.
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    All of the investor-owned utility commenters, except Wisconsin 
Power & Light Company (Wisconsin Power), argue that the Cajun decision 
is not a bar to recovery of stranded costs through transmission 
rates.<SUP>255 These commenters (e.g., EEI and Duke) argue that the 
Cajun decision was based on procedural grounds and merely stands for 
the proposition that the Commission should have held an evidentiary 
hearing in that case to resolve anticompetitive concerns. These 
commenters also argue that the portion of the Cajun decision relied on 
by the customer commenters is only dictum.

    \255\Wisconsin Power argues that stranded costs should be 
recovered, but not through transmission rates.
---------------------------------------------------------------------------

    Some commenters further contend that allowing the recovery of 
stranded costs through a transmission surcharge does not constitute an 
unlawful tying arrangement. EEI notes, as an initial matter, that the 
courts no longer view every bundling of products or services as a tying 
arrangement that is per se unlawful under the antitrust laws. Moreover, 
EEI submits that in a tie-in, a seller of one product requires its 
purchasers to buy the tied product by bundling the products together to 
promote sales in related markets that it could not achieve under 
competitive circumstances, effectively foreclosing the purchaser from 
obtaining the second product from competitors even if it could do so at 
a lower cost. EEI argues that a stranded cost surcharge, in contrast, 
would include only part of the former price of the power (the mark-up 
above its marginal cost included in the price approved by regulators), 
and would thereby allow the purchaser to obtain bulk power from 
competitive suppliers with the lowest marginal costs.
    With regard to the potential anticompetitive effects of allowing 
stranded cost recovery, some commenters contend that stranded cost 
recovery would inhibit the movement toward competition, distort price 
signals, result in inefficient decisionmaking, and unfairly reward the 
least efficient utilities.
    For example, APPA argues that charges for stranded costs are 
anticompetitive and hinder the development of a competitive market by, 
among other things: (1) Distorting transmission prices and erecting 
artificial barriers to new suppliers; (2) giving the host utility a 
paid-off asset with which to compete unfairly; and (3) slowing the 
introduction of new technology. APPA argues that the disallowance of 
stranded costs would encourage all utilities to strive for greater 
efficiencies and to compete for sales on the basis of price and 
service.
    The Ad Hoc Coalition on Environmental and Consumer Protection (Ad 
Hoc Coalition) argues that stranded cost recovery will amount to a 
government-ordered subsidy for electric generation from older, less 
efficient units that will further environmental degradation and stifle 
the move toward greater competition. It claims that the stranded costs 
that utilities primarily will be seeking to recover are uneconomical 
nuclear generation assets, and that the NOPR thus offers a new subsidy 
for nuclear power by shifting cost responsibility for nuclear assets 
from shareholders to ratepayers. The Ad Hoc Coalition believes that 
such a subsidy could affect investment decisions for the next 
generation of nuclear power plants if investors believe that they will 
be allowed to recover their costs as long as a ``reasonable 
expectation'' existed at the time the decision to build was made. Thus, 
the Ad Hoc Coalition argues that the NOPR will send an improper signal 
to utility managers and investors that generation investments remain 
safe investments, even when they do not pass the tests of a competitive 
market. According to the Ad Hoc Coalition, such a policy perpetuates 
the continued reliance on older, less efficient generating units that 
harm the environment.
    American Forest asserts that blanket assurances of stranded cost 
recovery are anticompetitive and create no incentive for utilities to 
lower their operating costs and mitigate any uneconomic costs. 
According to American Forest, stranded costs create enormous 
uncertainty that may make financing of competitors' plants impossible 
at any cost, thus killing the very competitive market the Commission 
seeks to foster.
    The Illinois Commission believes that stranded cost recovery 
produces an incorrect competitive result because such action 
effectively ``props up'' the least efficient (high-cost and high-price) 
utilities. The Illinois Commission argues that stranded cost recovery 
mechanisms effectively punish the more efficient suppliers that have 
paid attention to changing realities and have assumed a more 
competitive market-sensitive posture.
    In sharp contrast to the commenters that argue stranded cost 
recovery would hinder competition, commenters such as EEI, the United 
States Department of Energy (DOE), the Coalition for Economic 
Competition,<SUP>256 and the [[Page 17695]] Conservation Law Foundation 
(CLF)<SUP>257 contend that stranded cost recovery can promote a quicker 
transition to competition and can be used to enhance efficiency. Some 
commenters (e.g., DOE, Industrial Consumers, Enron Power Marketing, 
Inc. (Enron), CLF, and the Competitive Electric Market Working Group 
(Competitive Working Group)<SUP>258) suggest linking the recovery of 
stranded costs to utility actions that will further wholesale 
competition, such as the filing of an open access transmission tariff 
or membership in a regional transmission group (RTG).

    \256\The Coalition for Economic Competition consists of the 
following New York investor-owned utilities: Central Hudson Gas & 
Electric Corporation, Consolidated Edison Company of New York, Long 
Island Lighting Company, New York State Electric & Gas Corporation, 
Niagara Mohawk Power Corporation, and Rochester Gas & Electric 
Company.
    \257\CLF is a non-profit environmental law organization that 
represents approximately 10,000 members in the six New England 
states.
    \258\The Competitive Working Group consists of Electric 
Clearinghouse, Inc., Enron Power Marketing, Inc., and Destec Power 
Services, Inc.
---------------------------------------------------------------------------

    Commenters representing the financial community (e.g., Utility 
Investors and Analysts, American Society of Utility Investors, United 
Utility Shareholders Association of America) strongly support recovery 
of stranded costs so that the financial stability of the electric 
utility industry will be protected. These commenters argue that the 
amount of potential stranded costs exceeds the amount of equity 
investment in electric utilities. According to these commenters, 
investors have not made their current investment decisions with the 
rigors of competition in mind, nor have rate of return hearings 
included testimony concerning competitive risk. Without full recovery 
of stranded costs, financial community commenters argue, financial 
integrity will deteriorate, and utilities will be unable to attract 
capital. Due to the capital-intensive nature of the electric utility 
industry, these commenters note that lack of access to capital markets 
at reasonable rates will prevent utilities from keeping costs down.
    (b) Preliminary Findings. We do not interpret the Cajun court 
decision as barring the recovery of stranded costs. Rather, the Cajun 
court remanded the case because the Commission failed to hold an 
evidentiary hearing concerning whether the inclusion of a stranded cost 
recovery provision in Entergy's transmission tariff precluded the 
mitigation of Entergy's market power. As previously discussed, the 
court also found the Commission's substantive decision flawed because 
the Commission failed to explain adequately its approval of the 
stranded cost provision, among others. In this consolidated proceeding 
(i.e., the Stranded Cost NOPR, the Supplemental Stranded Cost NOPR, and 
the Open Access NOPR), we are providing the evidentiary record for 
addressing all of the court's concerns on a generic basis, and the 
opportunity for all participants in the electric industry to present 
evidence and arguments. We are also providing a full explanation of why 
the recovery of legitimate stranded costs is critical to the successful 
transition of the electric utility industry from a tightly regulated, 
cost-of-service industry to an open transmission access, competitive 
industry that will drive down the prices of electricity to consumers.
    The court in Cajun was concerned about whether Entergy's tariff 
allowed ``meaningful'' access to alternative suppliers. In this regard, 
the court stated that the Commission must address not only whether the 
stranded cost provision allowed for meaningful access, but also whether 
other provisions in the tariff might lessen the utility's market power. 
In the Open Access NOPR, the Commission is attempting to mitigate the 
core of market power not only for Entergy, but for all traditional 
public utilities: control over transmission access. The Commission is 
generically addressing all aspects of transmission market power, 
including those specifically identified by the Cajun court (e.g., 
point-to-point service limitations). Indeed, a fundamental purpose of 
the Open Access NOPR is to ensure the meaningful access to alternative 
suppliers that was identified by the Cajun court.<SUP>259 The Open 
Access NOPR includes the specific terms and conditions of access 
(contained in the pro-forma tariffs) that we believe are the minimum 
necessary to mitigate transmission market power.<SUP>260 Of utmost 
importance in mitigating market power is the Commission's non-
discrimination (comparability) requirement, a requirement that had not 
been articulated at the time of the Commission's order under review in 
Cajun, and that is proposed to be codified in the Open Access NOPR 
proceeding.

    \259\See Cajun, 28 F.3d at 179.
    \260\In seeking comment in the Open Access NOPR on the adequacy 
of these terms and conditions, we seek specific comment on the terms 
and conditions that were of concern to the Cajun court. See 
discussion supra Section III.E.4. For example, the Cajun court 
expressed concern that the point-to-point service limitation in 
Entergy's transmission tariff might restrain competition. However, 
under the Open Access NOPR, service will not be limited to point-to-
point. Instead, customers will be allowed to choose between point-
to-point and network service.
---------------------------------------------------------------------------

    With regard to the Cajun court's concern about stranded cost 
provisions, the Commission in Entergy failed to articulate the 
transition that the industry is experiencing, the fundamental fact that 
full competition is not yet a reality, and that stranded costs are a 
temporary but serious phenomenon that must be addressed if we are to 
successfully move from one regulatory regime to another, thereby 
creating fully competitive bulk power markets. In this regard, the Open 
Access NOPR provides a detailed explanation of the fundamental industry 
and regulatory changes that have given rise to the potential for 
stranded costs. In addition, in the Stranded Cost NOPR and the 
Supplemental Stranded Cost NOPR, we have gathered (and are continuing 
to gather) information concerning the magnitude of potential stranded 
costs; we have provided an explanation of the transitional nature of 
stranded costs; and we have explained the critical need to deal with 
these costs in order to reach competitive wholesale markets. We have 
also explained existing disparities in electricity rates and the 
consumer benefits that can accrue if we achieve fully competitive 
markets.<SUP>261

    \261\There is a wide disparity in consumer electricity prices 
across the United States. Some consumers pay more than 10 cents per 
kilowatt-hour on average, while others pay about one-third as much. 
While some of this price disparity is due to regional cost 
differentials, some of it may also be due to ineffective access to 
new power supplies. We believe that all consumers will benefit from 
changes that allow their suppliers greater access to lower-cost 
power supplies. This greater access can best be achieved by ensuring 
that non-discriminatory open access transmission service is 
available to all potential users of the transmission grid. The 
result will be greater trading opportunities among suppliers, and 
also more investment opportunities for new entrants in generating 
markets. All of this should serve the interests of consumers by 
lowering electricity prices.
---------------------------------------------------------------------------

    Failure to deal with the stranded cost problem would likely delay 
and would certainly complicate the transition to fully competitive bulk 
power markets. For example, stranded costs would then be borne by the 
utilities' shareholders, which could threaten the stability of the 
industry and the service it provides, or be reallocated to remaining 
customers, raising the price to such customers. An additional 
consideration is the fact that the AGD court instructed the Commission 
that it must consider the transition costs borne by regulated utilities 
when the Commission changes the regulatory rules of the game.
    We conclude that stranded cost recovery as proposed in this 
rulemaking is not a tying arrangement, as discussed by the Cajun court, 
and that the proposed cost recovery procedure will not ``cabin'' market 
power.<SUP>262 Rather, the stranded cost recovery procedure is 
[[Page 17696]] being prescribed to enable utilities, during a 
transitional period, to recover costs prudently incurred under a 
different regulatory regime.

    \262\Cajun, 28 F.3d at 177-78.
---------------------------------------------------------------------------

    Finally, the financial community argues strongly and plausibly that 
recovery of legitimate and verifiable stranded costs at this critical 
stage in the industry's move toward competition is needed to protect 
the financial stability of the electric industry. They confirm 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.
    (3) Responsibility for Wholesale Stranded Costs (Whether to Adopt 
Direct Assignment to Departing Customers). In the initial NOPR, the 
Commission proposed to allow utilities to seek to assign stranded costs 
associated with the departure of a given wholesale customer directly to 
that departing wholesale customer.<SUP>263 We noted, however, that an 
alternative might be to assign stranded costs more broadly by, for 
example, requiring all transmission customers (including native load 
which takes bundled service) to pay a higher rate for use of the 
transmission system. We invited comments on the direct assignment and 
alternative methods of stranded cost recovery.<SUP>264

    \263\Methods of direct assignment include a lump sum payable 
when the customer leaves the system. Such an exit fee could also be 
recovered over time in monthly installments. Presumably the utility 
would charge interest on the unamortized balance if the customer 
selected a delayed payment approach.
    \264\Stranded Cost NOPR at 32,867-68.
    (a) Comments. Many parties (representing all constituencies) 
support the direct assignment of stranded costs to the departing 
customer as proposed in the initial NOPR. Most commenters contend that 
the cost causation principle supports this approach. These parties 
argue that utilities undertake obligations on a customer's behalf and 
that, by leaving the system, the departing customer avoids paying for 
its fair share of these obligations. They further argue that general 
fairness requires that customers remaining on the system should not 
have to pay for a departing customer's obligations; they allege that 
this could lead to more customers leaving the system and the eventual 
bankruptcy of the utility.
    Nevertheless, other commenters suggest a framework for stranded 
cost recovery that is different from the direct assignment method 
suggested in the NOPR. According to some commenters (e.g., South 
Carolina Electric & Gas Company), stranded costs should be allocated to 
all customers and shareholders because everyone will benefit from the 
transition to competitive generation markets. In this manner, they 
contend that the overall burden would be reduced, because stranded 
costs would be spread among a greater number of parties. Commenters 
that support spreading the costs to all customers argue that requiring 
the departing customer to shoulder all stranded costs will result in 
few customers going off-system due to the economic inefficiency of 
paying two suppliers. Several commenters (e.g., Indiana Commission, 
Rhode Island Division of Public Utilities and Carriers, Department of 
Water and Power of the City of Los Angeles, and Fuel Managers 
Association) suggest that some shareholder liability for stranded cost 
recovery should be required, arguing that it would provide utilities 
with a greater incentive to mitigate stranded costs.
    Some commenters support the recovery of stranded costs through a 
transmission surcharge applicable to all transmission 
customers.<SUP>265

    \265\Some commenters (e.g., Allegheny Power) distinguish between 
transmission surcharges imposed on transmission-only customers as 
opposed to all customers. In the former case, only those customers 
taking transmission-only service from the utility would be assessed 
stranded costs; customers taking bundled service would not be 
assessed such costs. Allegheny Power indicates that it would support 
such an approach only if the Commission decides not to fully assign 
stranded costs to departing customers.
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    Other commenters oppose a general surcharge on all transmission 
customers, arguing that existing transmission customers, including 
native load, should not be allocated any stranded costs because they 
did not cause any costs to be stranded in the first place. Washington 
Water Power Company and Wisconsin Electric Power Company oppose a 
transmission surcharge on the basis that it makes an otherwise 
competitive supplier less marketable due to higher wheeling rates. 
Others allege that a transmission surcharge is inconsistent with the 
unbundling of transmission service and would slow the restructuring 
(disaggregation) of vertically-integrated utilities. Thus, according to 
some commenters, the use of a transmission surcharge would slow the 
move to competitive markets because the surcharge sends the wrong price 
signal, involves cross-subsidization by native load, penalizes 
competitive alternatives, and awards monopoly rents to the utility. 
Some commenters also note that, where the departing customer does not 
take transmission service from its former supplier, the departing 
customer escapes all responsibility for the stranded costs.
    Some commenters contend that the Cajun decision prohibits the use 
of a transmission surcharge. Still others argue that generation costs 
should not be assigned to transmission users because utilities would 
then have an incentive to shift costs to transmission in order to make 
their generation more competitive. SCOOP argues that the shifting of 
generation costs to transmission rates violates the Commission's policy 
prohibiting costs unrelated to the transmission function from being 
included in transmission charges.<SUP>266

    \266\SCOOP comments at 38 (citing Northern States Power Company, 
Opinion No. 383, 64 FERC para.61,324 at 63,377 (1993)).
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    The Public Utility Commission of Texas (Texas Commission) proposes 
a hybrid approach whereby a portion of stranded costs would be directly 
assigned to the departing customer and the remainder allocated through 
a general surcharge to all wholesale market participants. However, if a 
general surcharge on transmission customers is adopted, the Texas 
Commission supports the pooling of all stranded costs and the creation 
of an industry-wide surcharge. The Texas Commission does not explain 
how such a pool would be administered.<SUP>267

    \267\Trigen Energy Corporation advocates that Congress impose a 
``sunset'' energy tax on all electricity used in order to pay off 
stranded costs.
---------------------------------------------------------------------------

    Commenters that represent shareholder interests (American Society 
of Utility Investors, United Utility Shareholders Association of 
America, and Utility Investors and Analysts) argue against allocation 
of any stranded costs to shareholders because the rates of return 
granted to utilities in the past have not included any compensation for 
the risk of competition. They submit that fairness dictates that those 
placed at risk by a sudden change in the rules not be penalized. 
Tennessee Valley Authority (TVA), which as a Federal corporation has no 
shareholders to absorb stranded costs, shares this view.
    (b) Preliminary Findings. After careful consideration of the 
various comments, we believe that direct assignment of stranded costs 
to the departing wholesale customer, as proposed in the initial NOPR, 
is the appropriate method for recovery of such costs.\268\ This method 
is consistent with the cost [[Page 17697]] causation principle.\269\ As 
discussed in greater detail below, as part of the evidentiary 
demonstration necessary for stranded cost recovery associated with 
certain departing wholesale requirements customers,\270\ retail-turned-
wholesale transmission customers, or unbundled retail transmission 
customers, a utility must show that the costs are not more than the 
customer would have contributed to the utility had the customer 
continued to take generation service from that utility. We believe it 
only appropriate that the departing customer, and not the remaining 
customers (or shareholders), bear its fair share of the legitimate and 
prudent obligations that the utility undertook on that customer's 
behalf.

    \268\Because we are also proposing to entertain requests for 
recovery of stranded costs attributable to retail-turned-wholesale 
wheeling customers, or to retail wheeling customers in certain 
limited circumstances, our determinations and rationale regarding 
direct assignment also apply to those situations.
    \269\Contrary to arguments made by SCOOP, the shifting of 
generation costs to transmission rates does not violate Commission 
policy. The Northern States case cited by SCOOP deals with the 
Commission's bright line functionalization policy, pursuant to which 
the Commission, largely as a matter of administrative convenience, 
has attempted to maintain a boundary between generation and 
transmission functions. In that case, we found that 
refunctionalization is not per se improper or contrary to Commission 
policy, and we suggested that strict application of the traditional 
bright line approach may need to be reexamined in light of changes 
taking place in the electric industry. 64 FERC at 63,379. 
Significantly, we stated that the ``fundamental theory of Commission 
ratemaking is that costs should be recovered in the rates of those 
customers who utilize the facilities and thus cause the costs to be 
incurred.'' Id. (emphasis in original).
    This is exactly what we propose to do in the Stranded Cost NOPR 
and the Supplemental Stranded Cost NOPR. The customer that caused 
the costs to be incurred and stranded will continue to pay the 
costs. 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.
    \270\I.e., departing wholesale requirements customers under 
contracts entered into on or before July 11, 1994, who will use the 
utility's transmission system to reach other suppliers and whose 
contracts do not explicitly address stranded costs.
---------------------------------------------------------------------------

    The Commission recognizes that the direct assignment approach for 
addressing stranded costs for the electric industry differs from the 
approach eventually taken for the natural gas industry. In Order No. 
636, which involved the restructuring of the gas industry, the 
Commission determined that it was appropriate to spread the majority of 
the remaining transition costs associated with take-or-pay and other 
contracts to all customers (existing and new) using the interstate 
natural gas transportation system.\271\ However, unlike the situation 
facing the electric utility industry today, by the time the Commission 
issued Order No. 636, changes in the natural gas industry had 
progressed to such a point that it was not possible for the Commission 
to use a strict cost causation approach. 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. In contrast, in the electric area, the Commission (and the 
states) will be better able to address the transition cost issue up 
front, and to address stranded cost recovery before customers leave 
their suppliers' systems. This, in effect, will prevent the 
accumulation of unrecovered costs and will comport with our past policy 
of assigning costs to customers who caused the costs to be incurred.

