[Federal Register Volume 65, Number 46 (Wednesday, March 8, 2000)]
[Rules and Regulations]
[Pages 12088-12115]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 00-5021]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 35
[Docket No. RM99-2-001; Order No. 2000-A]
Regional Transmission Organizations
Issued February 25, 2000.
AGENCY: Federal Energy Regulatory Commission, DOE.
ACTION: Final rule; Order on rehearing.
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SUMMARY: The Federal Energy Regulatory Commission (Commission)
reaffirms its basic determinations in Order No. 2000 and clarifies
certain terms. Order No. 2000 requires that each public utility that
owns, operates, or controls facilities for the transmission of electric
energy in interstate commerce make certain filings with respect to
forming and participating in an Regional Transmission Organization
(RTO). Order No. 2000 also codifies minimum characteristics and
functions that a transmission entity must satisfy in order to be
considered an RTO. The Commission's goal is to promote efficiency in
wholesale electricity markets and to ensure that electricity consumers
pay the lowest price possible for reliable service.
EFFECTIVE DATE: Changes to Order No. 2000 made in this order on
rehearing will become effective on April 7, 2000.
FOR FURTHER INFORMATION CONTACT:
Alan Haymes (Technical Information), Federal Energy Regulatory
Commission, 888 First Street, N.E., Washington, D.C. 20426, (202) 219-
2919
Brian R. Gish (Legal Information), Federal Energy Regulatory
Commission, 888 First Street, N.E., Washington, D.C. 20426, (202) 208-
0996
James Apperson (Collaborative Process), Federal Energy Regulatory
Commission, 888 First Street, N.E., Washington, D.C. 20426, (202) 219-
2962
SUPPLEMENTARY INFORMATION:
Table of Contents
I. Introduction
II. Summary
III. Discussion
A. Commission's Approach to RTO Formation
1. Voluntary Approach
2. Legal Authority
B. Minimum Characteristics of an RTO
1. Independence
a. Definition of Market Participant
b. Ownership Issues
c. Section 205 Filing Rights
2. Scope and Regional Configuration
3. Short-Term Reliability
C. Minimum Functions of an RTO
1. Tariff Administration and Design
2. Congestion Management
3. Ancillary Services
4. OASIS and Total Transmission Capability (TTC) and Available
Transmission Capability (ATC)
5. Market Monitoring
6. Planning and Expansion
7. Interregional Coordination
D. Open Architecture
E. Transmission Ratemaking Policy for RTOs
1. Pancaked Rates
2. Uniform Access Charges
3. Service to Transmission-Owning Utilities That Do Not
Participate in an RTO
4. Performance-Based Rate Regulation
5. Other RTO Transmission Ratemaking Reforms
a. Levelized Rates
b. Return on Equity
c. Accelerated Depreciation and Incremental Pricing for New
Transmission Investments
d. Other Innovative Rate Issues
6. Additional Ratemaking Issues
7. Filing Procedures for Innovative Rate Proposals
F. Other Issues
1. Public Power and Cooperative Participation in RTOs
2. Existing Transmission Contracts
3. Lighter Handed Regulation
G. Implementation Issues
1. Filing Requirements
2. Deadline for RTO Operation
IV. Regulatory Flexibility Act Certification
V. Public Reporting Burden and Information Collection Statement
VI. Effective Date
VII. Document Availability
Regulatory Text
Appendix
I. Introduction
On December 20, 1999, the Commission issued a Final Rule (Order No.
2000) to advance the formation of Regional Transmission Organizations
(RTOs).\1\ Our objective in promulgating Order No. 2000 was to have all
transmission-owning entities in the Nation, including non-public
utility entities, place their transmission facilities under the control
of appropriate RTOs in a timely manner.
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\1\ Regional Transmission Organizations, Order No. 2000, 65 FR
809 (January 6, 2000), FERC Stats. & Regs. para. 31,089 (2000).
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In Order No. 2000, the Commission concluded that regional
institutions could address the operational and reliability issues
confronting the industry, and eliminate undue discrimination in
transmission services that can occur when the operation of the
transmission system remains in the control of a vertically integrated
utility.
[[Page 12089]]
Furthermore, we found that appropriate regional transmission
institutions could: (1) improve efficiencies in transmission grid
management; (2) improve grid reliability; (3) remove remaining
opportunities for discriminatory transmission practices; (4) improve
market performance; and (5) facilitate lighter handed regulation. We
stated our belief that appropriate RTOs can successfully address the
existing impediments to efficient grid operation and competition and
can consequently benefit consumers through lower electricity rates and
a wider choice of services and service providers. In addition,
substantial cost savings are likely to result from the formation of
RTOs.
Order No. 2000 established minimum characteristics and functions
that an RTO must satisfy in the following areas:
Minimum Characteristics:
1. Independence
2. Scope and Regional Configuration
3. Operational Authority
4. Short-term Reliability
Minimum Functions:
1. Tariff Administration and Design
2. Congestion Management
3. Parallel Path Flow
4. Ancillary Services
5. OASIS and Total Transmission Capability (TTC) and Available
Transmission Capability (ATC)
6. Market Monitoring
7. Planning and Expansion
8. Interregional Coordination
In the Final Rule, we noted that the characteristics and functions
could be satisfied by different organizational forms, such as ISOs,
transcos, combinations of the two, or even new organizational forms not
yet discussed in the industry or proposed to the Commission. Likewise,
the Commission did not propose a ``cookie cutter'' organizational
format for regional transmission institutions or the establishment of
fixed or specific regional boundaries under section 202(a) of the
Federal Power Act (FPA).
We also established an ``open architecture'' policy regarding RTOs,
whereby all RTO proposals must allow the RTO and its members the
flexibility to improve their organizations in the future in terms of
structure, operations, market support and geographic scope to meet
market needs.
In addition, the Commission provided guidance on flexible
transmission ratemaking that may be proposed by RTOs, including
ratemaking treatments that address congestion pricing and performance-
based regulation. The Commission stated that it would consider, on a
case-by-case basis, innovative rates that may be appropriate for
transmission facilities under RTO control.
Furthermore, to facilitate RTO formation in all regions of the
Nation, the Final Rule outlined a collaborative process to take place
in the Spring of 2000. Under this process, we expect that public
utilities and non-public utilities, in coordination with state
officials, Commission staff, and all affected interest groups, will
actively work toward the voluntary development of RTOs.
Lastly, under Order No. 2000, all public utilities that own,
operate or control interstate transmission facilities must file with
the Commission by October 15, 2000 (or January 15, 2001 \2\) a proposal
to participate in an RTO with the minimum characteristics and functions
to be operational by December 15, 2001, or, alternatively, a
description of efforts to participate in an RTO, any existing obstacles
to RTO participation, and any plans to work toward RTO participation.
That filing must explain the extent to which the transmission entity in
which it proposes to participate meets the minimum characteristics and
functions for an RTO, and either propose to modify the existing
institution to the extent necessary to become an RTO, or explain the
efforts, obstacles and plans with respect to conforming to these
characteristics and functions.
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\2\ A public utility that is a member of an existing
transmission entity that has been approved by the Commission as in
conformance with the eleven ISO principles set forth in Order No.
888 must make a filing no later than January 15, 2001.
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II. Summary
Thirty-eight petitioners filed requests for rehearing and/or
clarification of Order No. 2000.\3\ These entities raise a variety of
issues, including legal, policy and technical arguments. We respond
herein to the arguments made to us in the requests for rehearing and
clarification. To the extent not specifically addressed herein, the
requests are denied.
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\3\ The requesters and abbreviations for them as used herein,
are listed in an appendix to this order. PECO's request was filed
one day beyond the thirty days allowed for rehearing requests, so we
will consider its request to be for clarification. We note that
TransConnect, Inc. filed a motion to intervene on January 27, 2000
raising no issues that warrant discussion herein.
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Many of the parties requesting rehearing or clarification of Order
No. 2000 express their agreement with the majority of the rule. Indeed,
most petitions are relatively short in length and focus on only a few
discrete issues, indicating that most parties are generally comfortable
with the remaining substance of the Final Rule. We attribute this to
the unprecedented outreach effort that the Commission undertook before
and during the rulemaking process. Because we expect similar
significant results from the post-rule collaborative process which we
are initiating with our first regional workshop in Cincinnati on March
1, 2000, the Commission concluded that it was important to issue this
order on rehearing before that date. Our order on rehearing focuses on
the discrete issues that were raised on rehearing. However, the
extensive background for this rulemaking and a comprehensive discussion
of our goals and principles can be found in Order No. 2000.
On rehearing, we reaffirm the core elements and basic framework of
Order No. 2000. However, we have provided clarification with respect to
a number of issues, including concerns raised about our requirement
that the RTO must have exclusive and independent authority under
section 205 of the FPA to propose rates, terms and conditions of
transmission service provided over the facilities it operates. While we
have maintained the requirement without modification, we have carefully
and comprehensively addressed the concerns that were raised and
provided further clarification.
We have amended the regulatory text in three areas. First, we have
revised the definition of market participant in section 35.34(b)(2) to
remove specific references to entities that provide transmission
service to an RTO. Second, we have added section 35.34(j)(1)(iv) to
codify the requirement for audits with respect to the independence
characteristic. Third, we have revised section 35.34(d)(4) to require
RTO proposals to include an explanation of efforts made to include
cooperatively-owned entities, in addition to public power entities, in
the proposed RTO.
III. Discussion
A. Commission's Approach to RTO Formation
1. Voluntary Approach
In the Final Rule, the Commission adopted as a matter of policy a
voluntary approach to RTO formation. In other words, Order No. 2000
does not mandate RTO participation. We concluded that a voluntary
approach, with guidance and encouragement from the Commission, was the
most appropriate to achieving RTO formation at this time.\4\
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\4\ FERC Stats. & Regs. para. 31,089 at 31,033-34.
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[[Page 12090]]
Rehearing Requests
The Pennsylvania Commission argues that RTO membership must be
mandatory for all participants in the wholesale market and should be a
condition of participating in the competitive market. It claims that
failing to mandate participation undercuts the coordination of
generation additions. It states that the Commission clearly perceived
the problems, but stopped short of the solution.
TDU Systems asserts that the Commission did not give adequate
consideration to the advantages of mandatory RTO participation and the
disadvantages of the voluntary approach. It cites the potential costs
associated with the innovative rates discussed in the Final Rule, and
asserts that the Commission should perform a fuller evaluation of the
potential costs and benefits associated with each approach.
TAPS argues that the Commission erred by relying on voluntary
action for RTO formation rather than exercising its statutory authority
to mandate RTOs. It states that the Commission violated its statutory
obligations to remedy undue discrimination. It believes that past
experience and common sense demonstrate that voluntary action, coupled
with incentives, does not work.
CFA argues that the resistance of the vertically integrated
incumbent network owners will be so vigorous that the voluntary
approach will fail to solve the problem, and urges the Commission to
mandate participation in RTOs.
In addition to the arguments in favor of a direct mandate, TDU
Systems, TAPS, CFA, and Industrial Consumers argue that the Commission
must generically condition the granting of all market-based rate
authorizations and merger authorizations on participation in an RTO.
CFA states, for example, that without participation in an RTO, allowing
mergers or market-based rates is not in the public interest.
Commission Conclusion
We deny rehearing with respect to our adoption of a voluntary
approach to RTO formation. We agree with those advocating a mandatory
approach that the objective is to have all transmission-owning entities
place their transmission facilities under the control of RTOs in a
timely manner, and we stated this in the Final Rule.\5\ There are,
however, different possible means of attaining that objective. The
Commission has made a judgment that the most efficient and effective
means is one that involves establishing clear standards, removing
obstacles, and fostering cooperation and creativity, rather than one
that imposes strict mandates that could polarize parties and generate
resistance. That we have not chosen to mandate RTO participation does
not mean that we have avoided our obligations to address the
impediments to competition that we identified; it merely means that we
have chosen a method to address those impediments that we believe will
efficiently achieve the result we desire.
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\5\ See id. at 31,033.
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We explained in the Final Rule that the voluntary approach as we
structured it will allow the industry the opportunity and the
flexibility to develop mutually agreeable regional arrangements, and
will permit the industry to focus its efforts on the potential benefits
of RTO formation rather than on a non-productive challenge to our legal
authority to mandate RTO participation.\6\ We also stated a number of
reasons why we believe this voluntary approach will be successful: the
pace of restructuring is accelerating, industry participants are
recognizing the strategic benefits of focusing on one segment of the
utility business, the Final Rule provides clear guidance on what is
necessary to form RTOs, the Commission is facilitating a collaborative
process, and certain favorable ratemaking treatments are offered to at
least eliminate economic disincentives to RTO formation.\7\
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\6\ Id.
\7\ Id. at 31,034.
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Contrary to TDU Systems' assertion, the Commission gave careful
consideration to the advantages and disadvantages of the voluntary and
mandatory approaches. Specifically, TDU Systems faults the Commission
for not quantifying the impact of the favorable ratemaking treatments
that are offered, which, allegedly, would not be required under a
mandatory approach. We do not believe it is appropriate to think of the
innovative ratemaking treatments discussed in the Final Rule as a cost
of the voluntary approach. As discussed in the Final Rule, the
innovative ratemaking treatments are intended, among other things, to
eliminate disincentives to the efficient use and expansion of regional
transmission grids, and to allow transmission-owning utilities to
capture some of the benefits of more efficient system operation.\8\ We
are requiring as a part of any proposal for innovative ratemaking
treatments that the applicant demonstrate how the proposal would help
achieve the goals of RTOs, to submit a cost-benefit analysis including
rate impacts, and to demonstrate that the rate is just, reasonable and
non-discriminatory.\9\
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\8\ Id. at 31,171-73, 31,191-92.
\9\ FERC Stats. & Regs. para. 31,089 at 31,196.
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In response to those who argue that the Commission should state
generically that all market-based rates and mergers must be conditioned
on RTO participation, we continue to believe that this is best
addressed on a case-by-case basis. We see no need to decide at this
time that no merger or market-based rate proposal could satisfy our
applicable standards without RTO participation. There will be
sufficient opportunity to consider this in the context of individual
cases.
2. Legal Authority
The Commission discussed in the Final Rule its legal authority with
respect to RTO formation. We concluded that we possessed both general
and specific authorities to advance voluntary RTO formation, and
concluded that we possessed the authority to order RTO participation on
a case-by-case basis if necessary to remedy undue discrimination or
anticompetitive effects where supported by the record.\10\ We discussed
our authority and responsibility under sections 202(a), 203, 205, and
206 of the FPA.\11\
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\10\ Id. at 31,043.
\11\ See id. at 31,043-46.
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Rehearing Requests
TAPS argues that the Commission violated its statutory obligation
to remedy undue discrimination by relying upon a voluntary, as opposed
to mandatory, approach to RTO participation. CCEM argues that the
Commission committed legal error by not adopting CCEM's proposal--
operational unbundling of vertically integrated utilities that places
all uses of the transmission system under the same tariff--as a remedy
for undue discrimination. CCEM asserts that the Commission must provide
a reasoned explanation why simply encouraging jurisdictional
transmission owners to join RTOs is an effective remedy for undue
discrimination.
Duke argues that the Commission should not make findings that it
possesses the legal authority to mandate RTO participation on a case-
by-case basis, and asks for rehearing of this conclusion, or,
alternatively, requests clarification that no party will be deemed to
have waived its right to challenge this conclusion in an individual
proceeding. Similarly, EEI and Puget Sound ask for clarification that a
public utility retains the right to
[[Page 12091]]
challenge the Commission's legal authority should the Commission seek
to impose a requirement for RTO participation in the future. If the
Commission does not so clarify, they seek rehearing.
ISO Participants argue that the Commission erred in finding that
the formation of an RTO that involves transfer of operational control
without a transfer of ownership is a transaction that requires approval
under section 203 of the FPA. They assert that the assignment of
operational responsibilities to an ISO, by itself, is not a disposition
of facilities within the meaning of section 203.
