[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:
proposes to require all public utilities owning or
controlling facilities used for transmitting electric energy in
interstate commerce to file open access transmission tariffs;
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;
issues a supplemental proposed rule to permit the
recovery of legitimate and verifiable stranded costs associated with
requiring open access tariffs; and
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.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.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.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.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
NOPR5 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 facilities6 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. 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.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.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.''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.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.
436.12 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.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.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)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.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)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 * * *.''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.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,20 the FPC21
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
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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.'' [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.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).
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In Florida Power & Light Company v. FERC (Florida),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.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.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.27 The
Commission order would impose common carrier status on FP&L, the court
found.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.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.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. [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.''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.33
\32\Id. at 999.
\33\Id. at 1006.
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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.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.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.
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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,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.
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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.37 Thus, there was no pressure
on regulatory commissions to use regulation to affect the structure of
the industry.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.39 This was the beginning of periods of rapid
inflation, higher nominal interest rates, and higher electricity
rates.40 During [[Page 17669]] this time, consumers became
concerned about higher electricity rates and questioned any price
increases filed by utilities.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.
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During this same time frame, the construction of nuclear and other
capital-intensive baseload facilities--actively encouraged by federal
and some state governments--contributed to the continuing cost
increases and uncertainties in the industry.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.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.44 In addition,
by the 1980s, the oil cartel collapsed, with a resulting glut of low-
priced oil.45 At the same time, inflation substantially increased
the costs of these large baseload generating plants.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.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.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.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.
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Consumers responded to these ``rate shocks'' by exerting pressure
on regulatory bodies to investigate the prudence of management
decisions to build generating plants, especially when construction
resulted in cost overruns, excess capacity, or both. Between 1985 and
1992, writeoffs of nuclear power plants totalled $22.4 billion.50
These writeoffs significantly reduced the earnings of the affected
utilities.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.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.'').
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In addition to economic changes in the industry, significant
technological changes in both generation and transmission have occurred
since 1935. Through the 1960s, bigger was cheaper in the generation
sector and the industry was able to capitalize on economies of scale to
produce power at lower per-unit costs from larger and larger
plants.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.54 A significant factor was that larger
generation units were found to need relatively greater maintenance and
experience longer downtimes.55 The electric industry faced the
situation ``where the price of each incremental unit of electric power
exceeded the average cost.''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.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.
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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.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.
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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].''59
\59\Id. at 24.
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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.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.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
* * *'').
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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.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
transactions63 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,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.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.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.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.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.69 Notwithstanding these
limitations, QFs proliferated. In 1989, there were 576 QF facilities.
By 1993, there were more than 1,200 such facilities.70 For the
same time period, installed QF capacity increased from 27,429 megawatts
to 47,774 megawatts.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.
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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.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.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.
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There were two major impediments to the development of IPPs and
APPs. First, the ownership restrictions of the Public Utility Holding
Company Act (PUHCA)74 severely inhibited these new entities from
entering the generation business.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,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.77 Indeed, ``[i]n 1992, for the first time, generating
capacity added by independent producers exceeded capacity added by
utilities.''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.
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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.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.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.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.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.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.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 access85 remained
major barriers to new generators, Congress enacted Title VII of the
Energy Policy Act of 1992 (Energy Policy Act).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.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.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.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.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.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.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;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.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.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.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.
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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.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.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.''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).
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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.100 The Commission accepted the
proposed transmission tariff for filing and suspended its effectiveness
for one day, subject to refund.101 Rehearing requests challenged
the Commission's summary approval of the restriction of service to
point-to-point as being discriminatory and anticompetitive.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.
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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.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.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.105
\105\Id. at 61,490-91.
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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.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.
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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.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.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.109
\109\Id. at 915 (footnote omitted).
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In Heartland Energy Services, Inc.,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.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.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.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.''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.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,116 Wisconsin Electric Power
Company,117 and Wisconsin Public Service Corporation.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).
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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.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.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.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.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.
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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,123 (2) Transmission Pricing Policy Statement,124
(3) Pooling Notice of Inquiry,125 and (4) Regional Transmission
Group (RTG) Policy Statement.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.''127 Accordingly, the Commission proposed to
establish provisions concerning the recovery of wholesale and retail
stranded costs by public utilities and transmitting utilities.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.
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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.129 Under the new policy, it will permit a
variety of proposals, including distance sensitive and flow-based
pricing,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.''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.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.
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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.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.''134
\134\Id. at 35,714.
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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.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.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 1993.137 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.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.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.
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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.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.
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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.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.
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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.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).
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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.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.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.
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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.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).
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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.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.
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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,147 they have occurred.148 More
often, however, discrimination is likely to be manifested more subtly
and indirectly.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.150 Another way of frustrating access is to substantially
change the terms of negotiated agreements through protracted delay,
including filings with regulatory agencies.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.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).
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(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.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.
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(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.154
\154\See AEP, 64 FERC at 62,971-72.
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(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.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.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.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.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.
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(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.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.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).
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(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.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.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.
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(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.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.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.165
\164\See Coalition Petition at 13-14.
\165\See Mid-Continent Area Power Pool, 69 FERC para.61,347 at
62,308 (1994).
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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
212.166 Indeed, to date, the Commission has received eighteen
section 211 transmission requests,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.
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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 Pendinga............................ 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 Pendinga............................ 8
TX94-8...... 08/05/94 Pending............................. 7
TX94-9...... 09/09/94 Pendinga............................ 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
------------------------------------------------------------------------
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.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.
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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
636.170 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.
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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.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.
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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 NGA172 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.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.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.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.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.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,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.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).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.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,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.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.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.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.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;187 and (2) a sale of
unbundled generation at retail, subject to the state's
jurisdiction.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).
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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.189 We were concerned then, just as we
are concerned now, that interstate and intrastate programs operate
together in an appropriately integrated way.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.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.
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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.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.193
\193\These Appendices will not appear in the Federal Register.
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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.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.
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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 211.195
\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.
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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.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).
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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.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.
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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.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.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.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.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:
A requirement to meet generally applicable reliability
criteria.
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.
Fulfilling the transmission provider's current firm power
and firm transmission contracts.
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.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.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.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.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.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.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. 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.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.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,211 and that there is no affiliate abuse or reciprocal
dealing. In KCP&L,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.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.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. 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. 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 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 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.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.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, 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
211.222
\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 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.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.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).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.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 wheeling228
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.229 We believe states may impose retail stranded costs on
facilities or services falling under this definition.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.''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
parties232 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 Tail233 (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
Company234 (in which utilities were alerted to the threat of
municipalization), and the Commission's 1983 decision in Kentucky
Utilities Co.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