    \271\Order No. 636 at 30,457-62.
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    In addition, allowing direct assignment of stranded costs will 
ensure that there are no stranded costs left to be borne by the 
remaining customer base or by the shareholders. This, in turn, will 
ensure that the financial health of the industry is not placed in 
jeopardy. If some customers are permitted to leave their suppliers 
without paying for costs incurred to serve them, this may cause an 
excessive burden on the remaining customers (such as residentials) who 
cannot leave and therefore may have to bear those costs. Moreover, the 
prospect or lack thereof for recovering such costs from ratepayers 
could erode a utility's access to capital markets or significantly 
increase the utility's cost of capital. This higher 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.
    The alternatives to direct assignment of stranded costs are to do 
nothing or to assess stranded costs more broadly through some type of 
general surcharge on all customers. As discussed above, to do nothing 
would mean that the Commission would have to reallocate stranded costs 
to shareholders or to remaining customers. Those customers that caused 
the costs to be stranded would not have to pay. This would violate the 
cost causation principle which has been fundamental to the Commission's 
regulation since 1935. The other alternative, to assess costs more 
broadly, also violates this principle. Moreover, there appears to be no 
strong countervailing reason to assess costs broadly in the electric 
utility industry.
    (4) Recovery of Stranded Costs Associated With New Wholesale Power 
Sales Contracts. The NOPR proposed that public utilities and 
transmitting utilities would not be permitted to seek extra-contractual 
recovery of stranded costs associated with ``new'' contracts, i.e., 
contracts executed after July 11, 1994, through transmission rates for 
section 205 or 211 transmission services. For new contracts, the NOPR 
proposed that stranded cost recovery would be allowed only if explicit 
stranded cost provisions are contained in the contract accepted by the 
Commission.\272\ We also stated our preliminary view that it is not 
appropriate in this new regime to impose on wholesale requirements 
suppliers any regulatory obligation to continue to serve their existing 
requirements customers beyond the end of the contract term. However, we 
invited comment on the extent to which there should be such an 
obligation. We also sought comment concerning whether section 35.15 of 
the Commission's regulations, concerning notice of termination, should 
be deleted.

    \272\Under the proposed regulations, a public utility may seek 
recovery of such costs in accordance with the contract. However, 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. See Stranded Cost NOPR at 32,882.
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    (a) Comments. Some of the commenters dispute the Commission's 
belief that there should not be a future regulatory obligation to 
continue to serve wholesale requirements customers beyond the end of 
the contract. SCOOP argues that the FPA imposes an obligation on a 
public utility to continue wholesale service beyond the term of the 
contract when such service is required by the public interest, and that 
the Commission does not have the power to abrogate this authority. 
Sunflower Electric Power Corporation (Sunflower) submits that, for 
stability reasons, a utility's obligation to serve requirements 
customers should run beyond the end of the contract term.
    Some commenters (e.g., SCOOP, Sunflower, Illinois Commission) 
generally support Commission retention of its section 35.15 notice of 
termination filing requirement, arguing that such filing requirement is 
reasonable and/or necessary to ensure that any termination in service 
is not contrary to the public interest.
    Other commenters support the Commission's position that there 
should not be a future regulatory obligation to continue to serve 
wholesale requirements customers beyond the end of the contract and 
support modification or elimination of section 35.15. These 
[[Page 17698]] commenters argue that if contracts are to govern future 
requirements relationships in the electric industry, the Commission 
should allow the contracts to terminate on their own terms, without the 
need for a filing and Commission approval. New England Power Company 
submits that continuation of such a filing requirement would add 
uncertainty to the parties' mutually agreed upon termination date and, 
in turn, promote inequitable and asymmetrical risk/benefit allocations 
and ineffective resource planning. EEI asks the Commission to make a 
finding that it is in the public interest to end the regulation of the 
termination of bulk power contracts. EEI suggests that the Commission 
could (1) grant a blanket waiver of the regulations requiring notice of 
termination for new contracts; (2) amend section 35.15 to pre-grant 
waiver of notice of termination; or (3) amend the regulations to pre-
grant waiver of notice of termination in all bulk power contracts 
signed after the Commission makes its public interest finding to end 
the regulation of contract terminations.
    (b) Preliminary Findings. The Commission believes that future 
wholesale 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. 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. Accordingly, public 
utilities and transmitting utilities will be allowed stranded cost 
recovery associated with new contracts (executed after July 11, 1994) 
only if explicit stranded cost provisions are contained in the 
contract. Recovery of wholesale stranded costs associated with any new 
requirements contract (executed after July 11, 1994) will not be 
allowed unless such recovery is provided for in the contract.
    Further, to ensure that the rights and obligations of sellers and 
buyers are symmetrical in the new competitive era, we do not believe 
that it is 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. A requirements customer 
thus will be responsible for planning to meet its power needs beyond 
the end of the contract term. In this regard, it may sign a new 
contract with its existing supplier, or it may contract with new 
suppliers in conjunction with obtaining transmission service under its 
existing supplier's open access transmission tariff.
    We believe that the section 35.15 filing requirement should be 
retained for all contracts required to be filed under sections 205 and 
206 of the FPA that were executed prior to the effective date of the 
generic tariffs that we discuss herein.\273\ With regard to any power 
sale contract executed on or after that date,\274\ we propose to no 
longer require prior notice of termination pursuant to the provisions 
of section 35.15. However, for administrative reasons, we will require 
written notification of the termination of such contract within 30 days 
after the date termination takes place.

    \273\We also propose to retain the section 35.15 filing 
requirement for any unexecuted contracts that were filed prior to 
the effective date of the generic tariffs proposed herein.
    \274\We request comments on whether this proposal should also be 
applied to transmission contracts.
    (5) Recovery of Stranded Costs Associated With Existing Wholesale 
Power Sales Contracts. In the initial Stranded Cost NOPR (and again in 
this Supplemental NOPR) we stated that stranded costs are a 
transitional problem and that neglecting their recovery could delay the 
realization of fully competitive bulk power markets. We stated that it 
is thus important to set a date beyond which the Commission will no 
longer permit extra-contractual recovery of stranded costs that result 
from existing requirements contracts. To that end, we proposed a three-
year transition period during which public utilities must attempt and 
non-public utilities are encouraged to attempt to renegotiate certain 
existing wholesale requirements contracts (i.e., those that do not 
explicitly address stranded costs through an exit fee or other stranded 
cost provision), and during which they may seek recovery of stranded 
costs. However, if an existing wholesale requirements contract 
explicitly addresses stranded costs through an exit fee or other 
stranded cost provision, the initial NOPR would require the utility to 
recover such costs only as specified in the contract; it would not 
permit unilateral filings to change stranded cost provisions and would 
not permit the utility to seek recovery through transmission rates of 
stranded costs associated with that contract. Under the initial NOPR, 
existing contracts that prohibit stranded cost recovery, or explicitly 
prohibit renegotiation of an existing stranded cost or exit fee 
provision, or that prohibit renegotiation until after the three-year 
period has expired would not be subject to the obligation to 
renegotiate.\275\

    \275\The parties, of course, could always voluntarily 
renegotiate the contract.
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    Where an existing contract does not contain a stranded cost 
provision and the parties to the contract are unable to negotiate a 
stranded cost amendment, and the selling utility is a public utility, 
the initial NOPR proposed to permit the public utility to unilaterally 
file under section 205 or 206 of the FPA prior to the end of the three-
year period a proposed stranded cost provision as an amendment to the 
existing contract. The NOPR also proposed to permit the selling public 
or transmitting utility to seek to recover stranded costs through 
jurisdictional transmission rates if, prior to the end of the three-
year transition period, the customer under the existing wholesale 
requirements contract gives notice pursuant to the contract that it 
will no longer purchase all or part of its requirements from the 
selling utility, but instead will purchase unbundled section 205 or 
section 211 transmission services from the selling utility that will 
begin prior to the end of the three-year period.
    Under the initial NOPR, if a contract does not include an exit fee 
or other explicit stranded cost provision, but does contain a notice 
provision, the Commission proposed that there be a rebuttable 
presumption that the selling utility had no reasonable expectation of 
continuing to serve the customer beyond the period provided in the 
notice provision. We proposed to apply such presumption when the public 
utility proposed a unilateral amendment to the contract to change the 
notice provision and/or add an exit fee provision, or if the public 
utility or transmitting utility sought stranded cost recovery through 
transmission rates.\276\

    \276\Stranded Cost NOPR at 32,861; 32,869-70.
---------------------------------------------------------------------------

    The Commission recognized that some utilities' existing contracts 
may not provide for unilateral rate changes. We noted that although 
under the Mobile-Sierra doctrine<SUP>277 a customer may waive its right 
to challenge the contract and/or the utility may waive its right to 
make unilateral rate changes, the parties may not waive the 
indefeasible right of the Commission to alter rates that are contrary 
to the public interest. We went on to explain why we believe that it is 
in the public interest to permit public utilities with Mobile-Sierra 
contracts a limited opportunity to [[Page 17699]] propose contract 
changes unilaterally to address stranded costs if their contracts do 
not already explicitly do so.

    \277\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).
---------------------------------------------------------------------------

    In the NOPR, the Commission invited comments regarding, among other 
things, whether there should be a transition period during which 
utilities may renegotiate existing contracts, the appropriate length 
for such a transition period, whether utilities or customers with 
contracts that do not provide for unilateral amendments should be able 
to make unilateral filings or file complaints, whether the Commission 
should make a Mobile-Sierra public interest finding based on company-
specific findings instead of generic industry-wide findings, the types 
of contractual provisions that might demonstrate a sufficient meeting 
of the minds between the parties so that requiring renegotiation would 
be inappropriate, whether to apply the rules regarding existing 
contracts only to contracts between unaffiliated entities, and whether 
the rebuttable presumption should also be applied to any contract 
entered into after the date of enactment of the Energy Policy Act, even 
though the contract does not contain an exit fee or other explicit 
stranded cost provision or a notice provision.
    (a) Comments. (i) Contract Renegotiation. Investor-owned utilities, 
EEI, and the majority of state commissions generally favor 
renegotiation of requirements contracts.\278\ These commenters argue 
that the transition to a competitive market should not preclude 
utilities from recovering costs prudently incurred to serve customers 
who may wish to leave the system that was planned and built to serve 
the customers' needs.

    \278\Notable exceptions to this general observation include 
Southern California Edison Company, which opposes renegotiation of 
Mobile-Sierra contracts, and the Pennsylvania Public Utility 
Commission (Pennsylvania Commission) and the Vermont Department, 
which favor upholding the sanctity of contracts.
    Commenters representing cooperatives, municipal, industrial 
customers, and independent power producers generally oppose 
renegotiation. These commenters suggest that the framework established 
in the NOPR, requiring good faith renegotiation of contracts and 
permitting the unilateral filing of revised contracts to provide for 
recovery of stranded costs (where renegotiation fails), will result in 
a violation of the Mobile-Sierra doctrine. Numerous commenters argue 
that contracts should stand on their own, and that there is no factual 
record upon which the Commission can make a generic public interest 
finding, as required by Mobile-Sierra, that contracts should be 
modified. These commenters maintain that ``assumed'' threats to the 
financial stability of the industry do not meet the extremely heavy 
Mobile-Sierra burden of proof that is required to release a public 
utility from a contract. They argue that it is not the Commission's 
place to relieve utilities of improvident bargains. Many customer group 
commenters argue that requiring contract renegotiation improperly 
shifts the burden of proof from the utility to the customer. These 
commenters further argue that permitting contract renegotiation implies 
that customers should pay for a utility's failure to protect itself 
from business risk.
    Some commenters, such as American Forest, argue that the NOPR 
would, in essence, rewrite the law of contracts. These commenters state 
that there is no legal (or logical) basis for the NOPR's suggestion 
that wholesale customers with existing contracts containing valid 
notice of termination provisions can be forced to renegotiate such 
contracts to allow stranded cost recovery. Many of these commenters 
cite Boston Edison Company <SUP>279 and Arizona Public Service Company 
<SUP>280 for the proposition that notice provisions have been allowed 
and enforced. Many commenters contend that contract renegotiation is 
unfair because the policy would make the terms of existing contracts 
binding on only one party, while letting the other party unilaterally 
revise contract terms.

    \279\56 FPC 3414 (1976).
    \280\18 FERC para.61,197 (1982).
---------------------------------------------------------------------------

    Some commenters, including the Electric Generation Association and 
the Iowa Utilities Board, generally oppose renegotiation, but would 
allow it in certain situations. They state that a utility's right to 
recover stranded costs should depend on the terms for which the parties 
have bargained. However, they recognize that there may be situations in 
which the parties' intent is not clearly defined. Accordingly, these 
commenters support renegotiation to supply missing terms to an 
ambiguous contract. Some commenters such as the Iowa Utilities Board 
maintain that companies should always be free to renegotiate contracts; 
however, they oppose allowing utilities to make unilateral filings to 
amend contracts that do not provide for unilateral amendment.
    With regard to whether the renegotiation proposal should apply only 
to contracts between unaffiliated entities, some commenters (e.g., 
Wisconsin Power, Sunflower) support the application of the 
renegotiation policy to both affiliated and non-affiliated entities 
alike. However, other commenters (e.g., the Ohio Office of the 
Consumers' Counsel) recommend that the Commission not apply the 
proposed renegotiation rule to affiliated entities. They note that due 
to the mutual interest of affiliates, negotiations between them may not 
be arm's-length. These commenters urge the Commission to review all 
stranded investment agreements between affiliates to prevent cross-
subsidization and to prevent interference with competition.
    (ii) Three-Year Transition Period. With regard to the proposed 
transition period, although some commenters argue against permitting 
contract renegotiation, commenters generally raise no serious 
objections to three years as the period for contract negotiation. 
However, several commenters suggest that it is undesirable and 
unnecessary to delay the movement to competition for three years while 
contract renegotiations take place. For example, the Competitive 
Working Group argues that there is no assurance that stranded cost 
recovery will be resolved during the three-year period proposed in the 
initial notice. It suggests that the Commission could shorten the 
transition to competition while still providing for recovery of 
stranded costs by requiring that eligibility for recovery be 
conditioned on utilities agreeing to: (1) Grant wholesale customers the 
right to reduce or terminate purchase obligations under preexisting 
contracts and to convert to transmission-only service; (2) file 
comparable open-access transmission tariffs; and (3) mitigate the level 
of stranded assets by either divestiture or auction. The Competitive 
Working Group claims that these measures would ensure the move to 
competitive wholesale power markets.
    DOE, Industrial Consumers, Enron and CLF also suggest linking the 
recovery of stranded costs to utility actions that will further 
wholesale competition. These commenters suggest linking the recovery of 
stranded costs to the filing of an open access transmission tariff or 
membership in an RTG. CLF notes that environmental as well as economic 
benefits may be achieved by linking the recovery of stranded costs to 
the retirement of environmentally unsuitable electric generating plants 
or initiatives that encourage the development and deployment of 
renewable and clean energy technologies.
    Detroit Edison Company (Detroit Edison) suggests that the 
renegotiation period be the greater of (1) three years, 
[[Page 17700]] (2) the term of any existing contract, or (3) the period 
of any moratorium on changes in rates established in existing 
settlement agreements. According to Detroit Edison, adoption of this 
provision would allow utilities that already have established long-term 
contracts or that have agreed to a moratorium on rate changes to honor 
previously negotiated agreements.
    (b) Preliminary Findings. We reaffirm our proposal to permit the 
recovery of legitimate and verifiable stranded costs for a limited set 
of existing wholesale contracts, namely, contracts executed on or 
before July 11, 1994 that do not already contain exit fees or other 
explicit stranded cost provisions. We further reaffirm our desire that 
utilities and their customers attempt to renegotiate such contracts 
promptly to specify the rights and obligations of the parties. To that 
end, we encourage the parties to existing contracts that do not address 
stranded costs to reach a mutually agreeable resolution. If the parties 
negotiate such a 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. Of course, in some cases, the 
parties may disagree in good faith about whether the utility's 
expectations that the customer would continue taking service were 
reasonable. If so, negotiations may prove unsuccessful.
    In place of the three-year transition period proposed in the 
initial NOPR, we propose that, if an existing requirements contract 
does not contain an exit fee or other explicit stranded cost provision 
and is not mutually renegotiated to add such a provision: (1) A public 
utility or its customer may, at any time prior to the expiration of the 
contract, file a proposed stranded cost amendment to the contract under 
section 205 or 206; or (2) a public utility or transmitting utility 
may, at any time prior to the expiration of the contract, file a 
proposal to recover, through its transmission rates for a customer that 
uses the utility's transmission system to reach another generation 
supplier, stranded costs associated with any such existing contract. 
However, for a utility to be eligible for recovery of stranded costs, 
it must meet the evidentiary and procedural criteria discussed infra.
    Consistent with the initial NOPR, if an existing 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. As proposed in the initial 
Stranded Cost NOPR and reaffirmed here, we will reject a stranded cost 
amendment to an existing contract that already contains an exit fee or 
stranded cost provision, unless the contract permits renegotiation of 
the existing stranded cost provision or the parties to the contract 
mutually agree to renegotiate the contract.
    However, if a contract does not contain an exit fee or other 
explicit stranded cost provision, 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. In addition, 
even if the contract contains an explicit Mobile-Sierra provision, the 
Commission reaffirms its preliminary determination that it is in the 
public interest to permit public utilities to seek unilateral 
amendments to add stranded cost provisions if the contracts do not 
already contain exit fees or other explicit stranded cost provisions. 
If a utility demonstrates that it has met the standards for recovery 
outlined in this Supplemental NOPR, we believe that its recovery of 
stranded costs will be in the public interest.
    If neither of the parties to such a contract seeks and obtains 
acceptance or approval of an explicit stranded cost amendment, the 
Commission proposes to permit the public utility to seek recovery of 
stranded costs through its wholesale transmission rates. We also 
propose to establish procedures to provide an existing wholesale 
requirements customer who is contemplating switching suppliers, and 
using its existing supplier's transmission system in order to reach a 
new supplier, advance notice of how the utility would propose to 
calculate costs that the utility claims would be stranded by the 
customer's departure. We believe that the following procedures would 
enable such a customer to make an informed decision whether or not to 
switch suppliers:
    (1) A customer may, at any time prior to the termination date 
specified in its existing wholesale requirements contract, request the 
public utility to either: (i) Calculate the customer's maximum possible 
stranded cost exposure without mitigation, as of the date set forth in 
the customer's request; or (ii) provide the formula that the utility 
would use to calculate the customer's maximum possible stranded cost 
exposure without mitigation, to enable the customer to assess whether 
to contract for new generation service from another supplier. The 
customer should specify in its request, to the extent possible, 
pursuant to its rights under the power sales agreement with the seller, 
the date on which the customer would substitute alternative generation 
for the requirements purchase and the amount of the substitution. Any 
remaining requirements 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(s) 
(e.g., a monthly or annual adder to its transmission rate or an up-
front lump-sum payment).
    (2) The utility shall, within thirty days of receipt of the 
request, or other mutually agreed upon period, provide the customer: 
(i) The customer's maximum possible stranded cost exposure without 
mitigation; or (ii) the formula that the utility would use to calculate 
the customer's maximum possible stranded cost exposure without 
mitigation. The utility's response should indicate the period over 
which the utility proposes to charge the departing customer. There 
should be appropriate support for each element in the calculation or 
formula to enable the customer to understand the basis for the element. 
The utility should provide a detailed rationale for its proposal as to 
how long the utility reasonably expected to keep the customer. The 
utility also should address how it intends to mitigate stranded costs.
    (3) If the customer believes that the utility has failed to 
establish that it had a reasonable expectation of continuing to serve 
the customer beyond the contract term or that the proposed maximum 
stranded cost charge without mitigation (or formula) is unreasonable, 
it will have thirty days in which to respond to the utility explaining 
why it disagrees with the charge. The parties should then attempt to 
reach a mutually-agreeable charge for stranded costs within a 
reasonable period.
    (4) If the parties are unable to resolve the matter pursuant to the 
procedures specified in (1)-(3) above, the customer may either: (a) 
File a complaint with the Commission under section 206 of the FPA to 
seek a Commission determination whether the utility has met the 
reasonable expectation standard and, if so, whether the proposed 
maximum stranded cost charge (or formula) satisfies the other 
evidentiary standards set forth in this rule;<SUP>281 or (b) wait until 
the proposed stranded cost charge is filed under section 205 of the 
[[Page 17701]] FPA, and contest it at that time.<SUP>282 In either 
case, i.e., a section 205 or 206 proceeding, the utility would only be 
able to seek stranded cost recovery according to the formula and other 
terms identified in its earlier discussions with the customer.