Commission Conclusion
We found in the Final Rule that continuing opportunities for undue
discrimination exist in the electric transmission industry and that
they may not be remedied adequately by functional unbundling.\12\ TAPS
and CCEM believe that this finding requires a remedy different from the
voluntary approach to RTO formation adopted in the Final Rule. TAPS
asserts the remedy must be an RTO mandate, and CCEM asserts the remedy
must be a total unbundling of transmission, including, apparently,
retail unbundling. We do not agree that either of these remedies is
required by law. While it is true that the Commission has a legal
obligation to remedy undue discrimination it finds,\13\ the Commission
retains discretion as to what remedy to pursue.
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\12\ Id. at 31,015, 31,043.
\13\ See, e.g., Southern California Edison Company, 40 FERC
para. 61,371 at 62,151-52 (1987), order on reh'g, 50 FERC para.
61,275 at 61,873 (1990), modified sub nom., Cities of Anaheim v.
FERC, 941 F.2d 1234 (D.C. Cir. 1991); Delmarva Power and Light
Company, 24 FERC para. 61,199 at 61,466, order on reh'g, 24 FERC
para. 61,380 (1983).
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As we said in the Final Rule, we believe that the use of RTOs
throughout the country, with the required independence from market
participants, can reduce opportunities for unduly discriminatory
conduct.\14\ The Commission has taken a large step in Order No. 2000 to
encourage and advance the formation of RTOs. As discussed above with
respect to the Commission's voluntary approach, the fact that the
approach is not mandatory does not undermine the ultimate objective of
widespread RTO formation. We believe that the approach we have taken is
a measured and appropriate response at this time to the lingering
discrimination concerns that have been raised.\15\
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\14\ FERC Stats. & Regs. para. 31,089 at 31,024.
\15\ See id. at 31,028.
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In response to those asking clarification of our conclusion in the
Final Rule that the Commission possesses the authority to order RTO
participation on a case-by-case basis to remedy undue discrimination or
anticompetitive effects where supported by the record,\16\ we note that
this is a statement of our remedial authorities. It is well established
that the Commission's discretion is at its zenith when fashioning
remedies for undue discrimination.\17\ The Commission is given
substantial deference with respect to such remedies as long as they are
reasonably tailored to meet the Commission's goals.\18\ It is our view
that, pursuant to sections 206 and 309 of the FPA, the Commission could
order a public utility to participate in an RTO upon finding that the
public utility was engaging in unjust, unreasonable, unduly
discriminatory or anticompetitive practices, and that participation in
an RTO was a reasonable remedy for that unlawful behavior. If we were
to impose such a remedy in a particular case, any aggrieved party would
have the right to challenge the lawfulness and reasonableness of that
remedy to the extent permitted by law.
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\16\ Id. at 31,043.
\17\ See Order 888, FERC Stats. & Regs. para. 31,036 at 31,676
(1996); Niagara Mohawk Power Corp. v. FPC, 379 F.2d 153, 159 (D.C.
Cir. 1967); Tapoco, Inc., et al., 39 FERC para. 61,363 at 62,169
(1987).
\18\ Tenneco Gas Co. v. FERC, 969 F.2d 1187, 1198, 1201 (D.C.
Cir. 1992).
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ISO Participants' argument that the Commission erred in its
discussion of section 203 of the FPA is misplaced. Although they do not
specify the particular language in the order that they object to, they
apparently refer to our statement that ``public utilities'' transfers
of control of jurisdictional transmission facilities to entities such
as RTOs would require section 203 approval.'' \19\ ISO Participants
argue that a public utility's assignment of limited operating
responsibilities to an ISO, while retaining physical control and
ownership, is not a disposition within the meaning of section 203. The
language in Order No. 2000 was a general summary statement of how the
Commission has interpreted section 203 in its case precedent. Indeed,
the Commission has invoked its section 203 authority over the transfers
of control of transmission facilities for all five of the ISOs that
have been approved thus far. Thus, our statement in Order No. 2000 was
not intended as a new, changed, or amplified interpretation. Those
questioning whether specific fact situations invoke our jurisdiction
have appropriate avenues, such as requests for declaratory order, to
have those questions resolved.
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\19\ FERC Stats. & Regs. para. 31,089 at 31,045.
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B. Minimum Characteristics of an RTO
1. Independence
In the Final Rule, we discussed how to ensure that an RTO would be
able to operate independently from market participants. We defined who
was a market participant. \20\ We also discussed the extent to which
ownership of a transmission company by market participants would be
permitted. We stated that a truly passive form of ownership would be
acceptable,\21\ but that active ownership by market participants would
be limited.\22\ Another aspect of independence discussed in Order No.
2000 was how to ensure that the RTO could have independence with
respect to its tariff. In response to comments on the NOPR, we
clarified that the transmission owners retained rights to make section
205 filings to establish their revenue requirements for payments from
the RTO, but that otherwise the RTO must have the authority to file any
changes to its transmission tariff.\23\
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\20\ FERC Stats. & Regs. para. 31,089 at 31,061-63.
\21\ Id. at 31,064-68.
\22\ Id. at 31,068-73.
\23\ Id. at 31,075-76.
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a. Definition of Market Participant
We discuss below several distinct categories of rehearing requests
with respect to our definition of market participant.
Rehearing Requests
Several requests for rehearing argue against our inclusion in the
definition of market participant entities that provide transmission or
ancillary services to the RTO. With respect to the inclusion of
entities that provide transmission services, EEI, Independent
Companies, Southern Company, United Illuminating and Conectiv are
concerned that this could preclude the development of transcos and
other for-profit RTOs. For example, Conectiv argues that the definition
is circular when applied to RTOs that both own transmission facilities
and provide transmission service. Conectiv requests the Commission
clarify that the definition of market participant does not include
transcos and other for-profit RTOs. Southern Company states that in the
situation where an independent transmission company is an RTO, some
might argue that the transmission company is providing transmission
services to the RTO and would thus be a market participant. Southern
Company also argues that an
[[Page 12092]]
independent transmission company should not be a market participant
where it participates in a larger RTO with other transmission owners
and might be considered to be providing transmission services to the
RTO.
EEI requests that the Commission clarify that an RTO is not a
market participant with respect to transmission services it provides
within the RTO's boundaries, and that an independent transco should not
be deemed a market participant where it joins with others to form a
larger RTO. Independent Companies ask the Commission to clarify that
the market participant definition was not intended to include a
transmission owner that is making its transmission facilities available
through an RTO in which it holds active ownership and is not otherwise
engaged in electric generation or marketing activities.
United Illuminating asserts that pure transmission owners do not
have the incentive or ability to favor their power marketing
activities, and they do not participate in the energy or ancillary
services markets. United Illuminating also states that there appears to
be no reason to include in the definition of market participant a
transmission owner that provides transmission service to an RTO,
because that service would be provided according to the protections of
a regulated tariff. United Illuminating also claims that the part of
the market participant definition that includes any entity whose
economic or commercial interests that would be significantly affected
by the RTO's actions or decisions would automatically preclude a
transco as an RTO. United Illuminating asks that we confirm that pure
transmission owners are not market participants.
Commission Conclusion
We will grant rehearing in part, and clarification, with respect to
the definition of market participant. As noted in the Final Rule, we
use the definition of market participant as a reference point for
establishing limits on ownership (i.e., an RTO's ownership of market
participants and market participants' ownership of an RTO) and
standards for independent decisionmaking or governance, when governance
arrangements are being relied upon to ensure independence. With respect
to the inclusion in the definition of any entity that ``provides
transmission * * * services to the Regional Transmission
Organization,'' \24\ there is some confusion in what we intended. We
did not intend that a ``pure transmission company'' \25\ that qualified
to be an RTO would be thought to be providing transmission services to
the RTO within our definition of market participant. Additional issues
may arise as to the fairness of an RTO's governance, however, where a
pure transmission company is only one of several entities providing
transmission services to or making transmission facilities available to
the RTO. We now realize that our attempt to address these additional
issues through the definition of market participant has caused
unnecessary confusion. Accordingly, we will revise the definition of
market participant at Sec. 35.34(b)(2)(i) to delete specific references
to entities that provide transmission services to the RTO.
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\24\ Section 35.34(b)(2)(i).
\25\ We use the term ``pure transmission company'' to refer to a
transmission company that owns transmission facilities but has no
interests in or affiliation with sellers or brokers of electric
energy.
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While we are revising section 35.34(b)(2)(i) to drop specific
references to entities that provide transmission services to the RTO in
the definition of market participant, the involvement of a pure
transmission company in RTO decisionmaking processes may be relevant to
our independence criterion, and we cannot conclude that such
involvement would never be problematic. For example, in the ISO
context, we have set out the general principle that decisionmaking
processes should be independent of any market participant or class of
participants. The fact that a pure transmission company is no longer
included in the definition of market participant does not mean that the
governance of an ISO would be unaffected by the voting rights
attributed to pure transmission companies (or, indeed, pure
distribution companies who are also not included in the definition of
market participants). Accordingly, we emphasize that our revision to
the definition of market participant is not intended to prejudge the
issues or considerations that may be raised with respect to governance
arrangements involving, in part, pure transmission companies.
We note that pursuant to section 35.34(b)(2)(ii), the Commission
can find on a case-by-case basis that an entity that has economic or
commercial interests that would be significantly affected by the RTO is
a market participant. As we stated in the Final Rule with respect to
power buyers and with respect to pure distribution entities, there may
be circumstances where a transmission entity that obtained a
controlling interest in an RTO could manipulate access and curtailment
decisions, or planning and expansion decisions, in a way that would
advantage itself and disadvantage other users.\26\ We can and will deal
with those potential situations on a case-by-case basis.
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\26\ FERC Stats. & Regs. para. 31,089 at 31,062-63.
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United Illuminating makes the point that a pure transmission
company that either is an RTO, or is part of an RTO, would likely have
economic or commercial interests that would be significantly affected
by the RTO's actions or decisions, thus making it fall within the
definition of market participant under section 35.34(b)(2)(ii). We
clarify that pure transmission companies will not be within the scope
of section 35.34(b)(2)(ii) solely because of their ownership of
transmission facilities.
Rehearing Requests
Several requests for rehearing also ask for clarification and/or
rehearing with respect to the inclusion in the definition of market
participant of entities that provide ancillary services to the RTO. EEI
argues that there is a conflict between requiring the RTO to be the
provider of last resort of ancillary services and including ancillary
service providers in the definition of market participant. EEI states
that this is a problem not only with RTOs that are transcos, but also
where an ISO requires a transmission-owning member to provide ancillary
services. EEI also asserts that the definition will interfere with an
RTO's ability to run or administer an energy market. Independent
Companies assert that the definition of market participant
appropriately includes those entities providing generation-related
ancillary services to the RTO, but should not be interpreted to include
a transmission owner's provision of scheduling and dispatch services to
the RTO.
Southern Company argues that an independent transmission company
may find it beneficial to own limited amounts of generation to operate
an effective and efficient transmission system, and that it should be
allowed to own such ``non-competitive'' generation without being
considered a market participant.
Commission Conclusion
With respect to the part of the market participant definition that
encompasses an entity that provides ancillary services to the RTO, we
offer a clarification. Order No. 2000 requires under Function 4 that an
RTO serve as a provider of last resort of all ancillary services
required by Order No. 888 and subsequent
[[Page 12093]]
orders. As the provider of last resort for ancillary services, the RTO
must ensure that adequate arrangements are in place for the provision
of ancillary services to transmission customers. We recognize that
there are many different ways that ancillary services can be made
available, e.g. through contractual arrangements and market mechanisms.
We did not intend that an RTO that was fulfilling its obligation to be
a provider of last resort of ancillary services would be considered to
be providing ancillary services to the RTO. Rather, that obligation is
to provide ancillary services to the transmission customers.
Accordingly, we clarify that an RTO that provides ancillary services
within its region pursuant to its obligation under Function 4 will not
itself be considered to be within the definition of market participant
because of its performance of that function.
In addition, we clarify that our concern with the provision of
ancillary services to the RTO is focused on generation-related
ancillary services. Our concern, as we stated it in Order No. 2000, is
that the RTO will likely have considerable discretion in defining the
types and quantities of ancillary services needed and how they will be
procured, and we did not want the suppliers of ancillary services to be
able to influence the RTO's decisions on these issues.\27\ We continue
to believe this is a valid concern and will not delete this component
of the market participant definition with respect to any generation-
related ancillary service. However, we clarify that a pure transmission
company that performs the ``Scheduling, System Control and Dispatch
Service'' as described in Order No. 888 will not be considered to be
within the section 35.34(b)(2)(i) definition of market participant
because it performs that service.
---------------------------------------------------------------------------
\27\ Id. at 31,062-63.
---------------------------------------------------------------------------
In response to Southern Company's request that we allow independent
transcos to own ``non-competitive'' generation that ``essentially''
provides a transmission function, we note that the definition of market
participant is not framed in terms of generation ownership, but
includes entities that sell or broker electric energy, or that provide
ancillary services to the RTO. Any entity that sells or brokers
electric energy, directly or through an affiliate, is a market
participant. Also, as just discussed, any entity that provides
generation-related ancillary services to the RTO or its customers is
also a market participant.
Rehearing Requests
TDU Systems objects to the Commission's statement in Order No. 2000
that retail suppliers of last resort may request to be excluded from
the definition of market participant. TDU Systems argues that this
should not be encouraged, because suppliers of last resort can retain
substantial market share for a substantial period of time even if it
does not overtly compete for retail sales business, and the pendency of
waiver petitions at this time could be a source of disruption and
confusion.
Commission Conclusion
We did not intend to encourage such requests for waivers, but at
the same time, we feel compelled to recognize the possible situation
where a distribution company may desire to exit the sales business and
become a pure distribution company, but cannot due to an obligation to
be the supplier of last resort under a state retail access program. We
concluded that these entities would be within the definition of market
participant, unless they could show us special factors as to why they
should not (e.g. its sole electric sales are to satisfy a state
requirement and it does not compete for retail load).\28\ Certainly,
any seller of electric energy will carry a substantial burden to prove
to us that it should not be considered to be a market participant. We
expect that this will apply to a relatively narrow class, and we should
not be overwhelmed by waiver requests. Accordingly, we will not accept
TDU Systems' request that we withdraw our statements in the Final Rule.
---------------------------------------------------------------------------
\28\ Id. at 31,063.
---------------------------------------------------------------------------
b. Ownership Issues
In the Final Rule, we discussed at some length the requirements we
believed were necessary to ensure that ownership interests in RTOs
would not jeopardize the independence of RTOs from market
participants.\29\ We concluded: that truly passive ownership interests
by market participants would not be restricted; that active ownership
by market participants would have to cease after five years (with an
extension possible in certain circumstances); that during the time
active ownership is permitted, up to five percent ownership by a single
market participant was deemed a safe harbor and 15 percent ownership by
a class of market participants was a benchmark; and that there would
have to be periodic independent audits conducted to ensure
independence.
---------------------------------------------------------------------------
\29\ FERC Stats. & Regs. para. 31,089 at 31,064-73.
---------------------------------------------------------------------------
We discuss below the requests for rehearing and clarification that
we received on the issues of our limits on ownership generally, passive
ownership, active ownership, and auditing requirements.
Rehearing Requests
Duke objects generally to the Commission's focus on ownership,
asserting that the Commission's approach is overly rigid and that the
Commission has not examined whether there are less restrictive means to
meet the independence criterion. Duke first asks the Commission to
reconsider the structure allowed for the natural gas industry, where
affiliated production and marketing companies are permitted. Duke does
not challenge the Commission's observation that the electric industry
evidences a much higher level of vertical integration, but argues that
there is no reason to require separation of control of transmission and
merchant activities to a greater extent than is permitted in the gas
industry. Duke also suggests that the Commission could allow affiliated
transcos subject to a requirement that they retain an independent
auditor to review the activities and decisions of the affiliated
transco from the standpoint of potential discrimination and compliance
with codes of conduct and file regular reports of its findings.
Conectiv asks that the Commission clarify that the ownership
requirements do not apply to the non-profit ISO form of RTO, but would
only apply to transcos and other for-profit entities with voting
securities. It asserts that the record does not support ownership
restrictions for non-profit RTOs.