    \281\If a complaint is filed, neither the customer nor the 
utility could raise issues not identified in their earlier 
discussions. The burden of proof would be on the utility to satisfy 
the evidentiary standards related to stranded cost recovery.
    \282\As discussed in section III.F.1.c(10) infra, retail 
customers contemplating becoming wholesale customers may use the 
same procedures.
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    The above-described procedure would provide a customer an 
opportunity to know its maximum possible exposure as far in advance of 
its decision to change suppliers as the customer chooses (i.e., the 
customer can file its request for a stranded cost computation at any 
time). If the customer decides to contest the proposed stranded cost 
charge, in either a section 206 or 205 proceeding, it will know its 
exact exposure once the Commission has completed its review of the 
proposed charge. This procedure attempts to address the Cajun court's 
concern that exposure to an unknown stranded cost fee will discourage 
customers from looking at other suppliers. At the same time, this 
procedure will permit recovery of legitimate stranded costs as set 
forth herein.
    We strongly encourage utilities and their existing customers to 
attempt to resolve stranded cost issues through a mutually-agreeable 
exit fee or other stranded cost amendment to existing contracts that do 
not address stranded cost recovery.
    We invite comments on our proposal to drop the three-year 
negotiation requirement originally proposed in the Stranded Cost NOPR, 
and instead to permit amendments to certain existing requirements 
contracts at any time prior to the expiration of the contracts, or to 
permit utilities to seek recovery through a departing customer's 
transmission rates at any time prior to the expiration of the power 
sales contracts. We also invite comments on our proposal to establish a 
procedure whereby a wholesale requirements customer with an existing 
contract that does not explicitly address stranded costs can obtain its 
maximum stranded cost exposure without mitigation from the utility and 
can seek Commission review of the utility's reasonable expectation 
claim and the utility's proposed stranded cost charge or formula.
    (6) Filing Requirements for Wholesale Stranded Cost Recovery. The 
Commission proposes to amend Part 35, Chapter I, Title 18 of the Code 
of Federal Regulations to establish filing requirements for public 
utilities (as defined in FPA section 201(e)) and transmitting utilities 
(as defined in FPA section 3(23)) that seek stranded cost recovery. We 
reaffirm our view that the only circumstance in which transmitting 
utilities that are not also public utilities may seek stranded cost 
recovery from this Commission is through customer-specific surcharges 
to rates for transmission services under FPA sections 211 and 212, and 
that those surcharges may only apply to costs associated with existing 
contracts.
    The proposed regulations 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 seek comment on whether the proposed definition of ``wholesale 
stranded cost'' 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, and the 
customer does not thereafter become an unbundled transmission services 
customer of that utility. This situation might occur, for example, in a 
situation where the former requirements customer was in a non-
contiguous service area and does not need unbundled transmission 
service from the former seller in order to purchase power from a 
replacement supplier.
    Consistent with the initial Stranded Cost NOPR, the proposed 
regulations would 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 
(i.e., any wholesale requirements contract executed after July 11, 
1994), the proposed regulations would allow recovery of stranded costs 
only if the contract explicitly provides for recovery of stranded 
costs.
    Second, for existing wholesale requirements contracts (i.e., any 
wholesale requirements contract executed on or before July 11, 1994), 
the proposed regulations would specify that a utility may not recover 
stranded costs associated with such contract 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, the proposed rule would allow a public utility to seek 
recovery of stranded costs only as follows: (1) if the parties to the 
existing contract renegotiate the contract in accordance with this rule 
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, prior to the date the contract expires, and the 
Commission accepts or approves an amendment permitting stranded cost 
recovery; or (3) if the public utility files a request, prior to the 
date the contract expires, to recover stranded costs through an adder 
to a departing 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 an adder to a 
departing 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 contract does contain an 
explicit exit fee or other stranded cost provision.
    Fifth, for a retail-turned-wholesale customer, the proposed rule 
would allow a public utility or transmitting utility to file a request 
to recover stranded costs from the newly created wholesale customer 
through an adder to that customer's transmission rate.
    Sixth, for customers who obtain retail wheeling, a public utility 
or transmitting utility may seek recovery through transmission rates 
only if the state regulatory authority has no authority under state law 
at the time retail wheeling is required to address stranded costs.
    (7) Evidentiary Demonstration Necessary--Reasonable Expectation 
Standard.--In the Stranded Cost NOPR, we proposed, as part of the 
evidentiary demonstration that a public utility or transmitting utility 
must make to recover stranded costs in wholesale transmission rates, or 
through a unilateral amendment to the power sales contract, that the 
utility must show [[Page 17702]] that it incurred costs based on a 
reasonable expectation when the costs were incurred that the applicable 
contract would be extended.<SUP>283 We indicated that, in these 
situations, the question of whether a utility had a reasonable 
expectation of continuing to serve a customer is a factual matter that 
will depend on the evidence produced in each case. We further proposed 
that a notice provision in a contract would create a rebuttable 
presumption that the utility had no reasonable expectation of serving 
the customer beyond the period provided for in the notice provision. We 
invited comments with regard to these proposals and also asked whether 
we should adopt a minimum notice period that would create a presumption 
that the utility had no reasonable expectation of continuing to provide 
service beyond such period (e.g., a five-year notice period).<SUP>284

    \283\Stranded Cost NOPR at 32,873-74.
    \284\Id. at 32,874.
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    (a) Comments. Commenters express a variety of views on the 
reasonable expectation standard for extra-contractual cost recovery. 
Some commenters (e.g., the Transmission Access Policy Study Group) do 
not believe there is a legal basis to permit the claimed expectation of 
indefinite renewal of a contract to override a customer's express 
contractual termination rights. These commenters argue that there has 
never been any assurance that utilities will be allowed to recover all 
of their costs, no matter how incurred. These commenters assert that 
utilities have been on notice for years that customers may try to 
exercise their contractual right to terminate service when their 
contracts end, and that utilities would not be entitled to any contract 
extensions or other relief. These commenters state that the reasonable 
expectation test is an inadequate basis for denying customers their 
contractual termination rights.
    Other commenters (e.g., Environmental Action) state that if 
reasonable expectations (as opposed to contract language) are relevant, 
one must determine both the utility's and the customer's reasonable 
expectations. These commenters support the concept of contract 
symmetry; if there is no obligation to serve beyond the contract term, 
imposing an obligation to pay beyond the contract term is asymmetrical.
    With regard to the Commission's proposal that a notice provision in 
an existing contract creates a rebuttable presumption that there is no 
reasonable expectation that the contract will be renewed, many 
investor-owned utility commenters, as well as the Florida Commission 
and the Texas Commission, question whether a notice provision 
constitutes sufficient grounds for such an assumption. Because of the 
obligation to serve and the long lead time needed to construct new 
base-load generating units, they argue that a utility could have been 
found to be imprudent if it did not plan for and build sufficient 
generating capacity to meet its service obligations. These commenters 
maintain that it would have been unreasonable for a utility to assume 
that a customer that is served under a contract with a notice provision 
that has been repeatedly renewed would not again renew the contract. 
These commenters maintain that a notice provision is not sufficient to 
demonstrate a ``meeting of the minds'' on this issue.
    TVA states that the notice provisions in its contracts in no way 
lessen its intention to serve its customers. TVA states that its 
legislative provisions, planning process, and history all support the 
assumption that it will continue serving its wholesale customers 
indefinitely.
    Certain customer groups, such as the TDU Customers and the 
Wisconsin Wholesale Customers (Wisconsin Customers), believe that the 
Commission should make the rebuttable presumption stronger, i.e., that 
contracts with notice provisions should absolutely preclude stranded 
cost recovery. Wisconsin Customers state that there should be no 
opportunity for renegotiation to include stranded cost provisions in 
contracts with reasonable notice provisions.
    (b) Preliminary Findings. We believe we should retain a reasonable 
expectation standard as part of the evidentiary demonstration that a 
public utility or transmitting utility must make. 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. Depending on all of 
the facts and circumstances, a reasonable expectation that a contract 
would be extended could be established, for example, by: (1) Whether 
the customer had access to alternative suppliers; (2) a showing that 
the parties' actual conduct or course of dealing has been to renew the 
contract upon its scheduled expiration; (3) evidence that a utility has 
recovered construction-work-in-progress (for projects that would enter 
service after the scheduled contract expiration) from a particular 
customer without the customer's objection; or (4) communications 
between supplier and customer concerning system planning, such as an 
indication by a buyer that the seller should continue to include the 
buyer's load in the seller's resource planning beyond the contract 
term.\285\

    \285\See id. at 32,874.
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    In addition, as proposed in the initial NOPR, we believe that the 
existence of a notice provision in a contract should create a 
rebuttable presumption that the utility had no reasonable expectation 
of serving the customer beyond the period provided for in the notice 
provision. Of course, evidence that a contract with a notice provision 
has been repeatedly renewed (the scenario described by commenters 
opposing the creation of a rebuttable presumption) may, depending on 
the particular case, be sufficient to rebut the presumption that the 
utility had no reasonable expectation of contract renewal.
    Further, we will not adopt a minimum notice period for purposes of 
applying the reasonable expectation rebuttable presumption. We believe 
that whether a utility had 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. In these circumstances, we do not believe that a 
generic minimum notice period would be appropriate.
    In addition, 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.
    We seek further comment on the following specific aspect of the 
reasonable expectation standard: Should the reasonable expectation 
standard apply in a case where 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 or utilities? Should the 
Commission 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? In the 
alternative, should the Commission 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 or utilities? Finally, in the event that the 
seller establishes that it had a reasonable expectation, and the former 
wholesale customer does not take unbundled [[Page 17703]] transmission 
service from the former seller, what means ought to be available for 
the collection of stranded costs?
    (8) Identification of Recoverable Wholesale Stranded Costs. The 
Stranded Cost NOPR proposed, as part of the evidentiary demonstration 
necessary for wholesale stranded cost recovery, that a utility show 
that the stranded costs it incurred are not more than the customer 
would have contributed to the utility had the customer remained a 
wholesale requirements customer of the utility. We invited comments in 
the initial NOPR on what would constitute reasonable compensation for 
stranded costs and on how to determine the amount of stranded costs 
that the departing customer may be liable to pay. For example, we asked 
whether it would be reasonable to limit the annual amount of stranded 
costs to what the departing customer would have contributed to the 
utility's capital (customer revenues minus variable costs), or whether 
an alternative concept would be appropriate. We also requested comments 
as to what would constitute a ``reasonable compensation period'' over 
which to determine a customer's liability for stranded costs (e.g., 
five years, ten years, or some other period). We indicated that the 
present value of the customer's liability could be the discounted value 
of an annual amount for such reasonable compensation period and that 
this total amount could be paid in a lump sum or over any mutually 
agreeable period.\286\

    \286\Id. at 32,874-75.
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    We also assumed in the NOPR that stranded costs will be dominated 
by generating capacity, but stated that it is appropriate to consider 
stranded costs more broadly, including the possibility that fuel supply 
costs, purchased power costs (including QF costs), nuclear 
decommissioning costs, regulatory assets, and possibly other utility 
obligations may be stranded. Accordingly, we invited public comment on 
what categories of costs, in addition to investment costs, should be 
eligible for stranded cost recovery.\287\

    \287\Id. at 32,867.
    (a) Comments. (i) Acceptable Calculation Methods. Most commenters 
were not very specific regarding how to calculate the level of 
recoverable wholesale stranded costs. However, commenters that address 
this issue generally fall into three groups.
    The first group reflects the position of EEI and most investor-
owned utility commenters. This group proposes an asset-by-asset review 
of stranded investments (including contractual liabilities, regulatory 
assets, and certain social program costs) to develop a total company 
estimate of stranded costs that need to be recovered. These costs could 
then be allocated among customers to determine a hypothetical cost-of-
service measure of stranded cost liability. From this amount, the 
utility would subtract wheeling service revenues and any revenues from 
mitigation measures taken. As explained in more detail below in the 
discussion of allowable cost categories, investor-owned utility 
commenters argue for inclusion of a broad number of investments, 
expenses and future costs in the revenue requirement calculation of 
recoverable stranded costs. Commenters that support this approach also 
suggest that costs are properly included in the calculation (i.e., are 
recoverable wholesale stranded costs) to the extent that such costs 
have been ruled to be prudently incurred in a state determination.
    Some commenters, however, oppose a hypothetical cost-of-service 
calculation approach to determining recoverable stranded costs arguing 
that it will engender litigation. These commenters note that generating 
units are not built, and specific costs are not generally incurred, on 
behalf of individual customers. According to these commenters, 
attempting to define specific components of stranded costs associated 
with a specific departing customer is inconsistent with utility 
investment planning and historical cost incurrence.
    A second approach for determining recoverable wholesale stranded 
costs is based on ``revenues lost'' as a result of a customer switching 
suppliers. Most non-investor-owned utility commenters (e.g., state 
commissions and customers) and some investor-owned utilities (e.g., 
Commonwealth Edison Company (Commonwealth Edison), Utility Working 
Group (UWG)\288\) support this method of calculation. Commenters that 
support this approach argue that the calculation is less complex than a 
hypothetical cost-of-service approach and avoids an asset-by-asset 
review with its attendant accounting and tracking complexities.

    \288\The Utility Working Group members participating in UWG's 
comments in this proceeding are Dominion Resources, Inc., Duke Power 
Company, Duquesne Light Company, Entergy Corporation, General Public 
Utilities Corporation, Niagara Mohawk Power Corporation, Northern 
States Power Company, Pacific Gas and Electric Company, Portland 
General Electric Company, Public Service Electric and Gas Company, 
San Diego Gas & Electric Company, Southern California Edison 
Company, and Wisconsin Electric Power Company.
---------------------------------------------------------------------------

    Many commenters note that the revenues lost approach recognizes 
that utilities that made multiple investment decisions under the prior 
regulatory scheme compact expected a revenue stream from their 
customers to cover the costs of those investments. Under this approach, 
the measure of recoverable stranded costs is the difference between 
revenues expected from a customer under traditional regulation and the 
expected revenues in a competitive market. Some commenters suggest 
further limitations on the revenue stream calculation, i.e., 
calculating revenues on a present value basis, or using current 
revenues as the ceiling for utility expected revenues under the prior 
regulatory regime. According to commenters, these limitations serve at 
least two purposes: (1) Simplifying the calculation; and (2) creating 
incentives for utilities to mitigate stranded costs, which will shorten 
the transition period to a competitive market.
    Some commenters, including Public Service Electric and Gas Company 
(Public Service Electric), also point out that this approach is 
consistent with resource acquisition. These commenters note that 
specific investment decisions are not made on a retail/wholesale or 
customer-by-customer basis, but rather on the basis of resources needed 
to meet load, i.e., generation plant additions are made based on an 
analysis of total system needs. Commenters also note that under a 
revenues lost approach, specific investments/assets do not need to be 
assigned (or tracked) to a particular event causing stranded costs.
    A few commenters (e.g., APPA, Electric Generation Association, 
Illinois Commission) advocate a third method of calculating the level 
of recoverable wholesale stranded costs. Under this method, which is a 
``netting'' or ``market analysis'' approach, recoverable stranded costs 
would be determined based on the difference between embedded capital 
costs and the market value of stranded assets. While this approach is 
not dissimilar to a ``revenues lost'' approach, the level of stranded 
costs is generally determined only after a future action with respect 
to the stranded costs, i.e., auction, divestiture or other future 
disposition of assets. Other commenters (e.g., Central Vermont Public 
Service Corporation, Long Island Lighting Company (Long Island 
Lighting)) suggest variations of this ``netting'' approach, such as 
comparing the utility's revenues with some measure of the utility's 
marginal cost of requirements service. Commenters claim that, in a 
competitive market, the marginal cost would equal the market price. 
Thus, under this [[Page 17704]] approach, recoverable stranded costs 
are the excess above market value of the stranded assets. Duke Power 
Company notes that mitigation measures would be unnecessary if this 
method were used to calculate recoverable stranded costs because the 
utility's marginal cost (not just its variable expenses), i.e., the 
market price of the stranded assets, is used as the ``offsetting'' 
value in the calculation.
    (ii) Reasonable Compensation Period (how long utility could 
reasonably expect to keep customer). Commenters support a wide range of 
time periods as appropriate for determining a customer's stranded cost 
liability. Almost all of the commenters, however, request that the 
Commission provide flexibility in this regard and not establish a 
generic recovery period so that a variety of recovery mechanisms can be 
accommodated.
    Some state commission commenters (e.g., Illinois Commission) 
support a limited time period for determining a customer's stranded 
cost liability as an incentive for utilities to mitigate stranded 
costs. According to the Illinois Commission, limiting the time period 
over which a customer's stranded cost liability is to be determined 
should encourage utilities to ``fervently re-market the services 
produced by the potentially stranded resources.''\289\ Utility customer 
commenters (e.g., city of Las Cruces, TDU Customers) also support a 
limitation on the period over which stranded costs would be determined. 
These commenters propose limiting the reasonable compensation period to 
the lesser of the contractual notice period; the remaining portion of 
the stated term of a contract; a five-year period (as a maximum 
reasonable time to plan for mitigation measures); or the utility's 
planning horizon.