Commission Conclusion
We do not agree that the structure currently in place for the gas
industry would adequately support independent RTOs. As Duke itself
notes, it would allow the senior management of an entity that operates
in both the transmission and generation arenas to participate in
decisions involving the transmission business. These decisions would,
as a matter of course, have a significant effect on that same entity's
generation business. We also disagree that independent auditing alone
can substitute for the independence requirement. As we noted in the
Final Rule, we have found that in the electric industry, it is
difficult to monitor compliance with codes of conduct. Moreover, it is
a very intrusive form of regulation and ultimately requires us to be
``chasing after conduct.'' As we noted in the Final Rule, this is not
the light-
[[Page 12094]]
handed regulation that is essential to support emerging competitive
markets.
Conectiv's concern, which focuses at times on the distinction
between for-profit and not-for-profit entities and at other times on
the distinction between the transco and ISO form of RTO, is not
entirely clear. We clarify that our concerns about ownership and
control of an RTO are not a function of the for-profit or not-for-
profit approach. The limits on ownership by market participants apply
whenever the RTO intends to own and operate the transmission assets
itself, either directly or indirectly through other entities. The fact
that a market participant owner of an RTO operated on a non-profit
basis would not, for example, preclude the possibility that the RTO
could operate to benefit its generation business. Accordingly,
ownership restrictions are appropriate in that case.
Rehearing Requests
With respect to passive ownership, NRECA, TDU Systems, and
Dairyland argue that passive ownership should be disallowed completely
after five years, except in extraordinary circumstances. NRECA, for
example, recognizes the desirability of a transition period to phase
out passive ownership, but asserts that the maintenance of a passive
ownership threatens RTO independence and imposes heavy regulatory
burdens on the Commission to police. TDU Systems argue also that
passive ownership should be subject to the same benchmark individual
and class limits that apply to active ownership.
New Orleans also challenges the allowance of passive ownership by
market participants. New Orleans argues that the sale/leaseback cases
and the Securities and Exchange Commission Rule cited in Order No. 2000
in support of allowing passive ownership are in fact much narrower than
what the Commission is allowing, in that the passive owners there were
not primarily in the business of selling electric power. By permitting
passive ownership by market participants, New Orleans asserts, the
Commission has not provided the safeguards that exist in other passive
ownership situations. New Orleans claims that the Commission erred by
not limiting passive the same way it limited active ownership. Finally,
New Orleans asks that the Commission clarify that where there is clear
evidence that an RTO proposal would not be perceived as independent by
a majority of potentially affected entities, the proposal will be
rejected.
Duke argues that if passive ownership restrictions are retained,
the definition of passive ownership should not be so narrow as to leave
the board and management of the passive owner without the capability to
ensure that the transmission assets will be operated responsibly and in
accordance with legitimate business objectives. Duke states that if it
places its transmission into an affiliated transco, Duke's management
should be able to participate in decisions that significantly affect
the value of the transmission business, such as mergers, asset
divestitures and acquisitions, and the choice of individuals to manage
the transmission business.
EEI asks that the Commission clarify what types of passive
ownership would be acceptable. Specifically, EEI requests that the
Commission clarify that: (1) a fiduciary duty to maximize the value of
the RTO's transmission assets will not defeat independence; and (2)
passive owners may reserve certain rights to protect themselves against
abuse by the holders of voting rights. EEI argues that a fiduciary duty
to maximize transmission service revenues is similar to what the
Commission has approved in the ISO context, and that there is no duty
owed under corporate law that would require an RTO to maximize a
passive owner's outside interests. EEI states that a duty to maximize
the value of transmission assets will not create a bias toward
transmission-only solutions, because of the RTO's obligations with
respect to market mechanisms under the planning and congestion
management functions. EEI argues further that passive owners should be
able to reserve rights to participate in certain limited but major
decisions that affect their ownership status, such as mergers and
bankruptcy filings.
Commission Conclusion
We deny rehearing of the requests to phase-out or limit passive
ownership beyond what we stated in the Final Rule. NRECA is correct
that a phase-out of passive ownership, or limits on the percentage
interests of passive ownership, would reduce the regulatory burdens of
ensuring that the passive ownership arrangement does not threaten the
RTO's independence. However, as we noted in the Final Rule, passive
ownership arrangements can help resolve some significant impediments to
the transition to the type of RTO that would both own and operate the
transmission assets.\30\ Permitting flexibility on these arrangements
could enhance significantly our goal of accelerated formation of RTOs.
Limits on passive ownership interests or required phase-outs would not
further this goal. We are not convinced that the careful balance we
reached on this issue in the Final Rule is in error.
---------------------------------------------------------------------------
\30\ FERC Stats. & Regs. para. 31,089 at 31,064.
---------------------------------------------------------------------------
New Orleans' concern that we should guard against passive ownership
arrangements where there is clear evidence that an RTO proposal would
not be perceived as independent echoes the concerns we expressed in the
Final Rule.\31\ We explained in the Final Rule that this requires
assurances to all market participants that any passive ownership
arrangement is truly passive and will not interfere with the
independent operation and decisionmaking of the RTO. It is also one of
the reasons we said that it was important to require a system of
independent compliance auditing to ensure that passive ownership
arrangements remain passive over time and to provide assurances to
other market participants that the RTO is truly independent. We
appreciate New Orleans' concerns that there are differences in the
passive ownership arrangements that may be submitted as compared to
those we may have evaluated before in the context of sale/leasebacks or
those permitted under the SEC rule we referenced in the Final Rule.
However, we referenced these only to make the point that there are
different ways of structuring passive ownership arrangements and it may
be possible to structure them in such a way to demonstrate that they
are truly financial arrangements.
---------------------------------------------------------------------------
\31\ Id. at 31,065.
---------------------------------------------------------------------------
Duke's and EEI's concerns about the need of passive owners to
protect the value of their assets and investments are valid. However,
the Commission must balance these concerns against the need for an
independent RTO. We expect that proponents of passive ownership
arrangements will explore methods for protecting the value of their
assets and investments while also maintaining the true independence of
RTO decisionmaking. We recognize that this may require some creativity
and innovation to meld the regulatory needs with those of the markets,
but it is necessary if we are to ensure independent RTOs and
accommodate passive ownership arrangements.\32\
---------------------------------------------------------------------------
\32\ See, e.g., the statement of investment analyst Steven
Fetter, who said, ``The wide spectrum of permissible outcomes should
be welcomed by Wall Street. What investment bankers do best is
create innovative structures to meet legal and market
requirements.'' FERC's RTO Rule Should Cheer Investors,
www.fitchibca.com (January 13, 2000).
---------------------------------------------------------------------------
In response to EEI's concerns, we do not expect that a fiduciary
responsibility of the RTO to its passive owners to maximize the value
of the RTO's
[[Page 12095]]
transmission assets would, by itself, be problematic with respect to
the RTO's independence.
Rehearing Requests
On the issue of active ownership, Conectiv, CTA, EEI, Southern
Company, and Alliance all argue that the Commission was wrong to sunset
all active ownership after five years. EEI, representative of the
others challenging the sunset requirement, states that it is aware of
no other context where a complete ban on active ownership has been
imposed to prevent control; that the sunset requirement conflicts with
the Commission's finding that five percent active or lower does not
raise control concerns; that five years is an arbitrary and capricious
transition period; that limits on active ownership would reduce the
numbers of bidders for a transco's stock and would limit investment
opportunities for market participants; that a complete ban on active
would be difficult to monitor since there is no existing requirement to
disclose ownership less than five percent; and that the Commission does
not have the legal authority to order divestiture of ownership by
electric utilities. CTA adds that a five-percent active ownership
should be indefinite, because other holders of active interests would
prevent a five-percent minority holder from acting in its own
interests. CTA states further that the five-year transition is too
short and should be extended so as to avoid a ``fire sale'' in the
event of an economic slowdown.
TDU Systems argue that the five-percent safe harbor for individual
active ownership should be an absolute ceiling, and that the Commission
should refuse to permit a market participant to propose a higher level.
TDU Systems and NRECA both contend that intervenors should be allowed
to challenge whether even a five-percent active ownership is too high.
CTA asserts that passive ownership interests held by market
participants should not be a factor in whether a market participant
would be allowed to hold more than five-percent active ownership. It
states that if the Commission is vigilant to assure that passive
ownership cannot exercise control, there is no reason why passive
ownership should be a factor in determining appropriate active
ownership.
With respect to the 15 percent benchmark established in Order No.
2000 for a class of market participants, Conectiv, CTA, Alliance, and
EEI argue that there should be no such benchmark. They assert that it
is unlikely that class members would collude with their competitors,
that there are existing laws to prohibit collusion, and that keeping
track of the classes would be administratively difficult. EEI states
further that such aggregation of interests is not a factor in any other
regulatory context. Contrary to these parties' arguments, TDU Systems
argues that a 15 percent benchmark for classes of active owners is too
high, and that class ownership should be limited to 10 percent.
Commission Conclusion
We deny rehearing on the active ownership issues and reaffirm our
decision that active ownership by market participants will have to
cease after five years (with an extension possible in certain
circumstances), and that during the time active ownership is permitted,
up to five percent ownership by a single market participant will be
deemed a safe harbor and 15 percent ownership by a class of market
participants will be a benchmark. We carefully considered all of the
extensive arguments made in the comments on the NOPR on the active
ownership issue, and reached a solution in the Final Rule that we
continue to believe appropriately balances the interests of all parties
and our policy objective.
Many commenters argue that our willingness to allow active
ownership for five years undermines our policy against active ownership
after a five-year period. We disagree. Our decision reflects our belief
that over the long term independence may be adequately assured only if
there are no active ownership interests, but that a transition period
during which active ownership in limited amounts may be proposed,
together with auditing requirements, is a reasonable interim measure to
assist RTO formation. With respect to the 15 percent benchmark for
classes of active ownership, we explained fully in the Final Rule what
are concerns are,\33\ and we are not persuaded that our concerns are
invalid. Moreover, we have permitted sufficient flexibility for parties
to argue on a case-by-case basis that the 15 percent class benchmark is
too high or too low.
---------------------------------------------------------------------------
\33\ FERC Stats. & Regs. para. 31,089 at 31,072.
---------------------------------------------------------------------------
Rehearing Requests
With respect to the independence audits required by Order No. 2000,
Dynegy argues that the audits should commence immediately at RTO start-
up, not be delayed for two years, and should be ongoing. Dynegy states
that it has concerns about whether an audit performed two years after
start-up is sufficient to guard against ownership abuses. Dynegy asks
additionally that the Commission either place the audit and ownership
requirements in the regulation or provide clarification as to why they
do not appear in the regulations. TAPS expressly endorses the audit
requirements as essential.
Commission Conclusion
No party has objected to having independent audit requirements for
passive interests, active interests, and ISO governance, and we
continue to believe they are essential. In response to Dynegy, it is of
course a judgment as to how often to have them and how soon to start
them. We note that the Final Rule provides for the first audit two
years after our approval of the RTO, not after RTO start-up. We believe
we have struck an appropriate balance among the goals of having a
sufficient check on independence, allowing time for some initial
operational shake-out, and not imposing overly burdensome procedures.
We agree with Dynegy that it would be useful to state the auditing
requirements in the text of the regulations, and we have therefore
added a new sub-paragraph (iv) to section 35.34(j)(1) for this purpose.
The new regulatory text we added reads as follows:
(iv)(A) The Regional Transmission Organization must provide:
(1) With respect to any Regional Transmission Organization in
which market participants have an ownership interest, a compliance
audit of the independence of the Regional Transmission
Organization's decision making process under paragraph (j)(1)(ii) of
this section, to be performed two years after approval of the
Regional Transmission Organization, and every three years
thereafter, unless otherwise provided by the Commission.
(2) With respect to any Regional Transmission Organization in
which market participants have a role in the Regional Transmission
Organization's decision making process but do not have an ownership
interest, a compliance audit of the independence of the Regional
Transmission Organization's decision making process under paragraph
(j)(1)(ii) of this section, to be performed two years after its
approval as a Regional Transmission Organization.
(B) The compliance audits under paragraph (j)(1)(iv)(A) of this
section must be performed by auditors who are not affiliated with
the Regional Transmission Organization or transmission facility
owners that are members of the Regional Transmission Organization.
We also note that we stated in Order No. 2000 that applicants have
a continuing obligation to inform the
[[Page 12096]]
Commission of any changed circumstances regarding ownership.\34\
---------------------------------------------------------------------------
\34\ Id. at 31,067, 31,072.
---------------------------------------------------------------------------
c. Section 205 Filing Rights
In the Final Rule, we attempted to balance our desire to ensure
that the RTO have exclusive and independent authority over changes to
its transmission tariff with the FPA section 205 rights of public
utility transmission owners to seek rate changes.\35\ We affirmed that
RTOs, in order to ensure their independence from market participants,
must have the independent and exclusive right to make section 205
filings that apply to the rates, terms, and conditions of transmission
services over the facilities operated by the RTO. However, we also
clarified that the transmission-owning public utilities whose
facilities are used by the RTO have the right to make section 205
filings to establish their revenue requirement and the level of
payments for use of their facilities. We also stated that we would also
entertain other approaches as long as they ensured the independent
authority of the RTO and the ability of transmission owners to protect
the level of the revenue needed to recover the costs of their
facilities.
---------------------------------------------------------------------------
\35\ See id. at 31,075-76.
---------------------------------------------------------------------------
Rehearing Requests
A number of parties requested rehearing or clarification
challenging our division of section 205 filing rights between the RTO
and transmission-owning members of the RTO.\36\ For example, EEI
reflects most of the rehearing requests on this issue in arguing that
the division violates the transmission owners' section 205 rights. EEI
claims that it will jeopardize cost recovery for the transmission
owners because it breaks the link between establishing the revenue
requirement and establishing rate design, and it further breaks the
link between the party responsible for establishing the revenue
requirement and the party responsible for recovering it. EEI argues
that the RTO might not have the same incentive to design rates to
recover costs as the transmission owner would, and that the division is
inconsistent with court and Commission precedent. EEI states that this
division will discourage the voluntary participation in RTOs, and is in
fact inconsistent with at least some of the ISOs approved to date.
---------------------------------------------------------------------------
\36\ Conectiv, Duke, Southern Company, EEI, ISO Participants,
United Illuminating, Transmission Owners of NY, AEP, PECO and
Alliance.
---------------------------------------------------------------------------
Alliance contends that the Commission erred in determining that the
RTO must have exclusive authority to propose changes in rates. In
addition to similar arguments that EEI made about this unlawfully
depriving public utilities of section 205 rights and increasing the
risks for transmission owners, Alliance argues that it is a false
premise that the RTO needs exclusive authority over rates. It states
that Commission oversight of rates will provide a complete check on the
ability of transmission owners to implement rate changes that would
place them at a competitive advantage vis-a-vis other market
participants.
Conectiv argues that the division of filing rights is inconsistent
with the law (and could result in an unconstitutional taking of
property), that the Commission has provided insufficient factual basis
in the record to support its assertion that RTOs must have the
authority to file rate changes in order to ensure independence from
market participants, and that it does not provide sound economic and
transmission policy. Conectiv states that a disinterested RTO might not
make decisions based on the revenue recovery needs of the transmission
owner, and that non-profit RTOs do not have incentives to file
innovative rate design proposals to protect and encourage transmission
investment. ISO Participants also assert that the division of authority
is inconsistent with the Commission's endorsement of innovative rates.
Midwest ISO Participants ask the Commission to clarify that it need
not modify its Commission-approved ISO documents on the issue of
section 205 filing rights in order to qualify as an RTO. They state
that the Midwest ISO Agreement carefully delineated the rights of the
ISO and transmission owners, with the owners controlling the pricing
structure and revenue distribution methodology. They assert that this
was a critical element of the ISO Agreement, and the Commission
explicitly stated in its order that it would honor the transmission
owner's rights during the six-year transition period after start-up.
Midwest ISO Participants contend that Order No. 2000's requirement that
the RTO make section 205 filings to recover costs from transmission
customers is at odds with the Midwest ISO owners' rights to control
filings to change the ISO's rates. They claim further that Order No.
2000's division of authority makes no sense in the context of the
Midwest ISO's tariff, which contains a rate formula. They request that
the Commission make clear that the owners can continue to control the
rate formula.
PECO asks for clarification of how the proposed division of filing
authority would apply to situations like the PJM tariff, which is a
combined ISO and transmission owner tariff. They claim that Order No.
2000 would effectively bar the PJM transmission owners from making
changes to the tariff sheets that contain their individual revenue
requirements. They ask the Commission to clarify that in such a case
the transmission owners can still make section 205 filings to propose a
change to the tariff pages that cover their revenue requirements. PECO
also asks the Commission to clarify that any section 205 filing by an
ISO type of RTO would be subject to the established ISO governance
process.
SRP asks the Commission to clarify that its discussion of section
205 filing rights was not intended to broaden the applicability of
section 205 to non-jurisdictional public power entities, and to clarify
the ability of such non-jurisdictional entities to set the level of
their revenue requirements. SRP wants the Commission to clarify that it
intends to allow flexibility for non-jurisdictional entities to be able
to set their revenue requirements through means other than making
section 205 filings, which would mean in SRP's case, that its
independent board could continue to set its revenue requirement.
Commission Conclusion
The Commission will deny rehearing of its decision that an RTO, in
order to ensure its independence, must have the independent and
exclusive right to make section 205 filings with respect to the
transmission services the RTO provides to third parties. As discussed
below, we reject arguments that this decision is inconsistent with law
and precedent. However, in light of the concerns and misunderstandings
raised, we also will further clarify our requirement.
As noted in Order No. 2000, and as evidenced by the comments of the
parties seeking rehearing, unique issues arise with respect to tariff
filing rights in the situation where the RTO operates and provides
transmission service over transmission facilities owned by another
entity, e.g., in the context of an ISO. There are two legitimate
concerns here that need to be balanced. One is the concern that for the
RTO to provide transmission service independent from market
participants, it must have independent control over its tariff, and not
have a tariff that is subject to the control of particular participants
in the RTO. The other concern is that of transmission owners who will
turn the operation of their transmission facilities over to the RTO and
need some assurance that they will continue to receive a fair return on
their transmission investments. We
[[Page 12097]]
reconciled those concerns in the Final Rule by stating that in the ISO
type of situation, the RTO had to have the independent and exclusive
right to make section 205 filings that apply to the rates, terms, and
conditions of transmission services over the facilities operated by the
RTO, but that transmission owners have the right to make section 205
filings to determine the appropriate payments for the RTO's use of
their facilities.
As an initial matter, some parties question whether, to ensure
independence, it is necessary for the RTO to have exclusive and
independent authority with respect to filing changes to its tariff. We
find the need to be clear. The tariff establishes the rates, terms, and
conditions under which the RTO will provide transmission service to
transmission customers. If the RTO does not have the independent right
to seek appropriate changes to its tariff, it is difficult to see how
that RTO could be viewed as providing a transmission service that is
independent from market participants.
All of the objections to the division of authority we adopted in
the Final Rule are based on the false premise that we are restricting
the rights of transmission owners to protect their transmission
investments and therefore jeopardizing their asserted right to recover
their legitimate costs. This is not the case. Under our formulation,
transmission owners may make section 205 filings at any time to
establish their revenue requirements and the just and reasonable
payments they may charge the RTO for use of their facilities. This
gives them the full opportunity to recover their cost of service.
Those requesting rehearing, however, insist that transmission
owners will be at risk for not recovering their allowed payments from
the RTO, because the RTO either will not have an appropriate rate
design or will not have the incentive to collect revenues from
transmission customers sufficient to cover the payments to transmission
owners. These arguments have no merit. There is nothing in the Final
Rule that precludes transmission owners from seeking to assure recovery
of their allowed payments from the RTO through appropriate mechanisms
in the agreement establishing the RTO. For example, they may provide
for a contractually enforceable obligation for the RTO to pay the
owners their full revenue requirement as determined by the Commission,
and they may even provide for some sort of true-up mechanism if an RTO
fails to recover the costs it owes to the owners in a particular
period.
In addition, nothing in the Final Rule precludes the transmission
owners from participating in the RTO's designing of rates to
transmission customers, as long as they are not given veto authority
over, or otherwise control, what the RTO ultimately seeks to file under
section 205. The Commission did not intend to preclude transmission
owners from being involved in rate design proposals prior to the RTO
filing them. If, in designing rules to establish a new RTO (or to
justify rules of an existing ISO for which an RTO determination is
sought), parties can establish an approach or process for involving the
transmission owners in advance in the determination of the rate design
proposals that the RTO will file, and can demonstrate that the approach
or process does not compromise the independence of the RTO, the
Commission will be open to such proposals.\37\
---------------------------------------------------------------------------
\37\ In this situation, parties may also consider providing for
mutually agreeable rules regarding the timing of the revenue
requirement and rate design filings.
---------------------------------------------------------------------------
In addition, when the RTO proposes a rate design to recover the
costs the RTO owes to the transmission owners as well as other costs
that the RTO may incur, the Commission will exercise its
responsibilities to approve a rate that is designed to recover all RTO
costs, including the cost of payments that the RTO must make to the
transmission owners. Transmission owners will be able to participate in
that proceeding and to make whatever arguments they wish regarding
appropriate rate design and the effect on their recovery of costs.
Most of the parties asserting legal challenges on this issue,
including EEI, spend considerable effort reciting the basic rate
changing mechanisms of section 205 of the FPA, and claim an inalienable
right of a transmission owner to make rate changes even in the
situation in which they no longer control the transmission facilities
and are no longer the parties providing service over the facilities.
They claim they are owed a ``guarantee'' of recovering the costs of the
facilities which have been turned over to the RTO.
We reject the legal arguments made by those on rehearing. The
Commission's holding in Order No. 2000 did nothing contrary to the
fundamental tenets of section 205 of the FPA and nothing inconsistent
with the rights of utilities to have the opportunity (as opposed to a
``guarantee'') to recover costs associated with facilities used to
provide jurisdictional service. What the rehearing petitioners ignore,
and what the Commission pointed out in Order No. 2000, is that in the
context of an ISO, both the transmission owners and the RTO are public
utilities under the FPA with respect to the same facilities. Further,
it is the RTO, and not the transmission owners, that in this context is
the provider (seller) of jurisdictional service. Because the RTO is
providing the jurisdictional service, it is clearly within the
parameters of section 205 for the RTO to have on file a rate schedule
for the services it provides, and that it have the exclusive authority
to propose changes to that rate schedule.\38\
---------------------------------------------------------------------------
\38\ This is analogous to the situation in which there is a sale
and leaseback of public utility property for financing purposes. In
such a case, it is the lessee operator, not the owner, that files
tariffs.
---------------------------------------------------------------------------
Given that it deprives no public utility of the opportunity to
recover its costs and earn a fair return on its investments, the
section 205 filing procedure adopted in Order No. 2000 is well within
the Commission's authority. The Supreme Court has stated that the
Commission ``must be free, within the limitations imposed by pertinent
constitutional and statutory commands, to devise methods of regulation
capable of equitably reconciling diverse and conflicting interests.''
\39\ That is what we have done here.
---------------------------------------------------------------------------
\39\ Permian Basin Area Rate Cases, 390 U.S. 747, 767 (1967).
The Supreme Court in this case also rejected the notion that there
is an unrestricted right to file rate changes under section 4(d) of
the Natural Gas Act, which is parallel to section 205(d) of the FPA.
Id. at 779-80.
---------------------------------------------------------------------------
Several existing ISOs seek in their rehearings to have the
Commission make specific findings with respect to their current
division of section 205 filing rights. We do not believe it is
appropriate to make such findings in this generic proceeding and
instead will do so when those entities make their filings under this
rule. We note that we stated in the Final Rule that we would entertain
other approaches to the division of filing authority ``as long as they
ensure the independent authority of the RTO to seek changes in rates,
terms or conditions of transmission service and the ability of
transmission owners to protect the level of the revenue needed to
recover the costs of their transmission facilities.'' \40\
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\40\ FERC Stats. & Regs. para. 31,089 at 31,076.
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In response to SRP's request for clarification of the applicability
of our finding to non-public utilities, we clarify that our discussion
of filing rights pertained to public utilities under section 205 of the
FPA and that it was not intended to broaden the applicability of
section 205 to non-public utilities.
[[Page 12098]]
In response to arguments that the Commission's decision will
discourage the voluntary formation of RTOs or will result in favoring
transcos over ISOs, the intent of this rule is to be neutral as to
corporate form. As we stated above, we have left sufficient flexibility
for transmission owners to protect their revenues, obligations to
shareholders, and ability to attract capital whether they form an ISO,
transco, or other form of institution.
Some parties have argued that our decision undermines the incentive
to use performance based rates in the ISO context because it takes the
development of such mechanisms out of the hands of the transmission
owners. We do not think this is a necessary result. As we noted in the
Final Rule, when activities that contribute to performance are shared
between the RTO and the transmission owners, the RTO design may ensure
that the rewards and penalties associated with activities performed by
transmission owners flow through to the owners to achieve the desired
result.\41\
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\41\ Id. at 31,184.
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2. Scope and Regional Configuration
Order No. 2000 set forth as the second minimum characteristic of an
RTO that the RTO must serve a region of sufficient scope and
configuration to permit it to maintain reliability, effectively perform
its required functions, and support efficient and non-discriminatory
power markets.
Rehearing Requests
The Pennsylvania Commission asks that the Commission ensure that
RTOs are large enough to support an open and transparent market in
reactive power and other ancillary services. It states that RTO
applicants should be able to demonstrate that the geographic area and
diversity of ownership of generation and transmission facilities is
sufficient to support such a market.
Commission Conclusion
We agree with the Pennsylvania Commission that one of the
considerations in evaluating scope and regional configuration is
whether the RTO can support open and transparent markets, including
ancillary service markets.
3. Short-Term Reliability
The Final Rule required as the fourth minimum characteristic of an
RTO that the RTO have exclusive authority for maintaining the short-
term reliability of the grid. As part of this characteristic, the
Commission stated that the RTO must have exclusive authority for
receiving, confirming, and implementing interchange schedules; must
have the right to order redispatch of generation for reliability
purposes; must have authority to approve transmission maintenance
schedules; and must report to us if any reliability standards it
operates under hinder it from providing reliable, non-discriminatory
and efficiently priced transmission service. We did not require that
the RTO have authority over generation maintenance schedules or that
the RTO be required to establish transmission facility ratings. We also
stated that on the issue of the extent of RTO liability relating to its
reliability activities, we would address that on a case-by-case
basis.\42\
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\42\ FERC Stats. & Regs. para. 31,089 at 31,103-05.
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Rehearing Requests
Dynegy and TAPS are concerned with the information received by
control area operators who are market participants when they are
directed to implement interchange schedules by the RTO. Dynegy agrees
with the protections provided in the rule for separation of reliability
personnel and wholesale merchant personnel, but asks the Commission to
clarify that it will actively monitor compliance and enforce
appropriate penalties for violations. TAPS objects to limiting the
shield from sensitive interchange information to the control operator's
wholesale merchant personnel. It states that this would allow for a
market participant control area operator to share with its retail
merchant function to take improper advantage of the commercially
sensitive information. It asks that the Commission make clear that such
information must be kept from all personnel involved with making
purchases on the wholesale market, whether on behalf of wholesale or
bundled retail customers.
Dynegy asks that the Commission clarify that to the extent a
generator is redispatched by an RTO, it will be fully compensated for
the redispatch order, which may include lost opportunity costs.
Metropolitan asks that the Commission clarify that if an RTO
reschedules or cancels planned transmission maintenance, the
compensation will be limited to direct costs, and will not include
indirect costs such as opportunity costs, because they are too
speculative.
TAPS argues that certain functions that Order No. 2000 does not
require the RTO to have for reliability purposes in fact should be
required. TAPS contends that the RTO should be required to have a
greater voice in transmission facility ratings in order to have control
over ATC and TTC calculations. TAPS also contends that the RTO should
have, at least for reliability reasons, control over generation
maintenance schedules.
Duke calls the Commission's decision to decide liability
responsibility on a case-by-case basis arbitrary and capricious. It
states that transmission owners cannot be expected to transfer control
of their facilities to what could be a non-profit RTO with limited
assets without resolving the issue of the RTO's liability for its
errors. Duke asks that the Commission clarify that it will not permit
RTO operations to begin without a final resolution of liability issues,
and that the RTO would not be given unilateral authority to alter the
liability provisions of its tariff.
Commission Conclusion
We agree with Dynegy that it may be necessary to monitor and
enforce compliance with the requirement for separation of reliability
and merchant personnel. We expect that any RTO proposal would address
this issue and propose appropriate and specific procedures concerning
monitoring and enforcing compliance with all RTO rules, including
these.
We share TAPS concerns that, when the retail merchant function is
purchasing wholesale power, it is participating in the wholesale market
and should not be privy to commercially sensitive information that
would give it a competitive advantage over other purchasers of
wholesale power. We expect that any RTO proposal will reflect these
concerns to the extent it involves a control area operator affiliated
with a market participant who could obtain access to commercially
sensitive information.
We agree with Dynegy that generators that are redispatched by an
RTO should be fully compensated and that the compensation would
consider, among other things, lost opportunity costs. We also agree
with Metropolitan that, when the RTO reschedules or cancels planned
transmission maintenance, compensation to the transmission owners would
be limited to the actual, verifiable out-of-pocket transmission-related
costs incurred (e.g., additional labor costs caused by the
rescheduling).
In the Final Rule, we explained why we believe it is appropriate
not to require, as an initial matter, that the RTO have authority over
equipment ratings and generation maintenance schedules. While we expect
that some RTO proposals may initially exceed our requirements or may
evolve over time to place greater responsibility with the
[[Page 12099]]
RTO, we will not impose the additional requirements proposed by TAPS.
We continue to believe that liability issues should be addressed on
a case-by-case basis. We agree with Duke that it is important that
issues concerning liability and how liability provisions can or cannot
be changed over time should be addressed during the collaboration
process and resolved before the RTO begins operation. In this regard, a
public utility can seek a declaratory order or make an RTO filing and
have the liability issues resolved before the commencement of
operations.
C. Minimum Functions of an RTO
1. Tariff Administration and Design
In the Final Rule, we adopted the requirement that the RTO must be
the sole provider of transmission services and the sole administrator
of its open access tariff.\43\ Included in this function is the
requirement that the RTO have the sole authority for the evaluation and
approval of all requests for transmission service including requests
for new interconnections.
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\43\ See FERC Stats. & Regs. para. 31,089 at 31,108.
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Rehearing Requests
Duke and EEI request clarification that the requirement that the
RTO be the sole provider of all transmission service is not intended to
require unbundling of non-jurisdictional transmission service. Duke
argues that given the Commission's lack of jurisdiction over bundled
retail transmission, the Commission has no power to indirectly require
the unbundling of retail energy sales through a rulemaking. Duke
proposes the following change to section 35.34(k)(1)(i): ``The Regional
Transmission Organization must have the sole authority to receive,
evaluate, and approve or deny all requests for wholesale transmission
service.''
Dynegy also seeks clarification from the Commission as to the
requirement that the RTO be the provider of transmission service.
Dynegy requests guidance as to the level of flexibility contemplated by
the Commission for this requirement in situations where an umbrella
RTO-transco structure is adopted. Dynegy envisions a paradigm where an
interconnection-wide entity determines and/or arbitrates questions of
system capacity and acts a scheduler, but the RTO actually owns and
maintains the facilities and performs the dispatch. Under this
scenario, Dynegy points out that depending on the perspective, either
entity can be the provider of transmission service. In addition, SoCal
Edison requests clarification that a two-tariff model (e.g., RTO/ISO
tariff and transmission owner tariff), whereby transmission owners
continue to sell transmission service that is provided by an RTO, is an
acceptable option for RTOs.
In addition, a number of entities requested rehearing or
clarification on an RTO's authority over interconnections to the grid.
For example, Metropolitan and SoCal Edison request that the Commission
modify Order No. 2000 to clarify that an RTO has no interconnection
authority over transmission facilities it does not own or have
operational control of. Metropolitan is concerned that some systems
within an RTO region that are not under the operational control of the
RTO are already subject to arrangements with adjoining control areas
and transmission owners. In addition, Metropolitan notes that public
power systems may not be able to resolve legal or tax concerns in order
to permit their facilities to be controlled by an RTO.