    \289\Illinois Commission comments at 61-62.
---------------------------------------------------------------------------

    Some investor-owned utility commenters (e.g., EEI, Centerior Energy 
Corporation), on the other hand, oppose limiting the period over which 
a customer's stranded cost liability would be determined. EEI, for 
example, states that as a general rule, the departing customer should 
be responsible for its regulated rate less the utility's marginal cost 
and mitigating revenue. It contends that the period of such 
responsibility should continue until the utility needs the capacity 
freed up by the departing customer to meet retail load growth or firm 
wholesale obligations. In effect, these commenters support an open-
ended opportunity to recoup wholesale stranded costs. They argue that 
the recovery period should continue as long as possible to ensure that 
native load customers are held harmless.
    (iii) Allowable Cost Categories. Almost all commenters agree that 
stranded costs should not include variable expenses. The majority of 
customer commenters either: (1) Support the Commission's proposed 
categories; or (2) do not express an opinion regarding cost categories 
that are appropriate for recovery because they support the use of some 
type of ``revenues lost'' approach for determining recoverable costs, 
which does not require the identification of specific utility 
investments or expenses.
    Many investor-owned utility commenters, however, contend that, in 
addition to the items identified in the NOPR, recoverable stranded 
costs should include a broad number of other investments, expenses and 
future costs. These commenters propose that the additional items that 
are eligible for recovery should include, but not be limited to:
    <bullet> Construction work in progress;
    <bullet> Regulatory assets, such as phase-in plans for new 
generation plant, and accrual accounting requirements (e.g., income tax 
normalization, accounting for pension and PBOP costs);
    <bullet> Actual nuclear decommissioning costs as well as a 
utility's pro rata obligation to dismantle and decontaminate DOE's 
uranium enrichment facilities;
    <bullet> All fuel costs pending recovery via fuel adjustment 
mechanisms;
    <bullet> Mandatory social program costs including DSM, low-income 
assistance, environmental clean-up and various R&D projects;
    <bullet> Clean Air Act compliance costs;
    <bullet> Storm damage expenses; and
    <bullet> Other unknown future liabilities.
    In addition, EEI states that before 1992, i.e., pre-EPAct, no 
regulatory commission explicitly authorized a rate of return that 
compensated a utility for the risk of future retail competition. EEI 
notes that after EPAct only four regulatory commission decisions have 
addressed this issue. Because the risks of the new competitive market 
were neither contemplated by investors nor compensated by regulators 
under existing ratemaking, EEI argues that the cost of such risk must 
also be included as a category of costs eligible for stranded cost 
recovery.
    Public Power Council suggests that there are two dangers in 
creating lists of eligible and ineligible costs: (1) Wasteful 
regulatory battles are likely; and (2) utility managers will have the 
incentive to reduce ineligible costs, while ignoring opportunities to 
reduce eligible costs.
    (b) Preliminary Findings. The Commission preliminarily concludes 
that the determination of recoverable stranded costs should be based on 
a ``revenues lost'' approach rather than a hypothetical cost-of-service 
approach. The Commission believes that this approach has greater 
benefits than a hypothetical cost-of-service approach. A ``revenues 
lost'' approach avoids the asset-by-asset review that is required by 
alternative cost-of-service approaches in order to calculate 
recoverable stranded costs. Cost allocation procedures are also 
minimized. Moreover, the Commission believes that this approach will be 
easier to apply, thereby minimizing the cost of administering stranded 
cost recovery.
    The Commission's experience in the natural gas industry is relevant 
here. Certain pipelines faced with take-or-pay obligations under 
uneconomic natural gas supply contracts have developed a ``pricing 
differential'' mechanism that has enabled them to honor existing take-
or-pay obligations, while attempting to renegotiate the contracts.\290\ 
Under this mechanism, the pipeline continues to meet its contractual 
purchase obligation and continues to market the gas purchased through 
its separate marketing operation. The ``differential'' or ``revenues 
lost'' between the purchase price and the sales price is passed through 
as a transition cost.\291\

    \290\Texas Eastern Transmission Corporation, 63 FERC para.61,100 
at 61,507 (1993).
    \291\For details on the mechanics of this program, see Texas 
Eastern Transmission Corporation, 63 FERC at 61,507-08; Texas 
Eastern Transmission Corporation, 64 FERC para.61,378 (1994).
---------------------------------------------------------------------------

    Under the revenues lost method that we propose here, the utility 
would calculate a customer's stranded cost liability by subtracting the 
competitive market value of the power the customer would have purchased 
from the utility (and the basic revenues from the transmission service) 
had the customer continued to take service under its contract from the 
revenues that the customer would have paid the utility. As discussed in 
section III.F.1.c(9) infra, the utility must attempt to mitigate 
stranded costs by marketing stranded power supplies.
    The Commission seeks further comments on the revenues lost 
approach. In particular, what would be the appropriate method to 
calculate what the utility's revenue stream would have been had the 
customer continued service (e.g., current revenues based on current 
service levels, or should projection and adjustments reflecting changes 
in the revenue stream be permitted)? The Commission also seeks comments 
on the appropriate method to [[Page 17705]] calculate the revenues that 
the utility would receive in a competitive market for the stranded 
assets. Should the Commission require the utility to track the actual 
selling price of the power over time, or should it 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? Should the Commission allow prices in futures 
markets or forward markets to be used in an up-front approach, assuming 
such financial instruments become available? In addition, how should 
revenues received as a result of mitigation measures 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? Once determined, should any adjustment 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?
    With regard to establishing a reasonable compensation period (i.e., 
setting a limit on how long the utility could have reasonably expected 
to keep the customers), we do not believe that a one-size-fits-all 
approach is appropriate. A particular customer's stranded cost 
liability will depend, in each instance, on such case-specific factors 
as whether the utility can demonstrate that it had a reasonable 
expectation of continuing to serve the customer beyond the term of the 
contract and, if so, for how long. Therefore, we believe it appropriate 
to permit utilities and their customers some flexibility with regard to 
the period over which a customer's stranded cost liability would be 
determined. However, we will not allow an open-ended opportunity to 
recoup wholesale stranded costs. Although our preliminary finding is 
that a one-size-fits-all approach is not appropriate, we seek further 
comment with respect to whether the Commission ought to establish 
presumptions or, in the alternative, absolute limits on a customer's 
maximum liability in those situations where a utility establishes that 
it had a reasonable expectation that the contract would be extended. 
For instance, would it 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? What other events or criteria might the 
Commission use to establish either presumptions or absolute limits on 
the time period over which the customer's liability for stranded costs 
would be determined?
    Our decision to adopt a revenues lost approach for determining 
recoverable stranded costs, which avoids an asset-by-asset review, in 
effect eliminates the need to enumerate specific categories of costs 
that may be recovered. However, there may be special categories of 
costs that are properly allocated to departing customers and that are 
not captured in the revenues lost approach. For example, nuclear 
decommissioning costs may not be reflected, or may not be fully 
reflected, in current requirements rates. To the extent this is true, a 
departing customer may be ``escaping'' from costs that it caused as a 
result of taking power service from its supplier during the time that 
the nuclear plant was operating. We seek 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. We also solicit 
comments as to whether the Open Access NOPR raises any additional 
implementation or other issues affecting stranded cost recovery as 
proposed here.
    (9) Mitigation Measures. As part of the evidentiary demonstration 
that a utility must make in order to recover stranded costs, the 
Stranded Cost NOPR would require the utility to show that it has taken 
and will take reasonable and prudent measures to mitigate stranded 
costs. The Commission proposed in the initial NOPR that adequate 
mitigation measures might include: (1) Evidence that the utility has 
tried to market the asset or assets, market the generating capacity, 
reconfigure or delay investment in or purchase of new generating 
capacity, or reform fuel supply contracts that form the basis for the 
stranded costs charge, and that such measures to mitigate stranded 
costs will continue for the entire period for which the stranded costs 
charge will be paid; or (2) the utility has given the customer the 
option to market the generating capacity or supply of fuel or purchased 
power that forms the basis for the stranded cost charge in order to 
afford the customer an opportunity to lower its stranded costs charge. 
We invited comment on the mitigation requirement and what reasonable 
measures to mitigate may include.
    (a) Comments. Although there is nearly unanimous support for 
requiring that mitigation measures be taken, commenters raise several 
issues regarding how mitigation should be implemented and the 
effectiveness of such a requirement.
    As noted above, many investor-owned utility commenters argue that 
stranded costs should be defined to include costs other than capital 
investment in utility property. According to these commenters, stranded 
costs also may include environmental clean-up costs, decommissioning 
costs, and regulatory assets resulting from cost recovery deferrals. 
Unlike capacity, these costs cannot be ``marketed.'' Therefore, 
mitigation measures cannot be taken with respect to these costs. Thus, 
according to some commenters, there is a category of ``unmarketable'' 
stranded costs for which mitigation efforts to reduce the level of the 
costs are not possible.
    Many commenters (e.g., Texas Commission, TDU Customers) contend 
that a mitigation requirement will be more effective if incentives to 
mitigate are created. These commenters suggest several options, 
including:
    <bullet> Limiting recovery of stranded costs to current rate levels 
(no projections of increases in stranded costs for future periods);
    <bullet> Requiring shareholders to shoulder some cost 
responsibility (to ensure that mitigation measures will be aggressively 
pursued); and
    <bullet> Requiring any stranded investment to be offered for sale, 
either with the departing customer permitted to ``sell'' the stranded 
investment, or through some form of auction.
    Other commenters suggested that effective mitigation would require 
auctioning off stranded assets or some type of general divestiture of 
assets by the utility that is allowed to recover stranded costs.
    Many commenters acknowledge that revenues from mitigation measures 
should reduce the amount of wholesale stranded costs. An issue is 
raised, however, regarding how revenues associated with mitigation 
measures should be credited. Given the overall preference by commenters 
supporting stranded cost recovery for direct assignment of stranded 
costs to a departing customer, explicit crediting mechanisms and 
accounting requirements--and perhaps new accounts or subaccounts--would 
be needed to keep track of amounts owed by those assessed wholesale 
stranded costs. Consequently, these commenters contend that decisions 
regarding who should pay (and how) for wholesale stranded costs must be 
coordinated with decisions regarding the implementation of required 
mitigation measures so that parties receive appropriate credits. 
[[Page 17706]] 
    (b) Preliminary Findings. We note that the revenues lost approach 
for determining recoverable stranded costs encompasses 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 under its contract. Thus, our suggestion in the initial NOPR that 
revenues associated with mitigation measures be credited to the 
departing customer through reductions to that customer's surcharge is 
in effect accomplished by adoption of the revenues lost approach. 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. Nonetheless, we emphasize that mitigation as a 
general matter remains important, and seek comment regarding 
implementation of a mitigation requirement. For example, if mitigation 
is trued-up over time, how should the Commission ensure that the 
utility takes all reasonable steps to mitigate its own costs so as to 
minimize what the customer would have paid? How should the Commission 
ensure that the utility does its best to sell the power at its highest 
possible value so as to mitigate the customer's stranded cost 
liability? Are there other mitigation measures that should be taken 
into account (e.g., 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)?
    (10) Federal Forum for ``Retail'' Stranded Cost Recovery and 
Proposed New Definition of ``Wholesale'' Stranded Costs. In the initial 
NOPR, the Commission described two general ways in which retail 
stranded costs are likely to occur: (1) A retail franchise customer or 
group of such customers may, through state or local government action, 
become a wholesale customer that can then obtain unbundled transmission 
services in order to reach a new power supplier; and (2) a retail 
franchise customer may obtain voluntary unbundled retail transmission 
services from its existing power supplier in order to reach a new power 
supplier, or there may be a State or local government action that 
results in the existing supplier providing such retail transmission 
services. The Commission requested comments concerning the extent to 
which the Commission should provide a forum for resolving retail 
stranded cost issues. The Commission proposed two alternatives for 
addressing this issue. Under the first alternative, the Commission 
proposed that it would not entertain a request for retail stranded cost 
recovery if, in a specific circumstance, an appropriate state authority 
explicitly considers and deals with retail stranded costs and there is 
no conflict within or among state regulatory bodies regarding a state's 
disposition of the issue. However, in the absence of a clear expression 
by an appropriate state authority that it has dealt with the issue, or 
in the event of a conflict between states or among state officials 
within a single state, the Commission proposed to entertain requests to 
recover retail stranded costs. Under the second alternative, the 
Commission proposed not to entertain any request for recovery of retail 
stranded costs. Under this alternative, we proposed that state or local 
authorities would be the only forum for addressing the issue.\292\

    \292\Stranded Cost NOPR at 32,878-79.
    (a) Comments. Most of the state commissions comment that the 
Commission should not provide a forum for addressing retail stranded 
cost issues. The Massachusetts Department of Public Utilities suggests 
Commission involvement only if a conflict arises through disparate 
stranded cost treatment by different states that the states are unable 
or unwilling to resolve. The Pennsylvania Commission suggests 
Commission involvement in retail stranded cost issues only if states 
have lost jurisdiction (for instance, due to municipalization). Most of 
the state commissions argue that retail costs are subject to exclusive 
state jurisdiction and that action or inaction by a state or any 
differences between state actions are matters to be resolved by the 
courts, not the Commission. Many of these commenters (e.g., NARUC) note 
that numerous differences in ratemaking currently exist among states 
and that the Commission has not attempted to resolve those differences; 
they see no distinction with regard to retail stranded cost recovery. 
Some state commissions also argue that the possibility of Commission 
involvement in retail stranded cost recovery could introduce ``forum 
shopping.''
    The New York State Public Service Commission (New York Commission) 
suggests that the Commission provide a backstop to the states only if a 
state has taken no action regarding retail stranded costs. The Ohio 
Public Utilities Commission (Ohio Commission) and the Wyoming Public 
Service Commission suggest that the Commission become involved in 
retail stranded costs only at the request or petition of a state. 
Commenters representing investor-owned utilities, on the other hand, 
overwhelmingly agree that the Commission should provide a forum for 
resolving retail stranded cost issues. They propose a broad range of 
scenarios in which Commission involvement in retail stranded cost 
recovery is appropriate.
    EEI, Commonwealth Edison, Florida Power and Northern States Power 
Company argue that the Commission should act as a backstop to state 
commissions with authority to address retail stranded cost issues: (1) 
To address yet undefined questions; (2) when no state commission action 
is taken; or (3) when state commission action is not taken in a fair 
and timely manner or results in the confiscation of utility property.
    Allegheny Power, Arizona Public Service Company and Virginia 
Electric and Power Company argue that the Commission should provide a 
forum to address situations in which states allegedly have no authority 
to address retail stranded cost issues (primarily municipalization).
    The Coalition for Economic Competition, Entergy, Utility Working 
Group, and the Nuclear Energy Institute urge the Commission to address 
situations in which state policy is inconsistent with Commission 
policy. In fact, many investor-owned utilities advocate the 
establishment of uniform national guidelines for stranded cost recovery 
that will be applicable to both wholesale and retail stranded costs. 
These commenters contend that the Commission is the only body capable 
of fulfilling this role.
    Houston Lighting & Power Company urges the Commission to address 
retail stranded costs whenever retail stranded costs have a substantial 
adverse impact on interstate transmission.
    Two investor-owned utilities support Commission involvement in 
retail stranded cost issues only in limited circumstances. Entergy 
contends that Commission involvement is necessary only if state 
jurisdiction is evaded (i.e., certain cases of municipalization). 
Public Service Electric states that Commission oversight is needed to 
ensure that final results are consistent with Commission guidelines and 
are pro-competitive.
    Commenters representing small customer interests, such as Electric 
Consumers' Alliance and the National Black Caucus of State Legislators, 
support Commission involvement in retail stranded cost issues in order 
to ensure that large customers that leave the system do not evade their 
fair share [[Page 17707]] of stranded costs to the detriment of 
residential and other small customers.
    Commenters representing municipal and electric cooperatives (such 
as APPA, TAPS and SCOOP), commenters representing independent power 
producers (such as the National Independent Energy Producers), 
commenters representing industrial customers, some customer advocacy 
group commenters (such as Industrial Consumers, American Forest, and 
the National Association of State Utility Consumer Advocates (NASUCA)), 
and commenters representing environmental groups (such as CLF) 
generally oppose Commission involvement in retail stranded cost issues.
    DOE agrees with the Commission that retail stranded cost recovery 
is primarily a state issue. However, DOE states that the Commission has 
correctly determined that it has authority to regulate the rates, terms 
and conditions of retail transmission service. Accordingly, DOE 
supports Commission involvement in retail stranded cost issues.
    DOE notes that states may decide to make retail competition 
contingent upon the recovery of stranded costs by their jurisdictional 
utilities. DOE states that the Commission does not appear to have 
considered the possibility that a utility may seek recovery of retail-
related stranded costs through a retail transmission tariff filed with 
this Commission that has the support of the state commission. DOE 
submits that the Commission, as a matter of policy, should allow 
utilities to file tariffs for retail transmission service that recover 
stranded retail costs when such filings have the support of the 
affected state commissions. However, DOE states that the Commission 
should not give deference to tariffs for retail transmission service 
that contain a provision for stranded cost recovery if the tariff is 
opposed by any state commission that has a material interest in the 
filing.
    Public Service Electric states that due to the vertical integration 
of electric utilities, the distinction between wholesale and retail 
stranded costs is merely a matter of cost allocation. It contends that 
utilities generally do not have specific generating facilities in place 
to serve strictly wholesale customers, but rather include wholesale 
customer loads into their planning models as if they were retail 
customers. Public Service Electric thus concludes that no distinction 
between wholesale and retail stranded costs is necessary for purposes 
of evaluating stranded cost recovery.
    In contrast, other commenters contend that there are inherent 
differences between retail and wholesale stranded costs, resulting 
primarily from the different regulatory regimes in place. These 
commenters state that, at the state level, a utility provides retail 
service pursuant to a ``regulatory compact'' under which the utility 
undertakes an obligation to serve retail customers in exchange for an 
exclusive service franchise. In contrast, they submit that the 
utility's obligation to serve a customer at the wholesale level is 
established through contract. Some commenters conclude that these 
differences necessitate different approaches for recovery of wholesale 
and retail stranded costs.
    Several commenters (e.g., Duke, Entergy, Long Island Lighting, 
Nuclear Energy Institute,\293\ Public Service Electric, Coalition for 
Economic Competition, Utility Working Group) request that the 
Commission issue a uniform national set of standards to govern the 
treatment of all stranded investment (both retail and wholesale), 
irrespective of jurisdiction with respect to retail stranded costs.