SoCal Edison also argues that the Commission erred to the extent it
provided RTOs sole authority to approve requests for interconnections.
SoCal Edison notes that FERC, not RTOs, has the authority to approve
and evaluate interconnections, pursuant to sections 202(a) and 210 of
the FPA. SoCal Edison asserts that transmission owners must remain an
integral part of the interconnection process. According to SoCal
Edison, the text of the Final Rule should be amended as follows: ``The
Regional Transmission Organization must have the authority to establish
interconnection policies and to coordinate the interconnection process
for new interconnections.''
EPSA asserts that the Commission failed to expound upon the role of
RTOs vis-a-vis other transmission owners in facilitating new
interconnections. According to EPSA, in order to ensure non-
discriminatory interconnection processes for all generators, the
Commission should establish the RTO as the lead agency for new
interconnections, with individual transmission owners' roles limited to
performing studies on behalf of the RTO. EPSA contends that the RTO
must be capable, within a reasonable time frame, of performing the
necessary transmission studies and analyses that are required with
respect to requests for new interconnections. EPSA also argues that new
generators should not be required to commit to a particular level or
type of transmission service in order to obtain interconnection
service. In addition, EPSA proposes the development of a standardized
interconnection agreement that would hasten the development of new
generation and streamline the interconnection process. EPSA argues that
this application process for evaluating interconnection requests and
for processing the requests must be applied in a consistent and non-
discriminatory manner.
Dynegy supports the positions set forth by EPSA in its request for
rehearing on this issue. Dynegy urges the Commission to require, at a
minimum, that any RTO proposal clearly address the nature and scope of
the RTO's responsibility for the interconnection of new generators to
the transmission grid, and clarify that new generators will not be
required to negotiate separately with both the RTO and individual
transmission owners.
Finally, EEI requests that the Commission clarify that any RTO
authority over new interconnections does not interfere with the right
to recovery of costs of new interconnections under section 205 of the
FPA.
Commission Conclusion
We will not revise section 35.34(k)(1)(i) as proposed by Duke to
limit it to wholesale transmission service. The proposed revision would
disable the RTO from performing those retail transmission services that
are already included in our pro forma tariff, i.e., unbundled retail
transmission that may occur, voluntarily or as the result of state
action, on the system of the historical bundled retail supplier, or
unbundled retail transmission service provided by other transmission
providers that constitute more remote segments of a multi-system
transmission transaction.
However, we clarify that the Final Rule is not intended to require
the unbundling of non-jurisdictional transmission service (i.e., the
transmission component of bundled retail sales of energy). That is, the
requirement does not interfere in any way with whether retail open
access and retail choice are provided, or with the pricing of retail
bundled power sales which is a decision for appropriate state
authorities. However, the requirement is intended to require that the
RTO control all transmission facilities in the region. This is
consistent with what the Commission has done with respect to ISOs in
the past. As Duke notes, the Commission has addressed in the context of
existing ISOs, issues surrounding the fact that a transmission owner's
assets continue to be used to provide bundled retail power sales. For
example, in PJM, the Commission noted that, when transmission owners
engaged
[[Page 12100]]
in transactions under the PJM Tariff to meet retail load, they would
be, at the same time, using their transmission system to make bundled
retail sales and using the transmission system of the other
transmission owners, e.g., to import power to their system for the
purpose of making bundled retail sales.\44\ We note that, to date,
according to one analysis,\45\ approximately 40 percent of the nation's
electricity sales to ultimate customers utilize transmission systems
that are participating or have agreed to participate in Commission-
approved ISOs without implicating the continuing jurisdiction of state
commissions over bundled retail power sales. In short, we have
accommodated ISOs that provide service at wholesale as well as at
retail, and in states that have retail choice as well as states that do
not have retail choice, and we have done so without a conflict between
state and Federal authority.
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\44\ Pennsylvania-New Jersey-Maryland Interconnection, L.L.C.,
81 FERC para. 61,257 at 62,281-82 (1997).
\45\ See Initial Comments of Edison Electric Institute on the
RTO NOPR, at Appendix B.
---------------------------------------------------------------------------
In response to Dynegy's concerns, we do not see any inconsistency
in our requirement that the RTO be the provider of transmission service
and our flexibility to allow various RTO structures. We believe that
some of this concern arises from the meaning of the term ``provider of
transmission service.'' When we use the term provider of transmission
service in this context, we are referring to the entity (i.e., the RTO)
that has the primary obligation to ensure that transmission service is
provided, not the entity that may be operating the switches at the
direction of the RTO.
In response to SoCal Edison's request for a clarification on the
``two-tariff'' model, it would be inappropriate to consider in the
Final Rule the specifics of whether a particular aspect of an existing
ISO arrangement would satisfy the RTO requirements. We emphasize,
however, that we have created a Final Rule that provides clear guidance
as to the RTO requirements and extensive flexibility in how to satisfy
those requirements.
The concerns raised by Metropolitan and SoCal Edison with respect
to an RTO's authority over interconnections to the grid have two
facets. First, some facilities may not be under the control of the RTO
because they are owned by an entity that has not placed any facilities
under the control of the RTO, e.g., a public power entity. We agree
that the RTO would not have authority over interconnections to that
portion of the grid. Second, some facilities may not be under the
control of the RTO even though they are owned by an entity that has
placed other facilities under the control of the RTO. For example, in
the NEPOOL region, only Pool Transmission Facilities (PTF) were placed
under the control of ISO-NE. However, ISO-NE nonetheless has authority
over interconnections to non-PTF transmission facilities. We would
expect similar arrangements to be part of any RTO proposal.
We disagree with SoCal Edison's point that RTOs can exercise no
authority over interconnections because that authority resides only
with the Commission under sections 202 and 210 of the FPA. An
interconnection obligation is an element of transmission service and is
already required to be provided under our pro forma tariff that will be
administered by the RTO.\46\ As EPSA notes, this is true, whether the
interconnection request is tendered concurrently with a request for
transmission service or in advance of a request for a specific
transmission service.\47\ It is therefore appropriate for the RTO to be
the entity that reviews and approves interconnection requests. However,
we agree with SoCal Edison that transmission owners must remain an
integral part of the interconnection process. We also agree with Dynegy
that new generators should not have to negotiate separately with the
RTO and individual transmission owners. We expect one-stop shopping
under any RTO.\48\ Finally, we agree with EEI that the RTO's authority
over new interconnections does not suggest that entities incurring
costs to provide those interconnections will not be compensated.
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\46\ PJM Interconnection, L.L.C., 87 FERC para. 61,299 (1999),
reh'g denied, 89 FERC para. 61,186 (1999).
\47\ See Ameren Operating Companies, 89 FERC para. 61,041
(1999), order on reh'g, 89 FERC para. 61,208 (1999); Central Hudson
Gas & Electric Corporation, et al., 88 FERC para. 61,138 (1999).
\48\ See id.; New England Power Pool, et al., 87 FERC para.
61,043 (1999).
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2. Congestion Management
In the Final Rule, the Commission concluded that an RTO must ensure
the development and operation of market mechanisms to manage
congestion.\49\ The market mechanisms must provide transmission
customers with efficient price signals regarding the consequences of
transmission use decisions. We asserted that these pricing proposals
should ensure that (1) the generators dispatched in the presence of
transmission constraints are those that can serve system loads at least
cost and (2) limited transmission capacity is used by market
participants that value that use most highly. The Final Rule did not
prescribe a specific congestion pricing mechanism; instead, RTOs have
considerable flexibility to propose a congestion pricing method that is
best suited to their circumstances.
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\49\ FERC Stats. & Regs. para. 31,089 at 31,126.
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Rehearing Requests
Dynegy argues that because congestion management is a ``hot''
topic, the Commission should hold a technical conference on issues
surrounding congestion management and RTOs.
TDU Systems requests clarification that the Commission has not
mandated or approved the auction of limited transmission capacity to
the highest bidder in all circumstances. TDU Systems asks whether the
market participant who can pay the most for the capacity is necessarily
the one who will maximize the overall societal benefits of obtaining it
and whether the entity that can afford to pay the most on that day is
the supplier who can pay the going rate specifically because it has
decided to avoid serving loads of poorer residential consumers. TDU
Systems state that, while they do not expect the Commission to have
immediate answers to these questions, they urge the Commission to make
clear that the subject remains open for discussion. TDU Systems
contends that, otherwise, unfettered reliance on market mechanisms in
transmission pricing may become a recipe for new forms of undue
discrimination.
Commission Conclusion
We deny Dynegy's request, as part of this rehearing order, to
direct a technical conference on congestion management issues. We agree
that congestion management issues may be significant and controversial
and expect that parties will use the collaboration process to tackle
these issues.
As requested by TDU Systems, we confirm that Order No. 2000 does
not mandate or pre-approve any particular form of market mechanism for
congestion management. Furthermore, we agree that congestion pricing
must satisfy the same standards as any other rate, term or condition of
service, i.e., just, reasonable, and not unduly discriminatory or
preferential. We encourage that parties use the collaborative process
to identify their concerns about congestion pricing.
3. Ancillary Services
In the Final Rule, the Commission concluded that an RTO must serve
as the provider of last resort of all ancillary services required by
Order No. 888 and
[[Page 12101]]
subsequent orders.\50\ The Commission also allowed RTOs to propose
other ancillary services in recognition of local or regional
conditions. Moreover, the Commission concluded that real-time balancing
markets are essential for the development of competitive power markets
and an RTO must ensure that its transmission customers have access to a
real-time balancing market that is developed and operated by either the
RTO itself or another entity that is not affiliated with any market
participant.
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\50\ See FERC Stats. & Regs. para. 31,089 at 31,140.
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Rehearing Requests
Steel Dynamics requests rehearing of the Commission's decision not
to establish standard definitions for energy imbalance services, and
requests a determination that an hourly assessment of such imbalances
is the proper standard for FERC-approved ancillary services. In the
alternative, Steel Dynamics requests that the Commission establish a
generic proceeding to provide guidance on the development of real-time
energy imbalance markets and energy imbalance services.
On rehearing, TDU Systems argues that backup and hour-to-hour load
following service should be added to the mandatory ancillary services
menu. In the alternative, TDU Systems requests that the Commission: (1)
Clarify that proposals to augment the Order No. 888 menu of ancillary
services offerings are appropriate subjects for negotiation during the
collaborative process; (2) clarify that the Commission will entertain
proposals by market participants as well as RTOs to augment the menu of
RTO ancillary services, whatever the outcome of the regional process;
and (3) clarify that additional ancillary services may be proposed on
bases other than local or regional conditions.
Duke seeks clarification that in the discussion of balancing the
Commission was not referring to inadvertent interchange. Duke notes
that inadvertent interchange is the integration of all of the
mismatches within a control area over a time period, typically a single
hour, while energy and generation imbalances are the integration of a
particular transmission customer's load mismatches for any particular
scheduled transmission.
EEI requests that the Commission provide congruence in the
deadlines for the deployment of both congestion management and real-
time balancing markets, a year after an RTO commences initial
operation. EEI argues that real-time information is needed to operate a
real-time balancing market and this information requires investment and
installation of metering equipment. In addition, EEI notes that
operating a real-time balancing market encompasses full coordination
across interconnections.
Commission Conclusion
We deny the request to establish a generic proceeding to provide
guidance on the development of real-time energy imbalance markets and
energy imbalance services. We agree with Steel Dynamics that these
issues may be significant and controversial and expect parties to use
the collaboration process to address these issues.
We also decline to mandate additional ancillary services as part of
this Final Rule, but we clarify that proposals for the RTO to offer
additional services is an appropriate topic for discussion during the
collaborative process. We expect that one of the benefits of RTOs is
that they will be responsive to the needs of transmission users and
consider additional services beyond those mandated in Order No. 888 for
service on an individual system basis. While market participants are
free to propose revisions to RTO proposals that are ultimately filed
with the Commission, it is preferable that these issues be thoroughly
raised and considered during the collaborative process.
We clarify that the RTO's responsibility for operating a balancing
market is intended to address the energy and generation imbalances that
are associated with customers' transactions. However, we did express
our concern that transmission users had unequal access to balancing
options depending on whether they also operate a control area. We
recognize that inadvertent interchange among control areas is intended
to address different operational matters, but there is some concern
among industry participants that control area operators have the
ability to use inadvertent interchange as a low cost source of energy
imbalance service.\51\
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\51\ We note that NERC is currently evaluating issues related to
inadvertent interchange practices and the economic incentives of
operating a control area as a source of low cost balancing options.
See Report to Board of Trustees (Feb. 7-8, 2000).
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We are not persuaded by EEI that we should extend the deadline for
real-time balancing markets. We understand that such markets may
require technological support and investment in metering equipment, but
we believe that these issues can be resolved within the current
deadline.
4. OASIS and Total Transmission Capability (TTC) and Available
Transmission Capability (ATC)
The Final Rule provides that the RTO must independently calculate
ATC and TTC values based on data developed partially or totally by the
RTO. When data are supplied by others, the Final Rule stated that the
RTO must create a system of checks and tests to ensure unbiased data
and coordination. Also, the Commission concluded that issues relating
to capacity benefit margin (CBM) were outside the scope of this
proceeding and we noted that CBM issues can be addressed in Docket No.
EL99-46-000.
Rehearing Requests
Conectiv requests clarification that a non-profit ISO, which is an
RTO, shall accept equipment ratings and other verifiable transmission
data from member transmission owners to be used in the calculation of
ATC and TTC values. Conectiv is concerned that an RTO may deny the use
of verifiable data such as equipment ratings and impose its own
different standard. According to Conectiv, the non-use of transmission
owners' verifiable data, such as equipment ratings by an RTO, may
influence transmission investment and levels of reliability on the
transmission owners' systems.
TAPS argues that the Commission should clarify that RTOs have the
authority to independently review, verify and modify CBM in setting ATC
and TTC with the RTO's CBM values controlling pending ADR. TAPS asserts
that CBM is a key component that goes into the computation of ATC and
failure to include CBM within RTO authority will make RTO authority
over ATC meaningless.
Commission Conclusion
In the Final Rule, we concluded that the RTO should calculate ATC/
TTC values based on data developed partially or totally by the RTO. In
addition, the Commission required that RTOs independently verify data
supplied by transmission owners for the calculation of ATC/TTC.
Accordingly, we agree with Conectiv that an RTO can rely on data
provided by the transmission owner provided that the data is verifiable
by the RTO.
In response to TAPS, we recognize that CBM is an important
component in calculating ATC. However, as noted in the Final Rule,
issues relating to CBM are too detailed to be addressed at this time
and should be addressed when RTO proposals are filed. We agree that
these issues need to be resolved because
[[Page 12102]]
the RTO cannot accurately compute ATC without also resolving CBM
issues.
5. Market Monitoring
In the Final Rule, the Commission concluded that market monitoring
is an important tool for ensuring that markets within RTOs do not
result in transactions or operations that are unduly discriminatory or
preferential or provide opportunity for the exercise of market power.
In section 35.34(k)(6) of the regulatory text, we outlined the minimum
standards that RTOs' market monitoring plans must satisfy. We also
provided latitude to the RTO and market participants to design a market
monitoring plan that best fits the circumstances of the RTO and the
structure and design of its power markets. In addition, the Final Rule
requires than an RTO propose an objective market monitoring plan to
assess whether the RTO's involvement in markets favors its own economic
interest.\52\
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\52\ FERC Stats. & Regs. para. 31,089 at 31,064 and 31,156.
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Rehearing Requests
PSE&G reiterates the concerns it raised in its NOPR comments about
the need for and extent of a market-monitoring function for RTOs, and
asks that it be eliminated as one of the RTO's functions. PSE&G also
notes that, while the Final Rule declined to sunset the market
monitoring function as PSE&G had proposed, it noted that as bulk power
markets evolve and become more competitive, we may revisit the need for
the type of monitoring the Rule requires. Pointing to this observation,
PSE&G proposes that the Commission at least amend the regulation to
allow the market participants the flexibility to evolve to a more
competitive state where the intrusion of a market monitor is no longer
necessary. To this end, PSE&G proposes the following language to
section 35.34(k)(6): ``(iv) The market monitoring plan may provide for
its automatic expiration within a fixed period of time, provided that
the Commission finds that the markets administered by the RTO are
operating competitively without regulatory supervision.''
Conectiv argues that the Commission erred in giving the authority
to remedy market power abuses to RTOs. Instead, Conectiv asserts that
RTOs should be limited to investigating and reporting market power
abuses. Conectiv is concerned that if an RTO is permitted to take an
enforcement role in punishing market power abuses, the RTO might create
anticompetitive effects in the market by discriminating in punishments.
Duke expresses the same concerns as Conectiv and argues that the
monitoring arm of RTOs should not be provided policing authority over
market participants. Duke contends that an RTO should only be permitted
to administer penalties and sanctions to which parties have voluntarily
agreed by contract with the RTO.
Dynegy continues to be concerned that RTOs are market participants
and therefore, Dynegy requests that the Commission clarify that the
market monitoring plans proposed by RTOs must include a plan to assess
whether the RTO is able to favor its own interests over those of its
customers or members via its involvement in markets in which it
participates. Furthermore, Dynegy requests clarification that an
objective market monitoring plan to assess an RTO's own involvement
must be performed by an independent auditor.
PP&L requests rehearing of the Commission's decision to expand the
role of RTO market monitoring to the investigation and determination of
individual market participant behavior. PP&L argues that the
Commission's responsibility to identify and address the existence and
exercise of market power and other anticompetitive activity may not be
delegated to private parties such as RTOs. PP&L asserts that the FPA
contains no authority for the Commission to delegate to private parties
the enforcement of Commission's obligations to prevent discrimination
and to regulate the public interest, and furthermore, the delegation of
investigatory and regulatory authority to private parties is disfavored
under Federal law.
EEI requests that the Commission require that market monitoring
plans evolve as market structures evolve and mature. EEI recommends
that the Commission reconsider the need for a process through which
each RTO and its market participants can regularly assess the scope of
market monitoring, the responsibilities of the monitoring unit and the
types of data and information that are necessary to effectively
monitor.
Commission Conclusion
For the reasons given in the Final Rule, we reject PSE&G's request
to eliminate the market monitoring function completely. We also reject
PSE&G's proposed modification to the market monitoring requirement.
While we agree with PSE&G that the market monitoring function may
change over time, it would be premature to assume, as PSE&G proposes,
that parties can now predict that, by a date certain, all market
monitoring functions should terminate. The Commission will periodically
assess the need and degree of market monitoring that should be done by
the RTOs. Accordingly, we agree with EEI that an important element of
any market monitoring plan may be a process that provides for the
periodic evaluation of the plan's design and effectiveness. We believe
that this is an issue that should be raised during the collaborative
process.
We believe that Conectiv's, Duke's, and PP&L's concerns about
enforcement are premature and should be addressed when specific RTO
proposals are developed and filed with the Commission.\53\ We are not
delegating our statutory authority and responsibility; however, we
believe RTOs can help us understand and identify market problems. RTOs
will be permitted to take actions only within specified parameters that
are contained in a Commission-approved tariff.
---------------------------------------------------------------------------
\53\ See New York Independent System Operator, Inc., et al., 89
FERC para. 61,196 (1999); New England Power Pool, 85 FERC para.
61,379 (1998).
---------------------------------------------------------------------------
We provide the clarification requested by Dynegy that the
requirement referenced in the Final Rule \54\ concerning a monitoring
plan to assess the RTO's involvement in markets would be proposed at
the same time as the market monitoring plan related to the markets the
RTO operates and administers.
---------------------------------------------------------------------------
\54\ FERC Stats. & Regs. para. 31,089 at 31,156.
---------------------------------------------------------------------------
6. Planning and Expansion
The Commission concluded that the RTO must have ultimate
responsibility for planning, and for directing or arranging, necessary
transmission expansions, additions and upgrades within its region that
will enable the RTO to provide efficient, reliable and non-
discriminatory service. The Final Rule recognized the statutory
authority of the states to regulate siting of transmission facilities
and we concluded that the RTO's planning and expansion process must be
designed to be consistent with state and local responsibilities. In
addition, the Commission encouraged the development of multi-state
agreements or compacts to review and approve new transmission
facilities. Moreover, the Commission recognized that the planning and
expansion function may require coordination among multiple parties and
regulatory jurisdictions and established a three year deadline for
satisfying this function.
Rehearing Requests
TDU Systems agree that transmission planning and expansion is a
vital
[[Page 12103]]
function for RTOs to perform, and on rehearing, TDU Systems argue that
RTOs should be required to be capable of performing its planning and
expansion responsibilities on the first day of RTO operation.
NY Transmission Owners seek three clarifications on planning and
expansion issues: (1) Clarify that Order No. 2000 does not displace the
legal rights of owners of the transmission assets, including the right
to propose and build expansions to transmission systems to meet
obligations under state law; (2) clarify that the Commission intends to
require RTOs to adhere to the statutory requirements under FPA sections
210, 211 and 212 concerning any mandated interconnections or
expansions, including statutory provisions respecting cost recovery;
and (3) clarify that, if an RTO directs the construction of potentially
uneconomic facilities, the transmission owners will not be required to
bear the risk of any such facilities.
Duke notes that there may be situations where, regardless of the
planning process used, and despite the best efforts of the RTO,
transmission expansion cannot be effectuated. For example, Duke states
that a state commission could choose not to participate in the multi-
state process, or decide not to grant permission to construct. In these
situations, Duke asserts that neither the Commission nor the RTO have
legal or regulatory authority to compel the state commission to act in
a different manner. Therefore, on rehearing, Duke asks that the
Commission provide that in a situation in which, despite good-faith
efforts by the RTO, certain transmission facilities cannot be built,
the RTO consequently is relieved of the responsibility placed on it for
directing or arranging necessary transmission additions and upgrades.
Likewise, EEI asks that the Commission clarify that any obligation to
upgrade or expand transmission is subject to good faith efforts to
obtain the necessary approvals under federal, state or local law.
Commission Conclusion
We agree with TDU Systems that transmission planning and expansion
are vital functions, but disagree that we can expect RTOs to be capable
of performing these functions on the first day of RTO operation.
As we understand it, NY Transmission Owners are concerned on the
one hand that they might not be compensated for any expansion that they
undertake at the direction of the RTO, and on the other hand, that they
might be precluded from expanding their systems on their own initiative
without a directive by the RTO. We agree that a transmission owner is
entitled to compensation for construction undertaken at the directive
of an RTO, and we expect that these issues will be resolved
systematically by the RTO. We also clarify that our Final Rule does not
preclude a transmission owner from expanding its system on its own
initiative; however, it would be prudent for the transmission owner in
that case to resolve compensation issues in advance with the RTO.
In response to Duke, we clarify that the transmission expansion
obligations are no greater than we established in the pro forma
tariff.\55\ States, of course, retain siting authority. However, among
the benefits of an RTO is that expansion will reflect the result of a
regional process that can involve regional regulatory authorities, and
since the transmission system will be operated regionally, there may be
more than one expansion alternative that could resolve the situation.
We expect utilities to make good faith efforts to achieve the RTO's
desired transmission expansion.
---------------------------------------------------------------------------
\55\ See, e.g., pro forma tariff provisions at sections 15.4,
19.6, 20, and 28.2.
---------------------------------------------------------------------------
7. Interregional Coordination
In the Final Rule, the Commission added a general interregional
coordination requirement as one of the minimum RTO functions.\56\ Under
this requirement, the RTO must ensure the integration of reliability
practices within an interconnection and market interface practices
among regions. The Final Rule envisioned some level of standardization
and practices, including coordination and sharing of reliability data
and data for TTC and ATC calculation, transmission reservation
practices and congestion management.
---------------------------------------------------------------------------
\56\ FERC Stats. & Regs. para.31,089 at 31,166-68.
---------------------------------------------------------------------------
Rehearing Requests
Dynegy requests expedited implementation of the interregional
coordination function and proposes the creation of an interregional
transmission system coordinator (ITSC) to accomplish the following
functions:
(1) Resolving ``physics'' issues over broad geographic regions
using flow-based modeling, thereby `` internalizing'' loop flow. This
can be accomplished by:
Expanding use of NERC's interchange distribution
calculator (IDC) to determine and verify ATC calculations of existing
transmission providers, whether they are individual utilities, ISOs or
transcos and to determine and verify transfer capabilities at
interfaces.
(2) Serving as a grid operations manager (similar to an air traffic
controller).
The interregional transmission system coordinator could:
Monitor and oversee the grid;
Act as a seams coordinator;
Serve as the Security Coordinator;
Coordinate consistency of operating rules, e.g., schedule
deadline for submitting nominations;
Oversee low-level market monitoring; and
Enforce ATC and reliability rules
(3) Performing regional reliability functions on behalf of a Self-
Regulatory Organization.\57\
---------------------------------------------------------------------------
\57\ See Dynegy Request for Clarification and Rehearing at 13.
---------------------------------------------------------------------------
Dynegy points out that the ITSC would not impinge on the majority
of functions the Commission has assigned RTOs. Instead, Dynegy argues
that the ITSC would complement RTOs by ensuring that ATC is calculated
in a consistent manner or by ensuring tariffs and protocols do not
conflict or cause unwanted market or reliability impacts.
Commission Conclusion
We will deny Dynegy's request for expedited implementation of the
interregional coordination function. However, we continue to believe
that the coordination of activities among regions is an important
element in maintaining a reliable and efficient transmission system. We
expect that the parties will use the collaborative process to discuss
issues relating to interregional coordination and Dynegy's suggestions.
D. Open Architecture
In the Final Rule, we adopted the principle of open architecture in
order that the RTO and its members have the flexibility to improve
their organizations in the future. The Commission stated that an RTO
must have the flexibility to unilaterally propose changes to its
enabling agreements to meet changing market organization and policy
needs.\58\ We noted, however, that open architecture should not be
interpreted to mean the unfettered ability for an RTO to modify its
structure or processes. Under the Final Rule, proposed changes to the
RTO's jurisdictional rate schedules and contracts will be subject to
Commission review and approval under the FPA on a case-by-case basis.
---------------------------------------------------------------------------
\58\ See FERC Stats. & Regs. ] 31,089 at 31,170.
---------------------------------------------------------------------------
Rehearing Requests
EEI states that transmission owners should have fundamental rights,
such as
[[Page 12104]]
the right to terminate their participation in the RTO, the right to
switch to another RTO, the right to merge RTOs, the right to recover
their costs and a return on investment, and the right to protect their
assets and employees from damages and injuries. EEI asks the Commission
to clarify that these existing rights and obligations are recognizable
and enforceable, and that the RTO should not be able to unilaterally
abrogate these rights. NY Transmission Owners also request
clarification that transmission owners' fundamental rights cannot be
altered under the Final Rule's open architecture requirements. NY
Transmission Owners are concerned that an RTO may be allowed to change
the essential terms of the RTOs enabling agreements under the Final
Rule's open architecture policy.
Commission Conclusion
On rehearing, some transmission owners restate their concern that
open architecture places them at risk for being bound to an arrangement
that is fundamentally different from the one they agreed to join. We
believe that this is a legitimate concern that must be addressed in any
RTO proposal. In addition, in the Final Rule we agreed that ``the
flexibility implied by open architecture should not be interpreted to
mean unfettered ability on the part of the RTO to modify its structures
or processes.'' \59\ Accordingly, any RTO proposals or changes to
existing agreements, which will be changes to the RTO's jurisdictional
rate schedule(s) and contracts, will be subject to Commission review
and approval under the FPA. All changes to an approved RTO will be
examined on a case-by-case basis with interested parties having an
opportunity to comment on any proposal. Open architecture is aimed at
removing barriers to ongoing market improvements and is not intended to
allow unilateral changes without a full airing of issues by all
affected parties and review by the Commission.
---------------------------------------------------------------------------
\59\ FERC Stats. & Regs. para.31,089 at 31,170.
---------------------------------------------------------------------------
E. Transmission Ratemaking
1. Pancaked Rates
The Final Rule noted that the elimination of pancaked rates within
a region is a central goal of our RTO policy.\60\ While it is
acceptable to assess an access charge to recover capital costs, we
stated that transmission customers should not be required to pay
multiple access charges for crossing corporate utility boundaries in an
RTO region.
---------------------------------------------------------------------------
\60\ FERC Stats. & Regs. ] 31,089 at 31,174.
---------------------------------------------------------------------------
Rehearing Requests
EEI contends that the Final Rule provides no analysis of the impact
of the elimination of rate pancaking on wheeling rates and revenue. It
argues that the policy ignores the impact of loop flows on transmission
owners' property rights and infringes on state authority over service
territory boundary setting. EEI goes on to suggest that the policy
against pancaked rates be modified to allow an RTO to justify that its
pancaked rates are just and reasonable.
Commission Conclusion
We deny rehearing of the Final Rule's policy prohibiting pancaked
rates. Non-pancaked rates are a central attribute of RTO formation. We
have found that pancaking of access charges acts as a major detriment
to competition in the bulk power market. We believe that the allowance
of transitional use of license plate rates and certain innovative rate
provisions of the Final Rule will serve to protect transmission owners'
property rights.
2. Uniform Access Charges
The Final Rule recognized that the pancaked rate prohibition can
present problems for RTOs whose participants have divergent
transmission cost structures.\61\ An immediate move to a uniform access
charge across the entire RTO could cause disruptive cost shifting among
owners. We decided to apply flexibility in the use of license plate
rates, echoing our approach in the ISO approvals to date. The Final
Rule allowed RTO applicants to propose license plate rates for a fixed
term of the applicant's choosing. Under Order No. 2000, license plate
rates could be extended beyond the initial period if supported by the
facts at that time.
---------------------------------------------------------------------------
\61\ Id. at 31,177.
---------------------------------------------------------------------------
Rehearing Requests
PSE&G complains that the Final Rule's policy on license plate rates
is unfair to members of existing ISOs who will have to face uniform
rates at a date certain established in the orders approving those ISOs.
In light of the Final Rule's policy on license plate rates, PSE&G
argues that PJM should be relieved of the requirement to file uniform
access rates by July 1, 2002.\62\
---------------------------------------------------------------------------
\62\ See Pennsylvania-New Jersey-Maryland Interconnection, 81
FERC para.61,257 (1997).
---------------------------------------------------------------------------
TAPS contends that the policy on license plate rates should be
amended to include an explicit requirement that all transmission owners
be compensated for the use of their facilities.
Commission Conclusion
We deny rehearing of our policy on license plate rates. We shall
not address in this rehearing order PSE&G's request that PJM be
relieved of its obligation to file a uniform access charge by 2002.
PJM's RTO compliance filing will be tendered well before that date and
the Commission will consider any proposal to continue license plate
rates proposed by the RTO as a whole in the context of the overall RTO
proposal.
As to TAPS' request that we modify the Final Rule's license plate
policy, we agree with TAPS that all transmission owners should be
compensated for the use of their facilities, although we cannot
conclude in this rehearing order what types of compensation methods
should be used in a particular circumstance. As we stated in the Final
Rule, a certain level of detail in ratemaking matters is beyond the
Final Rule's scope, including issues such as TAPS' concern, and we will
decide these issues on a case-by-case basis.\63\
---------------------------------------------------------------------------
\63\ FERC Stats. & Regs. para.31,089 at 31,177.
---------------------------------------------------------------------------
3. Service to Transmission-Owning Utilities That Do Not Participate in
an RTO
In the Final Rule, we stated that where a transmission customer of
an RTO or the customer's affiliate owns, controls or operates
transmission in the RTO's region, and is not participating in that
particular RTO, we intend to permit that RTO to propose rates, terms,
and conditions of transmission service that recognize the participatory
status of the customer.\64\ The Commission concluded that each proposal
will be examined on a case-by-case basis. In addition, we noted that
some transmission owners may face legal obstacles to RTO participation
that need to be taken into account in the proposals.
---------------------------------------------------------------------------
\64\ See id. at 31,180.