    \293\Nuclear Energy Institute's utility members operate all 
(109) of the nuclear power plants in the United States.
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    In contrast, several of the state commission commenters emphasize a 
need for flexibility in dealing with retail stranded costs in lieu of a 
one-size-fits-all solution, which they argue may fail to address 
important differences between states. Accordingly, several of the state 
commission commenters, including the Alabama, California, Indiana, 
Michigan, and New York Commissions, urge that the Commission develop in 
cooperation with the state commissions a flexible approach to retail 
stranded cost recovery through various means such as joint boards or 
through more informal conferences or other joint forums.
    With respect to the issue of stranded costs caused by retail-
turned-wholesale customers, EEI and several investor-owned utilities 
(particularly those in Michigan, New York and California) maintain that 
the most important stranded cost issue before the Commission at this 
time is the formation of new municipal utilities. These commenters urge 
Commission involvement in the recovery of stranded costs resulting from 
this action. EEI notes that most states have constitutions or laws that 
permit municipalization, through which groups of retail customers may, 
in effect, become wholesale customers and thereby transfer primary 
regulatory responsibility for regulating sales to such entities from a 
state commission to the Commission.
    EEI argues that in most instances the Commission will be the 
regulatory body that will have to consider stranded cost recovery 
issues resulting from municipalization. EEI states that in 
approximately 28 states, there is virtually no limitation on the 
ability of municipalities to form utilities or to oust current 
suppliers;\294\ these states will be unable to protect their utilities 
from stranded costs. According to EEI, only 14 state commissions have 
some jurisdiction over the creation or expansion of municipal 
utilities,\295\ and only a few states require reimbursement for 
stranded generation or for lost earnings. Moreover, EEI notes that 
condemnation proceedings based on eminent domain principles often do 
not consider regulatory policies regarding stranded cost assignment and 
recovery.

    \294\EEI states that these states are Arizona, Connecticut, 
Delaware, Florida, Georgia, Idaho, Illinois, Kansas, Kentucky, 
Louisiana, Michigan, Minnesota, Montana, Nevada, New Jersey, New 
Mexico, New York, North Dakota, Ohio, Oklahoma, Oregon, Rhode 
Island, South Dakota, Tennessee, Utah, Virginia, Washington and 
Wyoming.
    \295\EEI states that these states are Alaska, Arkansas, Iowa, 
Indiana, Maryland, Massachusetts, North Carolina, New Hampshire, 
South Carolina, South Dakota, Texas, Vermont, West Virginia and 
Wisconsin.
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    NARUC, on the other hand, argues that states and/or state 
commissions have the ability to address all retail stranded cost 
issues. From NARUC's perspective, the recovery of stranded costs due to 
municipalization is a matter to be addressed by state authorities. 
Appendix D to NARUC's comments contains information regarding state 
practices and policies in the areas of municipalization and newly-
municipalized service territory (i.e., annexation). While policies do 
vary among the states, NARUC as well as most state commission 
commenters (e.g., Iowa Commission) maintain that state authorities 
(commissions, courts and legislative bodies) clearly have the ability 
to impose stranded asset payments on new municipal utilities. NARUC 
contends that resolution by state authorities is mandated by the legal 
authority of the states to act, and does not depend upon Commission 
deference to the states. NARUC also cautions the Commission against 
becoming an appellate body for reviewing state determinations that 
allegedly overrecover or underrecover stranded costs.
    However, NARUC suggests two situations where Commission involvement 
with stranded cost recovery in a municipalization scenario 
[[Page 17708]] is reasonable. The first case is when a state determines 
that the appropriate cost recovery mechanism would involve a wholesale 
transmission rate beyond the state's jurisdiction. The second case is 
when the sequence of events or the timing of the transaction creates 
some ambiguity regarding the retail or wholesale character of the costs 
(e.g., the Massachusetts Bay Transit Authority case cited in the NOPR).
    Some commenters (e.g., Florida Commission) request joint federal/
state consultation on the issue of municipalization. The Florida 
Commission also requests that the Commission delay the effectiveness of 
wholesale contracts resulting from municipalization until retail 
stranded cost issues are resolved.
    (b) Preliminary Findings. As discussed in the initial NOPR, as a 
general matter we believe 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 wholesale wheeling, or from retail customers who obtain retail 
wheeling, in order to reach a different generation supplier. Based on 
an analysis of all the comments received, we propose to exercise our 
authority to address stranded costs as follows.
    Because the vast majority of commenters have urged the Commission 
not to assume responsibility for retail stranded costs, except in 
certain circumstances, we have concluded that it is appropriate to 
leave it to state regulatory authorities to deal with any stranded 
costs occasioned by retail wheeling. The circumstances under which we 
will entertain requests to recover stranded costs caused by retail 
wheeling are when the state regulatory authority does not have 
authority under state law to address stranded costs at the time the 
retail wheeling is required. We continue to believe that utilities are 
entitled, from both a legal and policy perspective, to an opportunity 
to recover all of their prudently incurred costs. In addition, as 
discussed further below, we believe the Commission should be the 
primary forum for addressing recovery of stranded costs caused by 
retail-turned-wholesale customers.
    With regard to stranded costs caused by retail wheeling, we 
emphasize that we will not allow states to use the interstate 
transmission grid as a vehicle for passing through any retail stranded 
costs, with the limited exception discussed above. Only if the state 
regulatory authority does not have authority under state law at the 
time the retail wheeling is required to resolve the retail stranded 
cost issue will we permit a utility to seek a customer-specific 
surcharge to be added to an unbundled transmission rate. We have 
accepted the view that stranded costs caused by retail wheeling are 
primarily a matter of local or state concern. Thus, these costs 
generally must be passed through in a manner that does not involve 
``transmission of electric energy in interstate commerce'' as that 
phrase is used in the FPA. We are proposing to prohibit the pass-
through of these costs on interstate transmission facilities except in 
the limited circumstance described. As discussed in section 
III.F.1.c(11), we believe that most states have a number of mechanisms 
for addressing stranded costs caused by retail wheeling, as well as 
retail-turned-wholesale customers. In addition, as further discussed in 
section III.F.1.c(12), we are proposing to define ``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. States therefore will be free to impose stranded costs 
caused by retail wheeling on facilities or services used in local 
distribution.
    At this juncture, the Commission is comfortable with this approach 
and our hope is that a federal forum for recovery of retail stranded 
costs ultimately will not be necessary. When states address retail 
stranded costs caused by retail wheeling, the Commission holds the 
strong expectation that states will provide procedures for, and the 
full recovery of, legitimate and verifiable stranded costs. This is the 
same standard we set out for wholesale stranded costs. We do so as part 
of our goal to assure a smooth and orderly industry transition to 
competition that is fair to all affected parties. In this proposal we 
also set out procedures that all parties can use to seek equitable 
treatment of stranded cost recovery. Again, we expect a state providing 
for direct access to provide similar procedures. We know that states 
are aware and concerned about the impacts of providing direct access as 
shown by many state comments. Based on this awareness and concern, we 
anticipate state approaches to retail stranded costs not unlike our 
approach to wholesale stranded costs. Although our hope is that a 
federal forum will not be necessary, we will watch with interest the 
states' efforts to address the retail stranded cost problem.
    We believe this approach represents an appropriate balance between 
federal and state interests. It ensures that the wholesale market, 
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 burden 
customers in another state with stranded costs due to retail wheeling.
    We have a different view with regard to stranded costs caused by 
retail-turned-wholesale customers. If a retail customer becomes a 
legitimate wholesale customer, e.g., through municipalization, it would 
thereby become eligible to use the non-discriminatory open access 
tariffs we are proposing to require public utilities to provide. 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. While the 
stranded costs likely would derive primarily from generation 
investments that previously were in retail rate base, we note that 
utilities generally build generating facilities and incur other costs 
to serve their entire load, both retail and wholesale. We believe that 
costs stranded by the departure of a retail-turned-wholesale customer 
could and should be considered FERC-jurisdictional stranded costs once 
the new wholesale customer begins taking wholesale transmission 
services. They are identifiable economic costs that were incurred by 
the jurisdictional transmitting utility, and they do not disappear 
simply because the identity of the customer changes from retail to 
wholesale. There is a clear nexus between the FERC-jurisdictional 
transmission and the exposure to non-recovery of prudently incurred 
costs. Accordingly, we believe 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.
    To implement this policy, we propose to change the definition of 
``wholesale stranded costs'' that was contained in the initial NOPR, 
and to propose a definition that includes stranded costs resulting from 
unbundled wholesale transmission for newly created wholesale customers. 
We seek comment on this proposed change.
    We propose 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 
wholesale requirements customers leave a utility's system. In this 
regard, we no longer propose to [[Page 17709]] adopt the proposal in 
the initial NOPR that the ``reasonable expectation'' test should not 
apply in the case of retail-turned-wholesale customers or retail 
customers that obtain retail wheeling.<SUP>296 We propose that the 
utility must demonstrate that it incurred stranded costs based on a 
reasonable expectation that the customers would continue to receive 
bundled retail service. We expect 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.<SUP>297 We solicit comments on this proposed change.

    \296\Stranded Cost NOPR at 32,879.
    \297\We note, however, that certain states do not have service 
territories or have non-exclusive service territories (e.g., 
Louisiana).
---------------------------------------------------------------------------

    We reaffirm our proposal in the initial NOPR that utilities will 
have to make an evidentiary showing that the stranded costs are not 
more than the net revenues that retail-turned-wholesale customers or 
retail customers that obtain retail wheeling would have contributed to 
the utility had they remained retail customers of the utility, and that 
it has taken and will take reasonable steps to mitigate stranded costs. 
If the state has permitted any recovery from departing retail-turned-
wholesale customers, we will deduct that amount from what we determine 
to be legitimate stranded costs for which we will allow recovery.
    The procedures that we propose for a wholesale customer to file 
with the public utility when it requests computation of its stranded 
cost exposure will apply with equal force to a retail customer 
contemplating becoming a wholesale transmission customer (e.g., through 
municipalization). In particular:
    (1) Such a retail customer or group of customers may, at any time, 
request the public utility to either: (i) Calculate its maximum 
possible stranded cost exposure without mitigation, as of the date set 
forth in the customer's request; or (ii) provide the formula that the 
utility would use to calculate the customer's maximum possible stranded 
cost exposure without mitigation, to enable the customer to assess 
whether to become a wholesale transmission customer. The customer 
should specify in its request, to the extent possible, the date on 
which the customer would become a wholesale transmission customer of 
the utility and the amount of generation, if any, it will continue to 
purchase from its existing supplier. 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(s) 
(e.g., a monthly or annual adder to its transmission rate or an up-
front lump-sum payment).
    (2) The utility shall, within thirty days of receipt of the 
request, or other mutually agreed upon period, provide to the customer: 
(i) The customer's maximum possible stranded cost exposure without 
mitigation; or (ii) the formula that the utility would use to calculate 
the customer's maximum possible stranded cost exposure without 
mitigation. The utility's response should indicate the period over 
which the utility proposes to charge the departing customer. There 
should be appropriate support for each element in the calculation or 
formula to enable the customer to understand the basis for the element. 
The utility should provide a detailed rationale for its proposal as to 
how long the utility reasonably expected to keep the customer. The 
utility also should address how it intends to mitigate stranded costs.
    (3) If the customer believes that the utility has failed to 
establish that it had a reasonable expectation of continuing to serve 
the customer or that the proposed maximum stranded cost charge without 
mitigation (or formula) is unreasonable, it will have thirty days in 
which to respond to the utility explaining why it disagrees with the 
charge. The parties should then attempt to reach a mutually-agreeable 
charge for stranded costs within a reasonable period.
    (4) If the parties are unable to resolve the matter pursuant to the 
procedures specified in (1)-(3) above, the customer may either: (a) 
File a complaint with the Commission under section 206 of the FPA to 
seek a Commission determination whether the utility has met the 
reasonable expectation standard and, if so, whether the proposed 
maximum stranded cost charge (or formula) satisfies the other 
evidentiary standards set forth in this rule;<SUP>298 or (b) wait until 
the proposed stranded cost charge is filed under section 205 of the 
FPA, and contest it at that time. In either case, i.e., a section 205 
or 206 proceeding, the utility would only be able to seek stranded cost 
recovery according to the formula and other terms identified in its 
earlier discussions with the customer.

    \298\If a complaint is filed, neither the customer nor the 
utility could raise issues not identified in their earlier 
discussions.
    (11) State Mechanisms to Address Stranded Costs Caused By Retail 
Wheeling. The initial NOPR set forth a number of mechanisms that the 
Commission believes states can use to address stranded costs caused by 
retail wheeling and retail-turned-wholesale customers. We suggested 
that a state that permits a retail franchise customer to become a 
wholesale entity may consider whether to impose an exit fee prior to, 
or as a condition of, creating the wholesale entity.<SUP>299 We also 
suggested that a state may consider whether to require payment of an 
exit fee prior to a franchise customer being permitted to obtain 
unbundled retail wheeling. We noted that, in situations in which local 
distribution facilities are used by a retail wheeling customer, the 
state may consider whether to allow recovery of stranded costs through 
rates for local distribution services. Further, if a state decides not 
to impose an exit fee, or a surcharge through distribution rates, 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.

    \299\Stranded Cost NOPR at 32,878.
---------------------------------------------------------------------------

    We further suggested the possibility that state condemnation 
proceedings will provide a forum for a utility to seek recovery of any 
stranded costs where a new wholesale entity obtains ownership or 
control of a franchise utility's transmission or distribution 
facilities. The Commission solicited comments on other mechanisms that 
states can use to determine whether to allow stranded cost recovery, 
and from whom to allow recovery, and whether those mechanisms are 
adequate to deal with retail stranded costs.
    (a) Comments. We note, as an initial matter, that many of the state 
commission commenters did not specifically respond to our questions 
concerning mechanisms available to the states for addressing stranded 
costs. Those that did, such as NARUC, the Texas Commission and the 
Vermont Department, however, agree that the states have a variety of 
mechanisms available to deal with stranded costs. In addition to the 
mechanisms that we identified in the initial NOPR (i.e., imposing an 
exit fee prior to, or as a condition of, creating the wholesale entity; 
requiring an exit fee before a franchise customer is permitted to 
obtain unbundled retail wheeling; imposing a surcharge on local 
distribution rates; or state condemnation proceedings), these 
commenters identified the following: (1) Avoiding stranded costs in the 
first instance by seeking to preserve the integrity of the 
[[Page 17710]] utility's franchised service territory;<SUP>300 (2) 
seeking to reduce the burden of uneconomic costs through accelerated 
depreciation, revaluing of assets, or adjusting returns during the 
transition period; (3) allowing utilities to charge discounted rates 
(i.e., below embedded cost but above marginal cost) or reforming retail 
rates through new rate methodologies such as performance-based pricing 
or price caps; (4) charging access fees to generating entities seeking 
to enter retail markets; (5) adopting tax-based solutions, such as 
credits or deductions; (6) requiring utility write-offs of uneconomic 
costs; (7) establishing a stranded cost recovery fund to be funded 
through a broad-based surcharge or a tax on retail market participants; 
(8) encouraging research and development of more efficient end-use 
electrical technologies; and (9) not guaranteeing service to a 
departing customer that seeks to resume retail service if capacity is 
unavailable when the customer seeks to return. NARUC suggests that 
these options are not mutually-exclusive, but instead could be used in 
combination with others depending on the particular circumstances.

    \300\The Texas Commission suggests, for example, that a state 
might limit certain forms of retail competition, such as retail 
wheeling or multiple certification in utility service areas.
---------------------------------------------------------------------------

    In response to our question whether these mechanisms are adequate 
to deal with retail stranded costs, NARUC submits that the states have 
adequate legal authority to impose any existing regulatory mechanisms 
or to enact new mechanisms that may be needed to address stranded cost 
issues. NARUC further states that whether these mechanisms are adequate 
to provide utilities firm assurance that stranded costs will be 
recovered is not relevant to the Commission's inquiry. It argues that 
whether a utility in a particular case recovers all or part of what it 
identifies as stranded retail costs should be a fact-based 
determination made by the appropriate state commission(s).
    (b) Preliminary Findings. We are satisfied that the states do have 
a number of mechanisms available to them to address stranded costs that 
result from retail customers who obtain retail wheeling, in order to 
reach a different generation supplier.<SUP>301 We encourage the states 
to use the mechanisms available to them in whatever way they deem 
appropriate to address stranded costs.

    \301\As discussed above, we have determined that we will address 
stranded costs caused by retail-turned-wholesale customers.
---------------------------------------------------------------------------

    (12) Commission Authority to Regulate Transmission Rates, Terms, 
and Conditions for Unbundled Retail Transactions and Definition of 
State Jurisdictional Local Distribution. In the NOPR, the Commission 
stated that it has exclusive jurisdiction over the rates, terms and 
conditions of unbundled retail interstate transmission services. We 
based our conclusion in that regard on the plain meaning of the FPA and 
noted that there is nothing in the statute, the legislative history, or 
the case law to indicate that the Commission's jurisdiction over the 
rates, terms and conditions of transmission in interstate commerce 
extends only to wholesale transmission and not to retail 
transmission.<SUP>302 In the initial NOPR, we left open the question of 
the jurisdictional line between Commission- jurisdictional 
``transmission'' and state-jurisdictional ``local distribution.'' 
However, as discussed, we believe it is appropriate to set forth our 
views in this document on the demarcation of our respective authorities 
in this regard.

    \302\Stranded Cost NOPR at 32,876-77.
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    (a) Comments. Some commenters note that the Commission's authority 
to regulate sales for resale and transmission of electric energy in 
interstate commerce is premised on Congressional intent to fill the 
``Attleboro gap.'' These commenters note that Congress enacted the FPA 
to complement, not diminish, state authority. In light of this 
complementary jurisdictional posture, several commenters believe the 
Commission must explain how an unbundled retail sale is different from 
a bundled retail sale, which state commissions have regulated and will 
continue to regulate.
    Various non-investor-owned utility commenters, including the 
Illinois Commission and NASUCA, maintain that the Commission does not 
have jurisdiction over transmission service for an unbundled retail 
transaction. NARUC maintains that the issue is, at the very least, 
unsettled. Therefore, before addressing the question of whether and how 
the Commission has jurisdiction over retail stranded costs, these 
commenters argue that the Commission should first re-examine whether 
its jurisdictional premise is correct, or simply convenient. Investor-
owned utility commenters, on the other hand, generally concur with the 
conclusions in the NOPR regarding Commission jurisdiction.
    The Illinois Commission maintains that this Commission's 
jurisdiction extends only to the transmission of electricity between 
utility systems. It fails to see how ``unbundling'' of generation 
service from transmission/distribution services, in order to effectuate 
``retail wheeling,'' changes the basic intrastate nature of such 
services. The Illinois Commission states that if unbundled retail 
transmission is within the scope of federal jurisdiction, then one may 
question why the retail transmission portion of bundled services would 
not also be subject to Commission jurisdiction. It maintains that there 
is no legal or policy foundation supporting Commission jurisdiction 
over either bundled or unbundled retail electric services.
    The Illinois Commission further argues that the case law relied 
upon in the NOPR fails to establish that the Commission has retail 
wheeling ratemaking authority. The Illinois Commission contends that 
each of the cases cited by the Commission (as well as the FPA itself) 
all predate the issues of retail wheeling and retail stranded costs. 
Thus, according to the Illinois Commission, the courts have never 
contemplated retail wheeling or the effects that retail wheeling would 
have in terms of stranded costs for public utilities or transmission 
carriers. The Illinois Commission argues that, because section 201(a) 
of the FPA prohibits infringement of Federal regulation on matters 
subject to regulation by the states and because states currently 
regulate bundled retail transmission, the Commission is necessarily 
precluded by the FPA from regulating retail transmission.
    The Illinois Commission notes that under the Natural Gas Act, the 
states, and not the Commission, determine the rates, terms, and 
conditions of unbundled retail transportation services provided by 
local distribution companies. The Illinois Commission 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.
    Notwithstanding the jurisdictional debate, other state commission 
commenters such as the Ohio Commission contend that Commission 
assertion of jurisdiction may chill state willingness to undertake 
competitive reform at a retail level.<SUP>303 These 
[[Page 17711]] commenters further contend that Commission intervention 
in retail ratemaking will undermine a state's ability to address retail 
issues without being ``second guessed.'' Commenters view this 
regulatory uncertainty as an unwarranted and unnecessary result of the 
Commission's purported invalid assumption of jurisdiction.