---------------------------------------------------------------------------
Rehearing Requests
NRECA argues that the Commission should not unjustly reward RTOs by
allowing them to charge higher rates to non-participants where such
non-participation results from the RTOs' failure to reasonably
accommodate the needs of non-participation during the RTO formation
process. NRECA requests that the Commission clarify that proposals to
charge individual system rates to a transmission customer who is a non-
participant of the RTO may not be made unconditionally and must account
for the reasons underlying non-participation. Dairyland also asserts
that the Commission must make clear that non-public utilities will not
be penalized through the imposition of
[[Page 12105]]
disadvantageous pricing, terms and conditions for transmission service
from an RTO if solutions to the barriers non-public utilities face in
joining RTOs cannot be developed through the collaborative process.
Metropolitan, EEI, SMUD and NY Transmission Owners argue that the
Commission erred in permitting RTOs to charge individual rates to a
transmission customer who is a non-participating transmission owner in
the RTO region and that this provision should be deleted. These
entities assert that this aspect of the Final Rule violates
prohibitions against undue discrimination embodied in the Commission's
comparability pricing principles requiring that differences in rates be
based on differences in costs incurred to provide service. In addition,
EEI asserts that this provision contravenes the Commission's
determination to pursue a voluntary approach for RTO formation. South
Carolina Authority and TANC/MID also argue that the Commission should
grant rehearing and amend the Final Rule to prohibit discriminatory
rates for utilities that do not join RTOs. South Carolina Authority
asserts that because the Commission lacks the authority to require RTO
participation directly, subjecting parties who do not participate in an
RTO to less favorable rates, terms and conditions of service would be
unlawfully discriminatory. TANC/MID contends that the Commission failed
to adequately explain its decision to permit RTOs to propose rates that
penalize non-participants.
Commission Conclusion
As we noted in the Final Rule, proposals to charge different rates
to non-RTO participants must be demonstrated to be just and reasonable.
We agree that such demonstration must account for the reasons
underlying non-participation including, among other things, impediments
to participation that could not be overcome through the collaborative
process. We do not agree with the premise of some of the petitioners
who conclude that rate differences of any type constitute undue
discrimination. Finally, we disagree that the fact that we will
entertain such proposals is inconsistent with our voluntary approach to
RTO formation. The Final Rule neither requires nor pre-approves this
type of rate treatment. Rather, we simply declined to prohibit these
types of rate proposals entirely.
4. Performance-Based Rate Regulation
The Final Rule invited RTO applicants to file voluntary
performance-based regulation (PBR) proposals.\65\ We provided guidance
as to what constitutes a good PBR design in the RTO context. Under
Order No. 2000, PBR plans can be filed subsequent to the filing or
approval of the RTO proposal. The Commission concluded that proposals
for PBR should be fully documented with the necessary information to
evaluate costs and benefits.
---------------------------------------------------------------------------
\65\ FERC Stats. & Regs. para.31,089 at 31,183.
---------------------------------------------------------------------------
Rehearing Requests
Industrial Consumers argue that the Commission does not have
sufficient basis to abandon traditional cost-of-service principles in
favor of PBR. They contend that the Commission may not have met legal
requirements to enact such a policy shift. Further, Industrial
Consumers complain that the Commission has not inquired sufficiently
into the impact of PBR on customers of transmission service.
Commission Conclusion
As we noted in the Final Rule, we are not abandoning the
fundamental underpinnings of our traditional transmission pricing
policies, i.e., that transmission prices must reflect costs of
transmission service.\66\ The fact that performance-based pricing
mechanisms rely, in part, on benchmarks other than the transmission
provider's own costs (e.g., industry performance indices or normative
goals) does not constitute a departure from cost-of-service principles.
Moreover, we have not in the Final Rule approved any specific PBR. Any
entity proposing a PBR mechanism would have to include in its request,
as required by section 35.34(e)(1), explanations of how the rate would
help achieve the goals of RTOs, including efficient use of and
investment in the transmission system and reliability benefits to
consumers; a cost-benefit analysis including rate impacts, and why the
rate treatment is appropriate for the RTO. The Final Rule also
discussed a number of principles relating to PBR design.\67\ We will
analyze the merits of specific PBR mechanisms when they are proposed.
---------------------------------------------------------------------------
\66\ Id. at 31,173.
\67\ Id. at 31,185.
---------------------------------------------------------------------------
5. Other RTO Transmission Ratemaking Reforms
a. Levelized Rates
One of the innovative rate options we discussed in the Final Rule
is flexibility in the use of levelized rates to recover the cost of
transmission assets. Commission policy does not normally allow changes
from non-levelized to levelized rates when customer rates are impacted.
The Final Rule allowed more flexibility in the use of levelized rates
in RTO tariffs.\68\ We believed that this flexibility is reasonable
because the rates will be offered in a restructured market and will
represent a new service in many ways.
---------------------------------------------------------------------------
\68\ See id. at 31,193-94.
---------------------------------------------------------------------------
Rehearing Requests
Metropolitan, TANC/MID, NRECA and Dairyland argue that the
Commission's policy on levelized rates for RTOs will double charge
existing transmission customers who have been paying depreciation
charges in existing rates. These entities take issue with Order No.
2000's determination that an RTO's transmission tariff would be for a
new service to new customers. They claim that many existing customers
would be forced to pay twice for the same facility.
EPSA suggests that the double charging of existing customers may be
largely avoided by allowing levelized rates only on the net,
depreciated plant costs.
TDU Systems argues that the policy in Order No. 2000 on levelized
rates is arbitrary and capricious because the need for flexibility does
not justify a policy change that would require existing customers to
pay twice for the same investment. TDU Systems says that the
Commission's policy in Kentucky Utilities \69\ should be applied to RTO
transmission rates.
---------------------------------------------------------------------------
\69\ 85 FERC para.61,274 (1998).
---------------------------------------------------------------------------
Commission Conclusion
We deny rehearing of our use of increased flexibility in
considering rates based on levelized recovery of capital costs. We
disagree that our decision on levelized rates reflects a policy change.
Our prior cases dealt with rates charged by a single utility for
service over its system. The customers did not change and the service
did not change materially over time. Under an RTO, customers will
receive service over multiple systems at a single, non-pancaked rate.
Different customers will be served by the multiple systems and
different services will be provided. This is a material change that
warrants appropriate transmission ratemaking reform.
Finally, we do not agree that allowing levelized rates constitutes
the payment for the same facilities twice. We reaffirm the explanation
for considering levelized rates set out in Order No. 2000.\70\
Customers do not buy facilities; they buy service. Moreover, the notion
[[Page 12106]]
that any RTO customer who paid rates for past services based on the
cost of facilities that now comprise a portion of the RTO grid is
somehow entitled to RTO rates based on the same ratemaking treatments
is not only unjustified, but also unworkable.
---------------------------------------------------------------------------
\70\ FERC Stats. & Regs. para.31,089 at 31,193-94.
---------------------------------------------------------------------------
Going forward, customers will be paying rates for expanded and more
flexible services at rates that, in total, are significantly lower than
the rates offered under individual tariffs. Moreover, going forward,
levelized rates have the beneficial effect of charging customers the
same rates for use of the same system regardless of when they take
service. The sweeping reorganization of the transmission grid that will
occur as the result of the Commission's RTO initiative and the
industry's own movement towards unbundling of the assets themselves is
the best time to consider what type of rate treatments, going forward,
will best serve the needs of competitive energy markets.
b. Return on Equity
Several of the innovative rate options in the Final Rule involve
adjustments to the return on equity allowed in the calculation of
transmission rates.\71\ These options include: formulary rates, risk
adjustments and rates of return that do not vary with changes in the
capital structure. We offered these options because they remove some of
the disincentives that may accompany joining an RTO, they recognize
changes in risk involved in restructuring and they take some account of
the changes in the industry that have an impact on owners' risk.
---------------------------------------------------------------------------
\71\ Id. at 31,192-93.
---------------------------------------------------------------------------
Rehearing Requests
NRECA and TDU Systems ask that the Commission clarify its position
on the increased risk that RTOs will be expected to experience. They
are concerned that the Commission may have prejudged the issue and
determined that RTOs will experience greater risk entitling them to a
higher rate of return. They ask the Commission to clarify that the
Commission will assess the risk of each RTO based on evidence brought
to bear on a case-by-case basis.
Industrial Consumers argue that the Commission cannot assume that
participation in an RTO increases risks for transmission owners. On the
contrary, they argue that evidence shows that risks involved in RTO
participation and divested transmission operation will actually be
lower. Industrial Consumers point to findings of the California Public
Utilities Commission and commentaries of utility investment analysts to
support its proposition. They state further that risks are lower for
RTO participants because of the statutory requirement that regulators
allow a reasonable rate of return, unbundling will shield transmission
owners from prudence reviews on the generation side, and more
competitive generation will reduce bypass opportunities.
Commission Conclusion
The Final Rule draws no conclusions about the risks of a
transmission-only business. It simply observes that the uncertainty
created during the restructuring transition may increase risk. We have
not prejudged the risk issue, and that issue will be determined case-
by-case.
c. Accelerated Depreciation and Incremental Pricing for New
Transmission Investments
The Final Rule recognized that new transmission investment may need
innovative rate treatment to make necessary enhancements viable in the
RTO context. For that reason, we stated that we would consider
proposals to allow accelerated depreciation of new transmission assets
and proposals to charge incremental rates for new investment while
charging embedded rates for existing investment.\72\
---------------------------------------------------------------------------
\72\ Id. at 31,194.
---------------------------------------------------------------------------
Rehearing Requests
TANC/MID claims that the Commission's willingness to consider
accelerated depreciation and incremental pricing for new investment is
arbitrary and capricious and is not supported by substantial evidence.
It claims that transmission projects are impeded more by siting and
environmental concerns than by inadequate financing. TANC/MID also
argues that incremental pricing for new investment while applying
average pricing for existing facilities violates the Commission's
policy against ``and'' pricing.
TDU Systems disagrees with the Commission that accelerated
depreciation and incremental pricing are needed for new transmission
investment. It finds them unwarranted deviations from established
pricing policy. If the Commission adopts such rate policies for RTOs,
it should require that any affected new facilities be put out for
competitive bid.
Commission Conclusion
With respect to accelerated depreciation for new transmission
investment, as with the other innovative rate treatments discussed in
the Final Rule, we did not guarantee that it would be allowed in every
situation. Rather, we stated that we were willing to provide the
flexibility to permit RTOs to propose non-traditional depreciation
schedules. All such proposals will be required to be supported by the
explanations and analyses set forth in section 35.34(e)(1). We do not
believe that our willingness to consider such proposals is arbitrary
and capricious.
We disagree that we have departed from our policy against ``and''
pricing. The form of ``and'' pricing that the Commission has prohibited
is described in the Transmission Pricing Policy Statement.\73\ There we
addressed ``and'' pricing at the corporate level, i.e., proposals by
individual transmission providers to assess certain customers both an
embedded cost rate and an incremental cost rate, while assessing only
an embedded cost rate to their own uses of the transmission system.
While the pricing proposals we will entertain for RTOs may combine
elements of embedded cost rates and incremental cost rates, they do not
constitute corporate ``and'' pricing. Indeed, we have already approved
these rate forms for most existing ISOs, noting for example, that it is
acceptable to charge both a non-pancaked access fee based on embedded
costs and an incremental charge reflecting opportunity costs or
expansion costs. Significantly, unlike the corporate ``and'' pricing
prohibited under our Transmission Pricing Policy Statement, the
objective of this pricing proposal is not to make the cost faced by one
group of transmission users (i.e., the wholesale customer) higher than
another's (i.e., native load). Rather, this type of pricing is intended
to (1) reduce the cost of transmission over multiple utility systems in
both constrained and unconstrained situations and (2) rely on
congestion charges to provide a uniform price signal to all users in
constrained situations.
---------------------------------------------------------------------------
\73\ Inquiry Concerning the Commission's Pricing Policy for
Transmission Services Provided by Public Utilities Under the Federal
Power Act, Policy Statement, FERC Stats. & Regs. para. 31,005
(1994), clarified, 71 FERC para. 61,195 (1995).
---------------------------------------------------------------------------
We shall not dictate that an RTO put transmission projects out for
competitive bid. As we noted in the Final Rule, the Commission will not
mandate any specific approach in how an RTO satisfies the function of
planning and expansion.\74\
---------------------------------------------------------------------------
\74\ FERC Stats. & Regs. para. 31,089 at 31,165.
---------------------------------------------------------------------------
[[Page 12107]]
d. Other Innovative Rate Issues
Rehearing petitions were filed on other innovative rate issues as
described below.
Rehearing Requests
NRECA is concerned that some of the innovative rate proposals
discussed in Order No. 2000 may produce rates significantly higher than
the rates that would be approved under existing cost-of-service
principles. NRECA asks that the Commission clarify that the
reasonableness of innovative rates offered by an RTO must be measured
against established cost of service principles.
EEI suggests that the innovative ratemaking treatments be extended
to all transmission-owning public utilities, even to non-RTOs. TAPS
contends that the Commission should require RTOs seeking rate
incentives to make them available to entities, other than existing
transmission owners, who are willing to invest in transmission.
SoCal Edison requests that the Commission clarify that transmission
owners who participate in an ISO type of RTO may file for innovative
rate treatments. SoCal Edison states that the language in the Final
Rule seems to imply that only an RTO can seek innovative rate
treatment. It contends that there is no rationale for precluding
transmission owners from seeking innovative rates if the desired rate
treatment otherwise comports with Order No. 2000's requirements.
Further, it states that the ROE-based innovative rate treatments are
more appropriate for the revenue requirement filing that can be made by
transmission owners. Therefore, SoCal Edison asks the Commission to
clarify that transmission owners as well as RTOs can seek innovative
rate treatment.
Commission Conclusion
In response to NRECA, we reaffirm our statement in the Final Rule
that the innovative rate treatments we have offered do not depart from
cost of service principles, i.e., that transmission prices must reflect
the costs of providing the service.\75\
---------------------------------------------------------------------------
\75\ Id. at 31,173.
---------------------------------------------------------------------------
We reject EEI's request to extend the innovative rate treatments to
public utilities that do not participate in RTOs. The Final Rule
addresses RTOs; the innovative rate treatments discussed in the Final
Rule must be justified in terms of how the proposed rate treatment
would help achieve RTO goals.\76\ It is outside the scope of this
rulemaking to address the extent to which such innovative rate
treatments could be justified in the absence of RTO benefits.
---------------------------------------------------------------------------
\76\ Id. at 31,172. See also section 35.34(e)(1)(i).
---------------------------------------------------------------------------
We agree with SoCal Edison that some of the ROE-based innovative
rate treatments relate most directly to the revenue requirement and, in
the ISO context, the transmission owner may be responsible for filing
the revenue requirement under section 205 of the FPA. A proposed
innovative ROE treatment for a transmission owner's revenue requirement
can best be evaluated in the context of any other innovative rate
treatments proposed for the RTO. In addition, the justification
required by section 35.34(e) involves an evaluation of factors related
to the RTO as a whole, not only the revenue requirement of an
individual owner. The collaborative process provides an important
opportunity for the parties to consider the procedures that will apply
to the filing of innovative rate treatments.
6. Additional Ratemaking Issues
There were several ratemaking issues not discussed above that were
introduced in the Final Rule and addressed in petitions for rehearing.
In the Final Rule, we determined that these issues, while important,
were at a level of detail that they were better considered in
individual RTO proposals.\77\
---------------------------------------------------------------------------
\77\ FERC Stats. & Regs. para. 31,089 at 31,196.
---------------------------------------------------------------------------
Rehearing Requests
Duke asks for clarification as to how RTO development and operating
costs will be recovered. Duke asserts that such costs can be quite
high, and even though the Commission is apparently committed to
allowing such reasonable costs in transmission rates, Duke is concerned
about what happens if state regulators do not authorize charging such
costs to bundled retail transmission customers. Duke seeks
clarification that if certain non-jurisdictional customers cannot be
charged, the Commission will allow wholesale and unbundled retail
customers to bear all the costs.
TAPS suggests that the Commission should require RTOs seeking rate
incentives to make them available to other market participants.
SoCal Cities requests that the Commission clarify our description
of its position on time-differentiated rates \78\ to state:
``Metropolitan and Cal DWR favor the use of time-of-use pricing or off-
peak rates for transmission; SoCal Cities oppose any generalized
requirement for time-differentiated transmission rates.''