    \303\The Ohio Commission proposes a model for drawing the line 
of demarcation between federal and state jurisdiction whereby the 
states would have rate jurisdiction over the wheeling-in portion of 
unbundled retail service (i.e., the point at which retail power 
enters the system of the last entity who redelivers the power to the 
end-use customer) and this Commission would retain jurisdiction over 
the wheeling-out and wheeling-through portions of a transaction. It 
contends that retention of jurisdiction over a portion of wheeling 
is necessary for states to be able to assess retail stranded costs.
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    (b) Commission Ruling. We reaffirm our legal conclusion that the 
Commission has jurisdiction over the rates, terms and conditions of 
unbundled interstate transmission services by public utilities to 
retail customers, and that we have the authority to address retail 
stranded costs through our jurisdiction over such services.
    However, we also believe the States have authority to address 
retail stranded costs through their jurisdiction over facilities used 
in local distribution.<SUP>304 It is therefore important to define what 
we believe to be the legal demarcation between ``transmission in 
interstate commerce'' and ``local distribution,'' as used in the FPA. 
In addition, this demarcation is important because of the consequences 
it will have for the public utility facilities that will be affected by 
the open access requirements being proposed. We set forth below our 
jurisdictional analysis, and technical factors, for determining what 
constitutes ``facilities used in local distribution.''

    \304\States also have the authority to address so-called 
``stranded benefits'' (e.g., environmental benefits associated with 
conservation, load management and other DSM programs) through their 
jurisdiction over local distribution.
---------------------------------------------------------------------------

    (13) Stranded Costs in the Context of Voluntary Restructuring. As 
we note in the Open Access NOPR, the functional unbundling of wholesale 
services that we are proposing does not require corporate unbundling 
(disposition of assets to a non-affiliate, or establishing a separate 
corporate affiliate to manage a utility's transmission assets) in any 
form. At the same time, we recognize that some utilities may ultimately 
choose such a course of action. The Commission is 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.

G. Transmission/Local Distribution

    In light of the proposals in both the Open Access NOPR and the 
Stranded Cost Supplemental NOPR, the Commission believes it is 
important to express its views on the distinction between Commission-
jurisdictional transmission in interstate commerce, and state-
jurisdictional local distribution, in the context of unbundled wheeling 
by public utilities.<SUP>305 The distinction is important for three 
reasons. First, facilities that can be used for wholesale transmission 
in interstate commerce would be subject to the Commission's open access 
requirements. It is important that public utilities and their customers 
have a good understanding of which facilities will be subject to such 
requirements. Such understanding will be crucial to appropriate 
planning as we enter into the competitive regime. It is also important 
that utilities not be able to shield themselves from the Commission's 
open access requirements by claiming that the facilities necessary to 
deliver power to a wholesale purchaser are non-jurisdictional ``local 
distribution'' facilities.

    \305\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.
---------------------------------------------------------------------------

    Second, as discussed supra, states may, through their jurisdiction 
over facilities used in local distribution, impose a surcharge on local 
distribution that will permit recovery of stranded costs resulting from 
retail wheeling or retail-turned-wholesale customers. Providing 
guidance on the demarcation between transmission and local distribution 
should assure States that they have the ability to assess stranded 
costs on the departing customers. This should result in more realistic 
economic evaluations by retail customers contemplating leaving via 
retail wheeling and/or municipalization.
    Third, as the structure of the electric industry continues to 
change dramatically, particularly with the wide availability of 
unbundled wholesale (and perhaps retail) services to deliver power and 
the potential for various forms of voluntary corporate unbundling, 
utilities need to know which regulator has jurisdiction over which 
facilities in order to meet State and Federal statutory filing 
requirements.
    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 
directly 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, 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>306

    \306\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 (FPA) Provisions
    The Commission's jurisdiction is set forth in section 201 of the 
FPA.<SUP>307 Section 201(b)(1) provides in pertinent part:

    \307\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>308

    \308\16 U.S.C. 824(b) (emphasis added).
---------------------------------------------------------------------------

    Section 201(c) provides that:

     [[Page 17712]] 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.<SUP>309

    \309\16 U.S.C. 824(c).
---------------------------------------------------------------------------

    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>310

    \310\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>311

    \311\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 Public Utilities Commission v. Attleboro Steam & E. Co. 
(273 U.S. 83 [(1927)]) [(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>312

    \312\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>313

    \313\Id. at 27.

    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>314

    \314\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>315

    \315\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>316

    \316\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>317

    \317\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>318 section 206(b) was redesignated as section 206(d).

    \318\Pub. L. 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>319

    \319\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>320

    \320\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>321

    \321\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. [[Page 17713]] 
---------------------------------------------------------------------------

    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 Power & Light Company v. Federal Power Commission 
(Jersey Central)<SUP>322 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>323 of the FPA so that the Commission's prior 
approval of the stock acquisition was necessary under section 203 of 
the FPA.

    \322\319 U.S. 61 (1943) (Jersey Central).
    <SUP>323Section 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>324

    \324\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>325 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>326 Therefore, the Court 
found that Jersey Central was a public utility within the meaning of 
section 201(e).<SUP>327 The

    \325\Id. at 66.
    <SUP>326Id. at 67 (citation omitted).
    <SUP>327Id. 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>328 In Jersey Central, the 
Court explained the rationale for federal jurisdiction as follows:

    \328\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>329

    \329\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.
    Connecticut Light & Power Company v. Federal Power Commission 
(CL&P),<SUP>330 which was decided two years after Jersey Central, is 
the leading case interpreting 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>331 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>332 and did not interconnect with any other company 
that operated out of state.<SUP>333 ``Its purchases and sales, its 
receipts and deliveries of power, [were] all within the 
state.''<SUP>334 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>335 The Commission based its jurisdiction on these few 
transactions.<SUP>336

    \330\324 U.S. 515 (1945) (CL&P).
    <SUP>331Id. at 517.
    <SUP>332Id. at 518.
    <SUP>333Id. at 521.
    <SUP>334Id. at 522.
    <SUP>335Id. at 519-21.
    <SUP>336Id.
    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>337

    \337\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>338 In analyzing the 
statute, the Court stated:

    \338\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>339]

    \339\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>340

    \340\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 [[Page 17714]] distribution,<SUP>341 they were 
exempt from federal jurisdiction. <SUP>342 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:

    \341\It appears that while the Company received power (at one 
location) at 66 kV, it primarily owned facilities at 13.8 kV and 
below.
    <SUP>342324 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>343

    \343\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>344

    \344\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>345 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>346

    \345\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.
    <SUP>346Id. 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>347 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>348 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>349

    \347\197 F.2d 472 (7th Cir. 1952), cert. denied, 345 U.S. 934 
(1953) (Wisconsin-Michigan).
    <SUP>348Id. at 474.
    <SUP>349Id. (``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>350]

    \350\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 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>351 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>352

    \351\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).
    <SUP>352See 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 does the local 
distribution facilities first become operative.''<SUP>353 The court 
further stated that:

    \353\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>354]

    \354\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 [[Page 17715]] 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>355 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>356 
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>357 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>358 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.

    \355\376 U.S. 205 (1964) (Colton).
    <SUP>356The 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.
    <SUP>357Id. at 208, 209 & n.5.
    <SUP>358Id. 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>359 
characterized Congressional intent in the FPA:

    \359\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>360]

    \360\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>361]

    \361\Id. at 215-216.

The Court held that ``[t]here is no such exception covering the Edison-
Colton sale.'' <SUP>362

    \362\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>363]

    \363\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>364

    \364\Id. at 210 n.6.
---------------------------------------------------------------------------

    In Duke Power Company v. Federal Power Commission (Duke), <SUP>365 
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>366 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.

    \365\401 F.2d 930 (D.C. Cir. 1968) (Duke).
    <SUP>366Duke 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.[<SUP>367]

    \367\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.[<SUP>368]

    \368\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 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.<SUP>369

    \369\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 
[[Page 17716]] interstate in character, should be handled locally and 
should receive the consideration of local [officials] familiar with the 
local conditions in the communities involved.''<SUP>370

    \370\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 <SUP>371 
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.<SUP>372 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.

    \371\404 U.S. 453, reh'g denied, 405 U.S. 948 (1972) (Florida 
Power & Light).
    <SUP>372404 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.).<SUP>373 In turn, Florida Power 
Corp. connected with Georgia Power Company (Georgia Power) at a 
``bus''<SUP>374 south of the Georgia-Florida border.<SUP>375 Florida 
Power Corp. regularly exchanged power with Georgia Power.<SUP>376 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.<SUP>377 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.''<SUP>378 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 * * 
*.''<SUP>379

    \373\Id. at 456.
    <SUP>374A ``bus'' is a connector or group of connectors that 
serves as a common connection for two or more circuits.
    <SUP>375404 U.S. at 457.
    <SUP>376Id.
    <SUP>377Id. at 457 & n.8.
    <SUP>378Id. at 461. (emphasis omitted).
    <SUP>379Id. 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''<SUP>380 under section 201 of the FPA.<SUP>381 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.'').

    \380\See Section 201(d), 16 U.S.C. Sec. 824(d) (1988).
    <SUP>381Public 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.<SUP>382

    \382\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.<SUP>383

    \383\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>384]

    \384\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 [[Page 17717]] 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 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.''\385\

    \385\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.\386\ 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.''\387\ The court disagreed:

    \386\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.
    \387\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.\388\

    \388\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.\389\

    \389\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 * * *.''\390\ To reach the interstate pipeline, the 
industrials constructed a nine-mile pipeline. Together, the facilities 
bypassed the local distribution company.\391\

    \390\955 F.2d 1412, 1414 (10th Cir. 1992).
    \391\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.\392\

    \392\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.''\393\ 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.

    \393\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.\394\ 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.

    \394\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), this does 
not appear to be [[Page 17718]] 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).
    There are several indicators that we propose to evaluate in 
determining whether particular facilities are transmission or local 
distribution in the case of vertically integrated transmission and 
distribution utilities.\395\

    \395\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.\396\

    \396\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 we will apply a 
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 we will apply a combination 
functional-technical test that will take into account technical 
characteristics of the facilities used for the wheeling. In most, if 
not all, circumstances in this situation, we expect there to be local 
distribution facilities. To assist states in dealing with stranded 
costs resulting from retail wheeling, we will make every attempt to 
expedite a decision if a state requests clarification concerning 
whether certain facilities are local distribution facilities.
    By clarifying the tests the Commission will apply to determine if 
facilities used to deliver unbundled electric energy are FERC-
jurisdictional or state-jurisdictional, we believe we have facilitated 
the ability of this Commission and, importantly, state commissions to 
assess legitimate stranded costs to customers who leave their existing 
suppliers' systems. The application of these tests means that states 
will be able to address stranded costs by imposing an exit fee on 
departing retail customers, or including an adder in the retail 
customers' local distribution rates.

H. Implementation

    Because the proposed requirements in the Open Access NOPR are aimed 
at eliminating undue discrimination in the provision of transmission 
services in interstate commerce, and at achieving competitive bulk 
power markets for the benefit of electricity consumers, our preliminary 
view is that open access tariffs should be in place as soon as 
possible. Very simply, we would not want to delay a program which we 
expect to produce significant ratepayer benefits over time. We also 
would want to provide procedures and guidance for stranded cost 
recovery as soon as possible in order to complete the transition from a 
tightly-controlled cost-of-service regulatory regime to the competitive 
regime we expect in the very near future.
    To those ends, we propose implementation procedures that the 
Commission currently believes will be appropriate for non-
discriminatory open access transmission and stranded (transition) cost 
recovery. These proposed implementation procedures attempt to balance 
the goals of: Placing good open access tariffs into effect as soon as 
possible; supporting the transmission pricing flexibility permitted by 
our Transmission Pricing Policy Statement; and providing for 
implementation that is administratively feasible for utilities, 
customers, and the Commission.
    With respect to open access, we currently estimate that about 137 
public utilities would be required to have on file non-discriminatory 
open access tariffs if the Commission adopts a final rule.
    If the Commission were to employ traditional filing procedures in 
implementing an open access regime, we could attempt to streamline the 
process by, for example, relying, where appropriate, on paper hearing 
procedures and technical conferences and summarily disposing of the 
maximum number of issues possible. Nevertheless, we would still expect 
delays (and attendant uncertainty) measured in years.\397\ As a result, 
we propose a two-stage procedure to put in place without delay basic 
open access tariffs. We believe this procedure will ensure non-
discriminatory open access transmission services that would: (1) 
Satisfy most utilities and customers; and (2) provide a framework for 
utilities to subsequently submit novel proposals that they believe to 
be better tailored to their individual circumstances. We request 
comments on all aspects of the proposed procedure, including the 
proposed generic tariffs discussed infra.

    \397\Such uncertainty could adversely impact on utilities' cost 
of capital. Moreover, case-by-case implementation would result in a 
patchwork of open access around the country until the process is 
complete. This patchwork of conflicting requirements could inhibit 
the timely transition to competitive markets--a result directly at 
odds with the objectives of this proceeding.
---------------------------------------------------------------------------

1. Two-Stage Implementation Process

Stage One

    The Commission proposes to put into effect (not subject to refund) 
for every public utility that owns and/or controls transmission 
facilities, pursuant to section 206 of the FPA, generic tariffs 
providing network transmission services, firm and non-firm point-to-
point transmission services, and ancillary services necessary to effect 
network and point-to-point service.\398\ The Commission proposes to 
specify the rates, terms, and conditions in the final rule and to put 
all such tariffs into effect simultaneously on a date certain--12:00 
midnight 60 days after the effective date of the final rule.

    \398\As noted infra, we will address in a separate document the 
application of the proposed rule to public utilities who have open 
access proceedings pending before the Commission.
---------------------------------------------------------------------------

    The proposed network and point-to-point tariffs contained in 
Appendices B and C establish the minimum terms and conditions which we 
believe are necessary to eliminate undue discrimination in the 
transmission of electric energy in interstate commerce. We propose to 
place these terms and conditions into effect for each affected public 
utility.
    Although the proposed generic tariffs contain the minimum terms and 
conditions of service that is not unduly discriminatory, they do not 
contain specific rates. However, section 206(a) of the FPA requires the 
Commission to fix by order the just and reasonable rate.\399\ We 
therefore propose to establish and set forth in the final rule, for 
each affected public utility, just and reasonable rates for network 
service, point-to-point service, and six identified ancillary services. 
We propose to [[Page 17719]] establish such rates using the most 
current Form No. 1 data available for each public utility, and to 
incorporate them into the generic tariffs for each affected public 
utility.

    \399\Electrical District No. 1, et al. v. FERC, 774 F.2d 490 
(D.C. Cir. 1985).
---------------------------------------------------------------------------

    While the rates we will calculate using Form No. 1 data will be 
postage stamp rates, we wish to emphasize that utilities are free in 
Stage Two to propose immediately and support non-traditional 
conforming, as well as non-conforming, transmission pricing proposals 
consistent with the Commission's Transmission Pricing Policy Statement. 
The proposed calculation of these rates is discussed in detail infra.
    Customers will be able to rely on existing contracts for 
transmission service until such contracts expire or are otherwise 
terminated. While customers will be able to use the generic tariffs and 
any revised tariffs established in Stage Two for new or additional 
services, we do not propose to allow customers to seek termination of 
their existing transmission arrangements in order to use the generic or 
subsequently revised tariffs, unless such filings are contractually 
authorized or shown to be in the public interest. Of course, to the 
extent that such filings are contractually authorized, the Commission 
must still determine whether the termination of such existing 
transmission arrangements is just and reasonable, based upon the 
circumstances presented.
    The above procedures would apply to individual public utility open 
access tariffs. However, many public utilities transact under 
jurisdictional power pooling agreements. As discussed herein, power 
pools would have to comply with the non-discrimination requirements of 
the Open Access NOPR by making power pool transmission services 
available to all wholesale transmission customers and offering services 
at rates, terms, and conditions that are not unduly discriminatory. 
However, power pools raise complex issues and the Commission cannot at 
this time develop compliance tariffs for power pools. Therefore, we 
seek comments on how to implement the NOPR for power pools. After we 
have received comments on this matter, and before a final rule is 
adopted, we intend to hold technical conferences with power pools to 
discuss implementation issues. After holding these technical 
conferences, and taking into account the comments received in the Open 
Access NOPR proceeding as well as in our pending Notice of Inquiry on 
Alternative Power Pooling Institutions, we will issue a supplemental 
order directing compliance for power pools.

Stage Two

    The Commission proposes that Stage Two begin 61 days after the date 
the final rule becomes effective. On and after that date, public 
utilities may propose changes to the rates, terms, and conditions in 
the generic tariffs pursuant to section 205 of the FPA and Part 35 of 
the regulations. In addition, customers and others may file complaints 
pursuant to section 206 of the FPA seeking changes in the rates, terms, 
and conditions in the generic tariffs. We note, however, that Stage Two 
tariffs must contain at least the non-price tariff terms and conditions 
contained in the pro forma tariffs. Moreover, customers (or potential 
customers) dissatisfied with the generic tariffs may file section 211 
applications at any time (i.e., before Stage Two).
    We are hopeful that the generic tariffs will initially be 
acceptable to large numbers of utilities and their customers. Because 
we expect our Stage One tariffs to be satisfactory for the immediate 
needs of many transmission providers and customers, we would expect 
Stage Two proposals to be staggered somewhat, permitting us to process 
and reach final decisions more quickly on subsequent proposals to 
revise the generic tariffs.
    We propose to require any utility seeking to modify the generic 
tariffs in Stage Two to file, in addition to the other requirements 
specified in the regulations, an original and 14 copies of the revised 
tariffs showing any changes proposed by means of highlighting and 
striking out. In addition, we propose that the utilities also file two 
copies of such changes on diskette in ASCII format.
2. Calculations of Stage One Rates
    Because most utilities currently use embedded cost pricing for the 
transmission component of their own power sales and purchases, and 
because the Commission's Transmission Pricing Policy Statement requires 
comparability between transmission rates and the transmission pricing 
component of those power sales and purchases, the Commission proposes 
to establish rates for the generic tariffs based on embedded cost 
principles. However, these tariffs will include a provision that allows 
the transmission provider to file unilateral changes in all rates, 
terms, and conditions any time after the effective date of the generic 
tariffs (Stage Two filings). However, as we noted above, the minimally 
acceptable tariff terms and conditions in Stage Two will be the terms 
and conditions established in Stage One.
    We emphasize that utilities and customers have discretion under the 
Commission's Transmission Pricing Policy Statement to pursue other 
types of rate treatments, and that they may file a proposal any time 
after the generic tariffs become effective. For example, Stage Two 
filings could include:
    <bullet> A filing by the public utility under section 205 amending 
the generic tariff in a limited respect, such as a change in the loss 
factor, a change in the embedded cost unit charge, implementing an 
option to charge an incremental cost rate, including opportunity cost, 
when capacity is constrained, or the addition of another ancillary 
service.
    <bullet> A filing by the public utility under section 205 proposing 
an entirely new rate method such as a zone or distance based 
transmission rate. The generic tariff would constitute a conforming 
open access transmission tariff, but revised tariff filings could also 
include nonconforming proposals.
    <bullet> A complaint by a customer (or potential customer) under 
section 206 seeking limited changes to the generic tariff, such as a 
change in the loss factor, a change in the embedded cost unit charge, 
or the addition of another ancillary service.
    <bullet> A complaint by a customer (or potential customer) under 
section 206 proposing an entirely new rate method.
     We expect that, for many transmission providers and customers, the 
Stage One tariffs will satisfy their immediate needs. For example, a 
customer might believe that it could demonstrate in a section 206 
proceeding that a lower rate is appropriate, but decide the monetary 
impact is not sufficient to justify the filing of a complaint because 
its current needs are small or because the expected rate reduction is 
slight. In this situation, the customer may delay raising objections to 
the Stage One tariffs until the company files its next general rate 
case. Also, a company might believe that it could demonstrate that a 
higher rate is reasonable, but decide that its resources are best spent 
comprehensively designing a Stage Two non-traditional tariff, such as, 
a distance sensitive rate, a non-conforming proposal, or a spin-off of 
transmission assets into a separate company. Similarly, companies 
negotiating regional transmission tariffs may decide to devote their 
resources to that project rather than fine tuning their company 
specific rates.
    If we had not proposed this two-stage process and simply directed 
the filing of company specific tariffs, utilities and customers would 
have been forced to proceed on an inflexible schedule. In 
[[Page 17720]] addition, parties may have felt pressured to file 
proposals prematurely out of concern that a failure to do so would 
prejudice their ability to initiate them later. We believe that 
industry participants are better served by a process that, in addition 
to avoiding the delay inherent in a series of separate section 206 
compliance filings, allows affected parties to raise these complex 
issues when it best meets their needs and after taking whatever time is 
necessary to evaluate non-traditional alternatives.
    The Commission proposes to establish the rates for Stage One 
tariffs as follows:

Derivation of the Embedded Cost Transmission Charge for Point-to-Point 
Service

    To establish firm point-to-point transmission charges, the 
Commission proposes to use the fixed charge methodology that it uses to 
evaluate rate schedule filings. This methodology is available to the 
public on the Commission's Electric Power Data Bulletin Board and has 
been referenced in various proceedings before the Commission.<SUP>400
    Form No. 1 data are used to develop the cost relationship between 
fixed transmission costs and transmission plant investment (a fixed 
charge rate). The unit charge is calculated by: (1) Dividing plant 
investment by capability, using the annual system peak as a proxy for 
capability;<SUP>401 and (2) multiplying the result by the fixed charge 
rate. All data would be taken from the Form No. 1 except the return on 
equity.
    For the equity return, the Commission proposes to use an industry-
wide return calculated using the Commission's standard discounted cash 
flow (DCF) analysis of company specific dividend yields and an industry 
average constant growth rate.<SUP>402 As an alternative, the Commission 
could use its DCF method to compute company specific equity returns. 
However, this is not likely to change materially the Stage One rates 
(e.g., a 1% change in the equity return would change the monthly charge 
by about $.08/kW/month, equivalent to an hourly charge of 0.1 mill/
kWh). We invite comments on this issue.
    We also propose an alternative rate treatment and we ask for 
comment on which we should adopt for all affected public utilities. The 
alternative is a variation of our fixed charge rate method. Under our 
alternative proposal, the Commission would multiply an industry-wide 
transmission fixed charge rate by the company-specific investment cost 
per kW from the Form No. 1.<SUP>403 This would simplify the process. In 
our experience, differences in unit charges among companies are due 
primarily to differences in investment cost per kW of capability and 
not the fixed charge rate. We note that we adopted a similar approach 
in developing cost-based ceiling rates for the WSPP, although we 
developed a single composite rate for WSPP services.
    The following illustrates the computation of a specific Stage One 
point-to-point transmission charge for three utilities using the 
alternative proposal and 1993 Form No. 1 data, Dayton Power & Light 
Company (Dayton), Louisville Gas & Electric Company (LGE), and 
Minnesota Power & Light Company (MPL):

                                                                        
                       (2)Transmission                                  
     (1) Company           plant in      (3)System peak     (4)Annual   
                           service                            charge    
                                 (000)               MW  (2)/(3) x 17.5%
------------------------------------------------------------------------
(1) Dayton...........         $247,186            2,765        $15.64/kW
(2) LGE..............          173,836            2,239         13.59/kW
(3) MPL..............          162,656            1,252         22.74/kW

    Under either alternative, the final rule would establish specific 
unit charges. Charges for shorter term services would be derived from 
the annual charge using standard Commission methods:

Monthly Charge = Annual Charge/12
Weekly Charge = Annual Charge/52
Daily Charge = Weekly Charge/5
 Hourly Charge = Daily Charge/16

Revenues for daily and hourly service would be capped at the equivalent 
weekly and daily rates pursuant to our standard requirements.<SUP>404
                              ___________


400See, e.g., Western Systems Power Pool (WSPP), 55 FERC 
para.61,099 (1991); Jersey Central Power & Light Company, 38 FERC 
para.61,275 (1987); and UtiliCorp United Inc., 70 FERC para.61,149 
(1995).
<SUP>401The Commission consistently requires this method for non-
customer specific rates such as this. See, e.g., American Electric 
Power Service Company, 67 FERC para.61,168 (1994); Kentucky 
Utilities Company, 67 FERC para.61,189 (1994).
<SUP>402An industry-wide return on equity calculated using this 
method would currently yield a return of about 11%.
<SUP>403Based on analyses prepared by the Commission's staff to 
support acceptance of filings tendered by utilities during the last 
two years, a representative transmission fixed charge rate is 
17.5%. The Form No. 1 data used to compute a company specific 
investment cost per kW of load is found at Page 207, line 69, 
column g (end of year plant transmission plant in service) and Page 
401, column D (system peak load) of the Form No. 1.
<SUP>404See Appalachian Power Company, et al., 39 FERC para.61,296 
at 61,965 (1987); WSPP, supra, 55 FERC at 61,321.
    We propose to establish ceiling rates for non-firm service equal to 
the firm rates, consistent with industry practice. As a practical 
matter, there is generally a charge for non-firm service only in the 
hours when energy is scheduled and, therefore, non-firm service is 
provided at a discount from firm service, which is generally subject to 
a charge based on reservations without regard to actual usage. As we 
have emphasized in the past, we expect that a rate for firm service 
will be higher than a rate for another service that differs only in the 
degree of firmness.<SUP>405 We also expect that such discounts will be 
offered on a non-discriminatory basis to all customers and that 
customers will have sufficient information about the availability of 
discounts (e.g., through an information network).

    \405\Commonwealth Edison Company, 64 FERC para.61,253 (1993).
---------------------------------------------------------------------------

Derivation of Embedded Cost Charge for Network Service

    To establish network transmission charges, the Commission proposes 
to adopt the load ratio method we approved in Florida Municipal Power 
Agency.<SUP>406 Under this approach, the company's annual transmission 
costs (the product of column (2) in the table above for point-to-point 
service and the same fixed charge rate used to develop the point-to-
point rates) are multiplied by a load ratio percentage. The load ratio 
reflects the average of the 12 monthly customer coincident peaks 
divided by the average of the 12 monthly total system peaks. Total 
monthly system peaks for this calculation would reflect all firm uses 
of the transmission system, including the transmission owners' own long 
term [[Page 17721]] firm and unit power sales. We shall specify the 
annual revenue requirement in the generic tariff and direct the 
transmission provider to insert the load ratio computation into the 
service agreement when filed after a request for service is accepted by 
the utility.

    \406\See supra, 67 FERC at 61,481.
---------------------------------------------------------------------------

Derivation of the Charges for Ancillary Services

Loss Compensation

    The Commission proposes to establish a loss factor of 3% and a 
charge for energy losses equal to 110% of seller's incremental cost. A 
3% loss factor is representative of those in transmission agreements on 
file and a loss compensation charge based on the seller's incremental 
cost is also common.

Energy Imbalances

    The Commission proposes to establish an hourly deviation band of +/
- 1.5% with a minimum of 1 MW per hour and imbalances within this band 
would be returned in kind or subject to a charge equal to seller's 
incremental cost (or a payment equal to decremental cost if the public 
utility transmission provider receives too much energy and must 
compensate the transmission customer). Energy imbalances outside this 
band would be subject to a charge of 100 mills/kWh, the standard 
industry rate for emergency service. We propose the emergency service 
charge for this purpose because, as with emergency service, the rate 
should provide an incentive to minimize energy imbalances. We seek 
comment on the size of the deviation band and size of the imbalance 
charge.

Scheduling & Dispatching Charges

    The Commission's fixed charge rate methodology which will be used 
to establish the transmission charge includes Account No. 566, where 
the costs of transmission related scheduling and dispatching are 
booked. Accordingly, the generic tariffs would include no separate 
charge for scheduling and dispatching. This should be adequate for most 
transmission services because most customers are likely to require this 
scheduling and dispatching service. If a customer does not require this 
service, it may propose a different rate treatment by filing a 
complaint at Stage Two.

Other Charges

    The other ancillary services--Load Following, System Protection, 
and Reactive Power--have a common attribute. They all involve the cost 
incurred by the transmission provider as a result of using generation 
facilities to support the transmission service. In the past, some or 
all of these services were often provided at a rate reflecting embedded 
transmission costs, i.e., without a separate charge reflecting the cost 
of generation facilities. However, the Commission has allowed a 1 mill/
kWh charge for difficult to quantify costs that served to compensate 
transmission providers for costs like these. We propose, for purposes 
of the Stage One tariffs, to maintain a ceiling of 1 mill/kWh as the 
charge for these three ancillary services on a combined basis. We would 
expect that the parties would negotiate charges below this ceiling if 
the customer can provide some or all of these ancillary services and 
that this would be filed as a change in Stage Two. We emphasize that, 
if a utility believes that a 1 mill/kWh charge is unsatisfactory, it 
may file to revise the charge under section 205 in Stage Two. 
Similarly, if a customer finds a 1 mill/kWh charge unsatisfactory, it 
may file a complaint in Stage Two.
Questions

    We invite comments on which of the methodologies we should adopt. 
For example, we are interested in commenters' preference for the first 
alternative, which uses company specific Form No. 1 data for all 
inputs, or the second alternative, which uses company specific Form No. 
1 data only for investment and load. With respect to the first 
alternative, we seek comments on our proposal to use an industry-wide 
equity return for each affected public utility and, with respect to the 
second alternative, we seek comments on our proposed uniform 17.5% 
transmission fixed charge rate. We also seek comments as to whether a 
more specific definition of the load ratio should be adopted, and 
whether this ratio can be used fairly in all situations. We also invite 
comments on our proposals for ancillary service charges. All comments 
should take into account our intention to immediately put in place 
generic tariffs so that there will be no delay in the availability of 
nondiscriminatory open access transmission services.
3. Ongoing Proceedings
    There are currently a number of ongoing proceedings in which the 
Commission is investigating utilities' open access tariff filings. 
Concurrently with this order, the Commission is issuing a separate 
order concerning those cases.

IV. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA)<SUP>407 requires that 
rulemakings contain either a description and analysis of the effect the 
proposed rule will have on small entities or a certification that the 
rule will not have a substantial economic effect on a substantial 
number of small entities. Because the entities that would be required 
to comply with the proposed rule are public utilities and transmitting 
utilities that do not fall within the RFA's definition of small 
entities,<SUP>408 the Commission certifies that this rule will not have 
a ``significant economic impact on a substantial number of small 
entities.''

    \407\5 U.S.C. 601-612.
    <SUP>4085 U.S.C. 601(3) (citing section 3 of the Small Business 
Act, 15 U.S.C. 632). Section 3 of the Small Business Act defines a 
``small-business concern'' as a business which is independently 
owned and operated and which is not dominant in its field of 
operation. 15 U.S.C. 632(a).
---------------------------------------------------------------------------

V. Environmental Statement

     The Commission concludes that promulgating the proposed rule would 
not represent a major federal action having a significant adverse 
impact on the human environment under the Commission's regulations 
implementing the National Environmental Policy Act.<SUP>409 The 
proposed rule falls 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>410 Consequently, 
neither an environmental assessment nor an environmental impact 
statement is required.

    \409\18 CFR Part 380.
    <SUP>41018 CFR 380.4(a)(15).
---------------------------------------------------------------------------

VI. Information Collection Statement

    The Office of Management and Budget's (OMB) regulations<SUP>411 
require that OMB approve certain information and recordkeeping 
requirements imposed by an agency.

    \411\5 CFR 1320.13.
---------------------------------------------------------------------------

    The information collection requirements in the proposed regulations 
are contained in FERC-516, ``Electric Rate Filings'' (OMB approval No. 
1902-0096). The Commission uses the data collected in this information 
collection to carry out its responsibilities under Part II of the FPA. 
The Commission's Office of Electric Power Regulation uses the data to 
review electric rate filings. The data enable the Commission to examine 
and evaluate the utility's costs and rate of return.
    The Commission is submitting notification of this proposed rule to 
OMB. Interested persons may obtain [[Page 17722]] information on the 
reporting requirements by contacting the Federal Energy Regulatory 
Commission, 941 North Capitol Street, NE., Washington, DC 20426 
[Attention: Michael Miller, Information Services Division, (202) 208-
1415]. Comments on the requirements of the proposed rule can also be 
sent to the Office of Information and Regulatory Affairs of OMB 
[Attention: Desk Officer for Federal Energy Regulatory Commission].
VII. Public Comment Procedures

    The Commission invites comments on the proposed rule from 
interested persons. An original and 14 copies of written comments on 
the proposed rule must be filed with the Commission no later than 
August 7, 1995.
    The Commission will also permit interested persons to submit reply 
comments in response to the initial comments filed in this proceeding. 
Reply comments should be submitted no later than October 4, 1995.
    In addition, commenters are requested to submit a copy of their 
comments on a 3\1/2\ inch diskette formatted for MS-DOS based 
computers. In light of our ability to translate MS-DOS based materials, 
the text need only be submitted in the format and version that it was 
generated (i.e., MS Word, WordPerfect, ASCII, etc.). It is not 
necessary to reformat word processor generated text to ASCII. For 
Macintosh users, it would be helpful to save the documents in Macintosh 
word processor format and then write them to files on a diskette 
formatted for MS-DOS machines. All comments should be submitted to the 
Office of the Secretary, Federal Energy Regulatory Commission, 825 
North Capitol Street, NE., Washington, DC 20426, and should refer to 
Docket Nos. RM95-8-000 and RM94-7-001.
    All written comments will be placed in the Commission's public 
files and will be available for inspection in the Commission's public 
reference room at 941 North Capitol Street, NE., Washington, DC, 20426, 
during regular business hours.

List of Subjects in 18 CFR Part 35

    Electric power rates, Electric utilities, Reporting and 
recordkeeping requirements.

    By direction of the Commission.

    Commissioner Massey concurred in part and dissented in part with 
a separate statement attached.
Lois D. Cashell,
 Secretary.
    In consideration of the foregoing, the Commission proposes to amend 
part 35, 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 [INSERT DATE 90 DAYS AFTER THE FINAL RULE IS 
PUBLISHED IN THE FEDERAL REGISTER]; or
    (ii) If unexecuted, filed with the Commission prior to [INSERT DATE 
90 DAYS AFTER THE FINAL RULE IS PUBLISHED IN THE FEDERAL REGISTER].
    (2) Any power sales contract executed on or after [INSERT DATE 90 
DAYS AFTER THE FINAL RULE IS PUBLISHED IN THE FEDERAL REGISTER] 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 
cancellation or termination of such contract within 30 days after such 
cancellation or 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: 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 contract means any contract executed after July 11, 1994, 
or [[Page 17723]] extended or renegotiated to be effective after July 
11, 1994.
    (8) Existing contract means any 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) 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 through 206 of the FPA. The public utility may not 
seek recovery of such costs through any transmission rate for section 
205 or 211 transmission services.
    (iii) 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.
    (iv) 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 existing contract seeks a stranded cost 
amendment pursuant to a section 205 or section 206 filing 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 section 205 rates for electric 
energy.
    (B) If the existing contract is not amended to permit recovery of 
stranded costs as described in paragraph (c)(1)(iv)(A) of this section, 
the public utility may file a proposal, prior to the expiration of the 
contract, to recover stranded costs through section 205 or section 211 
through 212 rates for wholesale transmission services to the customer.
    (v) If wholesale stranded costs are associated with an existing 
wholesale requirements contract, if the seller under such contract is a 
transmitting 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 
section 211 through 212 transmission rates.
    (vi) 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 
section 205 or section 211 through 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)(iv) through (vi) 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) it has taken and will take reasonable measures to mitigate 
stranded costs.
    (3) Rebuttable Presumption. If a public utility or transmitting 
utility seeks recovery of wholesale stranded costs associated with an 
existing contract, as permitted in paragraph (c)(1) of this section, 
and the existing 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.

(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;
    (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; and
    (iii) it has taken and will take reasonable measures to mitigate 
stranded costs.


Sec. 35.27  Power sales at market-based rates.

    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 [INSERT DATE 30 DAYS AFTER THE FINAL RULE 
IS PUBLISHED IN THE FEDERAL REGISTER].


Sec. 35.28  Non-discriminatory open access transmission tariffs.

    (a) Every public utility owning and/or controlling facilities used 
for the transmission of electric energy in interstate commerce must 
have on file with the Commission no later than [INSERT DATE 90 DAYS 
AFTER THE FINAL RULE IS PUBLISHED IN THE FEDERAL REGISTER] tariffs of 
generally applicability for transmission services, including ancillary 
services, over these facilities on both a point-to-point basis and 
network basis consistent with the requirements of Order No. ______ 
(Final Order on Open Access and Stranded Costs).
    (b) Every public utility owning and/or controlling facilities used 
for the transmission of electric energy in interstate commerce, but not 
in existence on [INSERT DATE THE FINAL RULE IS PUBLISHED IN THE FEDERAL 
REGISTER], must file tariffs of generally applicability for 
transmission services, including ancillary services, over these 
facilities on both a point-to-point basis and network basis consistent 
with the requirements of Order No. ______ (Final Rule on Open Access 
and Stranded Costs) no later than the date any agreement under which 
such public utility would engage in a sale of electric 
[[Page 17724]] energy at wholesale in interstate commerce or the 
transmission of electric energy in interstate commerce is accepted for 
filing by the Commission.
    (c) Any public utility that owns and/or controls 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, must take transmission service for such 
sales and/or purchases under the tariffs filed pursuant to paragraph 
(a) or (b) of this section.

    Note: Appendix D and Commissioner Massey's statement will not 
appear in the Code of Federal Regulations.

Appendix D--Docket No. RM94-7-000, Recovery of Stranded Costs by Public 
Utilities and Transmitting Utilities List of Commenters

1. Ad Hoc Coalition on Environmental and Consumer Protection (Ad Hoc 
Coalition), consisting of Environmental Action Foundation, Citizen 
Action, Consumer Federation of America, Greenpeace, Toward Utility 
Rate Normalization, Public Citizen, Sierra Club, Nuclear Information 
& Resource Service, Economic Opportunity Research Institute, and 
U.S. Public Interest Research Group
2. Alabama Public Service Commission
3. Allegheny Electric Cooperative, Inc.
4. Allegheny Power Service Corporation (Allegheny Power)
5. American Forest & Paper Association (American Forest)
6. American Public Power Association (APPA)
7. American Society of Utility Investors
8. Arizona Public Service Company
9. Arkansas Public Service Commission
10. Atlantic City Electric Company
11. Blue Ridge Power Agency, Northeast Texas Electric Cooperative, 
Sam Rayburn G&T Electric Cooperative and Tex-La Electric Cooperative 
(Blue Ridge)
12. California Public Utilities Commission
13. Centerior Energy Corporation
14. Central Maine Power Company
15. Central Vermont Public Service Corporation
16. Cities of Anaheim, Azusa, Banning, Colton and Riverside, 
California
17. City of Las Cruces, New Mexico
18. Coalition For Economic Competition, consisting of Central Hudson 
Gas & Electric Corporation, Consolidated Edison Company of New York, 
Long Island Lighting Company, New York State Electric & Gas 
Corporation, Niagara Mohawk Power Corporation, and Rochester Gas & 
Electric Company
19. Coalition of California Utility Employees
20. Colorado Association of Municipal Utilities
21. Colorado Office of Consumer Counsel
22. Colorado Public Utilities Commission
23. Commonwealth Edison Company (Commonwealth Edison)
24. Competitive Electric Market Working Group (Competitive Working 
Group), consisting of Electric Clearinghouse, Inc., Enron Power 
Marketing, Inc., and Destec Power Services, Inc.
25. Conservation Law Foundation
26. Consumer-Owned Utilities in Maine, 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., Union River Electric Cooperative, Inc., 
and Van Buren Light & Power District
27. Consumers Power Company
28. Dairyland Power Cooperative
29. Department of Water and Power of the City of Los Angeles
30. Detroit Edison Company (Detroit Edison)
31. Direct Action For Rights and Equality
32. District of Columbia Public Service Commission
33. Duke Power Company
34. Duquesne Light Company
35. Edison Electric Institute (EEI)
36. Electric Consumers' Alliance
37. Electric Generation Association
38. Electricity Consumers Resource Council, the American Iron and 
Steel Institute and the Chemical Manufacturers Association 
(Industrial Consumers)
39. El Paso Electric Company
40. Enron Power Marketing, Inc. (Enron)
41. Entergy Services, Inc. (Entergy)
42. Environmental Action Foundation (Environmental Action)
43. Environmental Law and Policy Center of the Midwest
44. Florida Municipal Power Agency, Michigan Municipal Cooperative 
Group and Wolverine Power Supply Cooperative (Florida and Michigan 
Municipals)
45. Florida Power Corporation
46. Florida Public Service Commission (Florida Commission)
47. Fuel Managers Association
48. Houston Lighting & Power Company (Houston Lighting & Power)
49. Idaho Public Utilities Commission
50. Illinois Commerce Commission (Illinois Commission)
51. Illinois Power Company
52. Indiana Office of Utility Consumer Counselor
53. Indiana Utility Regulatory Commission (Indiana Commission)
54. Iowa Utilities Board
55. Irrigation and Electrical Districts' Association of Arizona
56. Land and Water Fund of the Rockies
57. Large Public Power Council
58. Long Island Lighting Company (Long Island Lighting)
59. Louisiana Energy and Power Authority
60. Maryland Public Service Commission
61. Massachusetts Department of Public Utilities
62. Metropolitan Edison Company, Pennsylvania Electric Company and 
Jersey Central Power & Light Company
63. Michigan Public Service Commission Staff
64. Mid-Atlantic Energy Project
65. Municipal Resale Service Customers of Ohio Power Company
66. National Association of Regulatory Utility Commissioners (NARUC)
67. National Association of State Utility Consumer Advocates 
(NASUCA)
68. National Black Caucus of State Legislators
69. National Independent Energy Producers (NIEP)
70. National Rural Electric Cooperative Association
71. New England Power Company
72. New York Mercantile Exchange
73. New York State Electric & Gas Corporation
74. New York State Public Service Commission (New York Commission)
75. North Carolina Electric Membership Corporation
76. North Dakota Public Service Commission
77. Northern States Power Company
78. Nuclear Energy Institute
79. Oglethorpe Power Corporation
80. Ohio Office of the Consumers' Counsel
81. Ohio Public Utilities Commission (Ohio Commission)
82. Older Women's League
83. Omaha Public Power District
84. Pace Energy Project
85. Pacific Gas and Electric Company
86. Pacific Gas and Electric Company and Natural Resources Defense 
Council
87. PECO Energy Company
88. Pennsylvania and Massachusetts Municipals
89. Pennsylvania Power & Light Company
90. Pennsylvania Public Utility Commission (Pennsylvania Commission)
91. Public Power Council
92. Public Service Company of New Mexico
93. Public Service Electric and Gas Company (Public Service 
Electric)
94. Rhode Island Division of Public Utilities and Carriers and 
Jeffrey B. Pine, Attorney General of the State of Rhode Island
95. Rural Utilities Service
96. Sacramento Municipal Utility District
97. San Diego Gas & Electric Company
98. Sierra Pacific Power Company
99. South Carolina Electric & Gas Company
100. Southern California Edison Company
101. Southern Company Services, Inc.
102. Stranded Cost Order Opponent Parties, consisting of the 
Delaware Municipal Electric Corporation, Village of Freeport, New 
York, City of Jamestown, New York, Town of Massena, New York, 
Modesto Irrigation District, M-S-R Public Power Agency, City of 
Santa Clara, California, and Southern Maryland Electric Cooperative, 
Inc. (SCOOP)
103. Suffolk County Electrical Agency
104. Sunflower Electric Power Corporation (Sunflower)
105. Tampa Electric Company
106. Tennessee Valley Authority (TVA)
107. Public Utility Commission of Texas (Texas Commission)
108. Texas Utilities Electric Company
109. Transmission Access Policy Study Group (TAPS) [[Page 17725]] 
110. TDU Customers, consisting of Chicopee Municipal Lighting Plant 
of the City of Chicopee, Massachusetts, Golden Spread Electric 
Cooperative, Inc., Holy Cross Electric Association, Inc., Kansas 
Electric Power Cooperative, Inc., Old Dominion Electric Cooperative, 
Seminole Electric Cooperative, Inc., South Hadley Electric Light 
Department of the Town of South Hadley, Massachusetts, and Westfield 
Gas and Electric Department of the City of Westfield, Massachusetts
111. Trigen Energy Corporation
112. United Illuminating Company
113. United States Department of Defense
114. United States Department of Energy (DOE)
115. United Utility Shareholders Association of America
116. Utility Investors and Analysts
117. Utility Working Group (consisting of Dominion Resources, Inc., 
Duke Power Company, Duquesne Light Company, Entergy Corporation, 
General Public Utilities Corporation, Niagara Mohawk Power 
Corporation, Northern States Power Company, Pacific Gas and Electric 
Company, Portland General Electric Company, Public Service Electric 
and Gas Company, San Diego Gas & Electric Company, Southern 
California Edison Company, and Wisconsin Electric Power Company)
118. Vermont Department of Public Service (Vermont Department)
119. Virginia Electric and Power Company
120. Virginia State Corporation Commission
121. Washington Utilities and Transportation Commission
122. Washington Water Power Company
123. Wheeled Electric Power Company
124. Wisconsin Electric Power Company
125. Wisconsin Power & Light Company (Wisconsin Power)
126. Wisconsin Public Service Commission
127. Wisconsin Wholesale Customers
128. Wyoming Public Service Commission
Promoting Wholesale Competition Through Open Access Non-Discriminatory 
Transmission Services by Public Utilities

Docket No. RM95-8-000

Recovery of Stranded Costs by Public Utilities and Transmitting 
Utilities

Docket No. RM94-7-001

    Issued March 29, 1995.
    Massey, Commissioner, concurring in part and dissenting in part:

I. Concurring Opinion

    Today, the Commission takes the logical next step--a bold, 
aggressive and historic step--toward full and robust competition in 
the electric power industry. Our proposal will change fundamentally 
the nature of this industry, and the relationships among 
transmission-owning utilities, their customers and competing power 
suppliers.
    Why now? An uninformed observer might think it somewhat 
startling, at the very least counterintuitive, that in the current 
political climate, at the very same time Congress is debating a 
regulatory moratorium, this Commission issues the most profound 
regulatory proposal for the electric utility industry since the New 
Deal legislation. Why now?
    There are several compelling reasons. First, now is always the 
best time to end undue discrimination. Federal law ``bristles'' with 
concern about undue discrimination. The Federal Power Act does not 
allow this Commission to tolerate it. There will never be a better 
time than now to stop it.
    Second, now is also an appropriate time to eliminate the 
industry's uncertainty over our policy directions. Uncertainty is 
deeply unsettling for this industry. Instead of focusing on how to 
beat the competition, industry participants must first speculate 
about the future rules of the competition. This is intolerable in 
the long term and, in the short-term, stifles creativity, initiative 
and investment. We believe industry participants will applaud 
efforts to end the uncertainty now.
    Third, this Commission wants to move boldly toward customer 
choice and light-handed regulation of wholesale generation. We 
believe it will bring lower rates. But we are limited greatly by 
transmission market power. We cannot move forcefully in these 
directions if transmission owners are able to skew the market and 
eliminate competition by denying or delaying transmission access, or 
by offering inferior terms and conditions for transmission service. 
The current patchwork of transmission access impedes competition. We 
must move beyond voluntary open access tariffs and time-consuming 
and expensive case-by-case rulings on wheeling requests. Now is the 
time to eliminate the transmission market power of the utilities 
over which we have jurisdiction. How can there be truly robust 
competition if buyers and sellers can't reach each other? Those who 
believe in competition and lower rates will applaud this step.
    And, fourth, we cannot move to new rules without assuring 
utilities that they will recover the costs they prudently incurred 
under the old rules. That is a fundamental principle of our NOPR. We 
must strive to eliminate the uncertainty in the industry over the 
way in which this Commission will address stranded cost issues. Now 
is the time to speak clearly on this critical issue.
    For these reasons, now is not only an appropriate time, but may 
indeed be the best time to take this bold step toward truly robust 
competition. It is my fervent hope that the market-based solutions 
this proposal portends, and the giant step it takes toward 
eliminating industry uncertainty over policy directions and stranded 
cost recovery, will strike a responsive chord among lawmakers, other 
policy makers, and others who care about the future of this 
important industry.
    I strongly support virtually all of this NOPR. The NOPR 
addresses dozens of open access and stranded cost issues in ways 
that have my wholehearted support.
    For example, I agree strongly with the proposed requirements of 
open access tariffs. It is one thing to state somewhat blithely that 
we favor the golden rule of transmission access. That is about all 
we have said so far. It is another thing entirely, and much more 
valuable to industry participants, to put real meat on the bones of 
comparability. The extensive text of the order accomplishes this 
objective, with unparalleled clarity. In fact, this entire document 
is a persuasive, compelling, technically brilliant work.
    Let me highlight three specific issues. First is the issue of 
the NOPR's effect on regional transmission groups. Some in the 
industry may erroneously conclude that this rulemaking will lessen 
the value of, and need for, RTGs. The order emphatically disagrees. 
As the order states:
    RTGs are structures to reflect the interest of all of the grid's 
users, not just some. RTGs allow for consensual solutions to local 
or regional issues, instead of solutions imposed by FERC. RTGs can 
function as regional laboratories for experimentation on 
transmission issues. And, RTGs will provide a regional forum, a 
necessary predicate to regional cooperation.
    In short, RTGs remain a key part of our vision of the future of 
this industry.
    Second, the NOPR requires the new tariffs to include a 
reciprocity provision. This provision would ensure that a public 
utility offering transmission access to others can obtain similar 
service from its transmission customers. If customers want access on 
a public utility's transmission wires, they must be willing to offer 
access for the utility on their own transmission wires. That is only 
fair.
    Third, the NOPR would require functional unbundling of public 
utilities' jurisdictional services. That is, utilities would be 
required to take transmission service (including ancillary services) 
for new wholesale sales and purchases of electric energy under the 
open access tariffs. The tariffs also must state separately the 
rates for each type of transmission or ancillary service. This 
requirement of functional unbundling will give public utilities the 
incentive to offer service on fair terms and conditions, since the 
public utility will have to live with the same terms and conditions 
it proposes for others.
    Now let me turn to an issue involving symmetry of rights between 
customers and utilities. Today's order makes an explicit generic 
finding that it is in the public interest to allow utilities to make 
filings at FERC for the recovery of stranded costs even if their 
contracts contain so-called Mobile-Sierra restrictions that would 
bar such filings.<SUP>1 I fully agree with this conclusion. I 
believe the policy rationale justifying the recovery of stranded 
costs is so strong that the public interest test is met and such a 
generic finding is necessary.

    \1\United Gas Pipeline Co. v. Mobile Gas Service Corp., 350 U.S. 
332 (1956); FPC v. Sierra Pacific Power Co., 350 U.S. 348 (1956).
---------------------------------------------------------------------------

    I have some concern, however, about the fact that today's order 
does not sufficiently explore making that same type of public 
interest finding on behalf of customers. The order spends many pages 
making a persuasive case that the current environment, in which no 
more than a handful of utilities have filed open access tariffs, is 
rife with undue discrimination and can no longer be tolerated. This 
is the fundamental philosophical and legal underpinning for the 
order's new open access requirements. [[Page 17726]] 
    But if the order's perception of undue discrimination is 
accurate, and I believe it is, would it not suggest that some power 
supply contracts negotiated in that environment were infected with 
undue discrimination and therefore unlawful? Would it not be 
appropriate, and more symmetrical, to allow such customers the right 
to make a filing asking the Commission to determine whether their 
current contract is unduly discriminatory, unjust or unreasonable? 
We would not, of course, allow such customers to escape their 
stranded cost responsibility in any event. Even if we allowed 
customers to make such filings, they would remain fully responsible 
for the costs reasonably incurred on their behalf.
    A more symmetrical approach to customers and utilities during 
the transition to competitive markets would be consistent with the 
Commission's Order 636. There, the Commission granted all pipeline 
``sales'' customers the right to choose other gas suppliers but 
granted all pipelines 100 percent recovery of their eligible and 
prudent transition costs. In granting ``conversion rights'' to 
pipeline sales customers, the Commission found that continued 
enforcement of customers' existing purchase obligations, entered 
into when pipelines provided bundled service and had a virtual 
monopoly over certain aspects of interstate service, was contrary to 
the requirements of the Natural Gas Act.
    I am not suggesting today that we mirror precisely the natural 
gas model by granting all customers, regardless of contracts, the 
right to choose other suppliers. I am suggesting, however, that 
during the comment period we give full and fair consideration to the 
argument that power customers with contracts lacking explicit 
stranded cost recovery provisions should have the same right we 
grant utilities to make filings seeking contract modifications 
regardless of Mobile-Sierra restrictions. I am confident that 
commenters will give us the benefit of their thinking on this issue.

II. Dissenting Opinion

    Finally, let me turn briefly to the sole issue on which I will 
be dissenting in part from an otherwise exceptionally strong order. 
That issue involves this Commission's role and relationship with the 
states in making determinations with respect to stranded costs 
arising from retail competition and from municipalizations.
    There have been full and vigorous discussions at the Commission 
about how to handle this issue. My goal, which the entire Commission 
shares, is to strike an appropriate balance that ensures the 
recovery of stranded costs, and ensures that the legitimate rights 
of states are respected. We have all struggled with these issues in 
good faith. I simply disagree with the majority in certain respects 
about how to accomplish these goals.
    First, I will address retail competition. Under the NOPR, this 
Commission would allow filings seeking recovery of stranded costs 
related to retail competition only when the state regulatory 
commission does not have authority under state law to address 
stranded costs at the time retail wheeling is required.
    I find this approach too narrow. I would allow such filings when 
the state commission lacks authority to decide the issue or when the 
state commission has authority but does not decide the issue. I 
would not second-guess the state decision, but I would not allow 
retail stranded costs to ``fall through the cracks'' merely because 
the state commission has, but does not use, authority to decide the 
issue.
    On municipalization, the NOPR proposes making this Commission 
the primary forum for seeking recovery of stranded costs. The NOPR 
says that, if a state has allowed recovery of any stranded costs 
from municipalized customers, this Commission will deduct that 
amount from the amount we determine to be recoverable. In other 
words, even when states have and exercise the authority to decide 
the recoverability of stranded costs related to municipalization, 
this Commission would take over and federalize the issue.
    I cannot support this approach. The Federal Power Act does not 
constitute this Commission as the court of appeals to challenge 
unsatisfactory state decisions. It is not this Commission's role to 
stand in judgment of policy choices and decisions lawfully made by 
our state counterparts.
    In my judgment, the following principles should govern this 
Commission's approach to stranded costs arising from either retail 
competition or municipalization. In either case, utilities are 
entitled to a decision on the recoverability of such costs. It would 
be unfair, and would unduly jeopardize the financial health of 
utilities, for stranded costs to slip through because no regulatory 
commission provides a forum and decides the issue.
    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.
    My views on how we should handle stranded costs arising from 
municipalization are influenced by the fact that, according to 
commenters, roughly 14 states have municipalization statutes that do 
in fact authorize states to deal with stranded cost issues. 
Arkansas, for example, has a statute enacted in 1987 that appears to 
give the Arkansas Public Service Commission full authority to deal 
with the stranded cost issue in a way that protects both the 
remaining customers and shareholders. It is an extensive, thoughtful 
statute that deals with a wide range of issues. It is, apparently, 
the will of the sovereign state of Arkansas that this state statute 
be enforced. I see no reason to yank this issue from the Arkansas 
Commission, or from any other state commission that has statutory 
authority to act.
    In that vein, if this Commission were to decide the 
recoverability of stranded costs for either retail competition or 
muncipalization (because the state lacked authority or did not 
decide the issue), I believe we should adopt procedures allowing the 
affected state commissions to participate in our proceeding in a 
meaningful way. Specifically, I propose allowing state participation 
through one of the procedures specified in section 209 of the 
Federal Power Act.<SUP>2 These include joint state boards, joint 
hearings, concurrent hearings and technical conferences. I have no 
views at this time on which of these tools could or should be used 
in particular cases. The decision on which of these tools to use can 
be made in individual cases, as they arise. But, clearly, they are 
useful mechanisms for obtaining state input in proceedings involving 
retail competition and municipalization.

    \2\16 U.S.C. 824h (1988).
---------------------------------------------------------------------------

    For all of these reasons, I will concur in part and dissent in 
part. In virtually all respects, this is an excellent order; except 
as I have noted, it has my wholehearted support.
William L. Massey,
Commissioner.
[FR Doc. 95-8534 Filed 4-6-95; 8:45 am]
BILLING CODE 6717-01-P