---------------------------------------------------------------------------
\78\ Id. at 31,195.
---------------------------------------------------------------------------
Commission Conclusion
We decline to make any generic rulings, in the abstract, on the
recovery of RTO development and operating costs. We do not agree that
the benefits of RTOs flow only to wholesale markets. For example,
retail suppliers will benefit by access to regional markets at non-
pancaked rates under an RTO. However, we are cognizant that there may
be limitations on the ability of transmission providers to provide for
recovery of these costs from all retail ratepayers in the near-term. We
encourage parties to raise these issues during the collaboration
process and to involve state regulators and representatives of retail
consumers in these discussions. We expect that any RTO proposal will
address these matters.
In response to TAPS, there is nothing in our Final Rule that
precludes an RTO from involving entities other than existing
transmission owners in transmission expansion. Indeed, we expect that
the innovative rate treatments we have adopted will provide greater
flexibility to RTOs in ensuring timely and efficient expansion.
We accept SoCal Cities' clarification of its position.
7. Filing Procedures for Innovative Rate Proposals
As articulated in the Final Rule, the Commission will evaluate all
RTO proposals including any innovative rate treatment based on the
applicant's demonstration of how the proposed rate treatment would help
achieve the goals of regional transmission organizations, including
efficient use of and investment in the transmission system and
reliability benefits.\79\ We also required that applicants provide a
cost-benefit analysis, including rate impacts, and demonstrate that the
proposed rate treatment is appropriate for the proposed RTO and that
the rate proposal is just, reasonable, and not unduly discriminatory.
In addition, the Final Rule stated that pricing proposals involving
moratoriums and returns on equity that do not vary according to capital
structure may not be included in RTO rates after January 1, 2005.
---------------------------------------------------------------------------
\79\ Id. at 31,196.
---------------------------------------------------------------------------
Rehearing Requests
EEI and SoCal Edison argue that the Commission should eliminate the
requirement of a cost-benefit analysis in order to receive innovative
rates. These entities note that cost-benefit analyses
[[Page 12108]]
are difficult to perform, speculative in nature, and are likely to
result in expensive and time-consuming litigation of competing
hypotheticals and models.
Alliance Companies contend that the choice of January 1, 2005 is
arbitrary and capricious, and unlikely to accomplish the Commission's
goal of encouraging voluntary formation of RTOs. Alliance Companies
requests that the Commission eliminate the sunset provision, and permit
transmission owner participants in an RTO to address these issues in
their RTO applications. Likewise, EEI is concerned with the sunset
provision of January 1, 2005. EEI asserts that the Commission should
not sunset innovative rate methods, but review them on a case-by-case
basis instead.
Commission Conclusion
We shall not eliminate the cost-benefit analysis requirement. Those
urging us to consider the transmission rate reforms we adopted in the
Final Rule argued that innovative rate treatments would create tangible
benefits for electric markets. Moreover, we expect that an evaluation
of the impacts of any proposed rate treatment on electric markets would
be an integral part of the process that filing parties would undertake
before selecting and filing a specific innovative rate treatment.
We disagree that our selection of the sunset date is arbitrary and
capricious. As we noted in the Final Rule, the innovative rate
treatments which are available for a limited time are appropriate
during a transitional period only. The transition period we selected
reflects a reasonable balance of the benefits to RTO formation provided
by mechanisms such as a rate moratorium and the inability to rely on
these mechanisms for an extended period of time.
F. Other Issues
1. Public Power and Cooperatives
The Final Rule concluded that a properly formed RTO should include
all transmission owners in a specific region, including municipals,
cooperatives, Federal Power Marketing Agencies, Tennessee Valley
Authority and other state and local entities.\80\ Section 35.34(d)(4)
of the regulatory text required that an RTO proposal filed with the
Commission include a description of ``efforts made to include public
power entities in the proposed Regional Transmission Organization.''
---------------------------------------------------------------------------
\80\ FERC Stats. & Regs. para. 31,089 at 31,200-02.
---------------------------------------------------------------------------
Rehearing Requests
NRECA and Dairyland seek clarification and revision of section
35.34(d)(4) of the regulatory text. These entities assert that the
Commission inadvertently failed to include the term ``cooperatives'' in
the regulatory text, while the corresponding text of the preamble
repeatedly referred to public power entities and cooperatives
separately.
East Texas Cooperatives assert that although the Final Rule directs
RTOs to include public power and cooperatives in the planning process,
it does not require RTOs to allow small transmission owners to place
their facilities under the RTO tariff and recover a portion of their
annual transmission revenue requirements through the RTO tariff. East
Texas Cooperatives argue that it does little good to require RTOs to
include cooperatives in the development process if the RTO may refuse
to allow the cooperative to place its facilities under the RTO tariff
and receive an allocation of revenue.
Commission Conclusion
As requested by NRECA and Dairyland, we clarify that section
35.34(d)(4) should include cooperatives consistent with the text of the
preamble. In fact, our intent was for those proposing RTOs to consult
with all non-public utility transmission owners in its region. We will
revise section 35.34(d)(4) to read as follows, with the addition to the
text underlined: ``Any proposal filed under this paragraph (d) must
include an explanation of efforts made to include public power entities
and electric power cooperatives in the proposed Regional Transmission
Organization.''
In response to East Texas Cooperatives, the Commission explained in
the Final Rule that participation by public power entities and
cooperatives is vital to ensure that each RTO is appropriate in size
and scope. We continue to expect public power entities and cooperatives
to join RTOs and to participate fully in RTO formation and
operation.\81\ Furthermore, we agree that all transmission owners
should be compensated for the use of their facilities, although we
cannot conclude in this rehearing order what types of compensation
methods should be used in a particular circumstance.
---------------------------------------------------------------------------
\81\ While the filing requirements of section 35.34(c) apply
only to public utilities, we will permit submittals by non-public
utilities if they wish to inform the Commission of their views.
---------------------------------------------------------------------------
2. Existing Transmission Contracts
In the Final Rule, the Commission concluded it is not appropriate
to order generic abrogation of existing transmission contracts at this
time.\82\ We adopted the measured approach of addressing the issue of
existing transmission contracts on an RTO-by-RTO basis and we stated
that each RTO can propose whatever contract reform is necessary. The
Commission stated that its goal in review of existing transmission
contracts is to balance the desire to honor existing contractual
arrangements with the need for a uniform approach for transmission
pricing and the elimination of pancaked rates.
---------------------------------------------------------------------------
\82\ FERC Stats. & Reg. para. 31,089 at 31,205.
---------------------------------------------------------------------------
Rehearing Requests
Metropolitan, PSE&G and TANC/MID request rehearing on this issue.
Metropolitan and TANC/MID argue that the Commission failed to provide a
reasonable explanation for encouraging RTOs to propose piecemeal
abrogation of existing contracts and that this policy is a departure
from Order No. 888. PSE&G asserts that the Commission erred in refusing
to address treatment of existing contracts on a generic basis and that
the Commission should allow existing contracts to remain in effect
following the formation of an RTO.
Commission Conclusion
We clarify that Order No. 2000 did not order abrogation of existing
transmission contracts. We continue to recognize that existing
contracts represent negotiated agreements. However, this issue has
arisen in every ISO filing tendered to date, and we intend to address
the issue of existing transmission contracts on an RTO-by-RTO basis
when it arises again. RTOs may propose whatever contract reform they
conclude is necessary to convert from existing contracts to RTO
service. The circumstances faced by each region may differ
significantly and the likelihood that parties can reach agreement on
how to resolve this issue is enhanced if they have the flexibility to
design region-specific solutions. As we stated in the Final Rule:
``[O]ur goal in reviewing existing transmission contracts and contract
transition plans is to balance the desire to honor existing contractual
arrangements with the need for a uniform approach for transmission
pricing and the elimination of pancaked rates.'' \83\
---------------------------------------------------------------------------
\83\ Id.
---------------------------------------------------------------------------
[[Page 12109]]
3. Lighter Handed Regulation
In the Final Rule, the Commission concluded that a properly
structured RTO would reduce the need for Commission oversight and
scrutiny, which would benefit both the industry and the Commission.\84\
We stated that some degree of deference could be granted on certain
issues to independent RTOs that have appropriate procedural mechanisms
in place to ensure adequate representation of all viewpoints. In the
Final Rule, the Commission noted that we cannot delineate the
appropriate degree of deference, or on what issues. We believe,
however, to the extent an issue can be resolved fairly within a region
without Commission involvement, benefits accrue to all parties.
---------------------------------------------------------------------------
\84\ Id. at 31,027.
---------------------------------------------------------------------------
Rehearing Requests
Dynegy argues that the Commission's deference standard has the
potential to confer broad unilateral powers on RTOs. Dynegy requests
that the Commission: (1) clarify that if a party challenges the bona
fides of an alleged consensus, the Commission will independently
examine the facts and circumstances to determine if there was a true
consensus; and (2) clarify that if an RTO seeks deference on the
adoption of a particular rule, the Commission will ensure that the rule
is promulgated in advance pursuant to appropriate internal procedures
and subject to Commission review.
Commission Conclusion
At the outset, we note that we will continue to apply the level of
regulation and scrutiny that is necessary to ensure that public
utilities comply with the FPA and our regulations. We confirm that our
purpose is not to rely solely on consensus as the basis for accepting
RTO provisions. However, we intend to give considerable weight to those
aspects of an RTO proposal that result from good faith efforts and an
inclusive collaboration process. We encourage all parties to
participate in the collaborative process and to consider the diverse
interests and needs of the other participants. In this rehearing order,
we will not dictate the procedures that RTOs must follow in adopting
and promulgating rules. We expect, however, that these procedures will
be clearly defined in any RTO proposal that is filed with the
Commission.
G. Implementation Issues
1. Filing Requirements
In the Final Rule, the Commission required that all public
utilities that own, operate or control interstate transmission
facilities (except those already participating in an approved regional
transmission entity) file by October 15, 2000, either a proposal to
participate in an RTO or an alternative filing describing efforts and
plans to participate in an RTO.\85\
---------------------------------------------------------------------------
\85\ See id. at 31,226.
---------------------------------------------------------------------------
Rehearing Requests
NRECA notes that some entities (small utilities as defined by the
Small Business Association and entities with only limited and discrete
transmission facilities that do not form an integrated transmission
grid) have been granted waivers of some of the requirements of Order
Nos. 888 and 889. NRECA requests that the Commission clarify that
utilities with such waivers also be granted waivers from the filings
mandated by section 35.34(c). NRECA argues that the transmission
facilities owned by a utility holding waivers from Order Nos. 888 and
889 are not critical to an RTO and that the costs associated with
making the section 35.34(c) filing will exceed the benefits.
Commission Conclusion
We deny NRECA's request to waive the filing requirements of section
35.34(c) to entities that have been granted waivers from some of the
requirements of Order Nos. 888 and 889. We note that the Final Rule
only requires that each public utility that owns, operates or controls
transmission facilities participate in one-time filings proposing an
RTO or make a filing explaining why they are not participating in an
RTO proposal. In any filing explaining why they are not participating
in an RTO, we will allow entities that previously have been granted
waiver from some or all of the requirements of Order Nos. 888 and 889
to make an abbreviated filing.\86\ However, we expect that all
utilities, including those transmission-owning utilities that received
waivers, will participate in the collaborative process. Moreover,
during the collaborative process, we expect those utilities to consider
their involvement in an RTO, e.g., to ensure that formation of an RTO
is not impaired by the exclusion of their limited transmission
facilities.
---------------------------------------------------------------------------
\86\ We also clarify that we are not precluding such entities
from participating in joint filings with other public utilities or
having other public utilities file on their behalf.
---------------------------------------------------------------------------
2. Deadline for RTO Operation
In the Final Rule, the Commission retained the originally proposed
startup and other functional implementation deadlines (RTO startup by
December 15, 2001, implementation of congestion management by December
15, 2002, and implementation of the parallel path flow coordination and
transmission planning and expansion functions by 2004).\87\
---------------------------------------------------------------------------
\87\ See FERC Stats. & Regs. para.31,089 at 31,229.
---------------------------------------------------------------------------
Rehearing Requests
Duke is concerned that it will not be able to comply with the time
schedule set forth in Order No. 2000 for formation of an RTO without
infringing on state jurisdiction over retail electric service. Duke
requests clarification that the timetables set forth in Order No. 2000
are merely benchmarks and that Commission will permit public utilities
to transition to RTO membership in a manner that is coordinated with
state retail service restructuring and unbundling. In addition, EEI
argues that the time schedules for RTO implementation are unreasonable
and unrealistic given the record of RTO formation to date. EEI requests
that the Commission modify the time schedules consistent with the
flexibility shown throughout the Final Rule and to reflect a reasonable
timetable for the development and implementation of an RTO.
Commission Conclusion
We will deny EEI's request to modify the time schedules adopted in
the Final Rule. We will also reject Duke's clarification that the RTO
operational deadlines in the Final Rule are merely benchmarks. We
continue to believe that the timetable for RTO formation and
implementation established in the Final Rule is feasible and realistic.
First, we note that all industry participants and the Commission have
learned a great deal during the formation of the five ISOs under
Commission jurisdiction and this knowledge should facilitate RTO
formation. Second, the Final Rule provided flexibility that enables an
RTO to satisfy the minimum characteristics and functions in a cost
efficient manner. Moreover, we adopted a longer phase-in period for
functions that may be difficult to establish, such as congestion
management, parallel path flow measures, and transmission planning and
expansion. In response to Duke, we stated in the Final Rule that ``an
acceptable RTO structure need not be a monolithic organization that
requires an extended period of time to become fully set up so that it
can
[[Page 12110]]
directly `push all of the buttons.' '' \88\ In sum, we continue to
think that the phased startup and other implementation deadlines are
reasonable.
---------------------------------------------------------------------------
\88\ See id. at 31,229.
---------------------------------------------------------------------------
IV. Regulatory Flexibility Act Certification
The Regulatory Flexibility Act requires rulemakings to either
contain a description and analysis of the effect that a proposed or
Final Rule will have on small entities or to contain a certification
that the rule will not have a significant economic impact on a
substantial number of small entities. In Order No. 2000, the Commission
certified that the Final Rule would not impose a significant economic
impact on a substantial number of small entities. No rehearing requests
of Order No. 2000 were filed on this issue and the Commission finds no
reason to alter its previous findings on this issue.
V. Public Reporting Burden and Information Collection Statement
Order No. 2000 contained an information collection statement that
the Commission submitted to the Office of Management and Budget
(OMB).\89\ Given that this order on rehearing makes only minor
revisions to Order No. 2000, OMB approval for this order will not be
necessary. However, the Commission will send a copy of this order to
OMB for informational purposes.
---------------------------------------------------------------------------
\89\ The OMB control numbers for this collection of information
are 1902-0096 and 1902-0082.
---------------------------------------------------------------------------
The information reporting requirements under this order are
unchanged from those contained in Order No. 2000. Interested persons
may obtain information on the reporting requirements by contacting the
following: Federal Energy Regulatory Commission, 888 First Street, NE,
Washington, DC 20426 [Attention: Michael Miller, Office of the Chief
Information Officer, Phone: (202) 208-1415, fax: (202) 208-2425, E-
mail: [email protected]] or send your comments to the Office of
Management and Budget, Office of Information and Regulatory Affairs,
Washington, DC 20503, [Attention: Desk Officer for the Federal Energy
Regulatory Commission, phone: (202) 395-3087, fax: (202) 395-7285].
VI. Effective Date and Congressional Notification
Changes to Order No. 2000 made in this order on rehearing will
become effective on April 7, 2000.
VII. Document Availability
In addition to publishing the full text of this document in the
Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
Internet through FERC's Home Page (http://www.ferc.fed.us) and in
FERC's Public Reference Room during normal business hours (8:30 a.m. to
5:00 p.m. Eastern time) at 888 First Street, NE, Room 2A, Washington,
DC 20426.
From FERC's Home Page on the Internet, this information is
available in both the Commission Issuance Posting System (CIPS) and the
Records and Information Management System (RIMS).
CIPS provides access to the texts of formal documents
issued by the Commission since November 14, 1994. CIPS can be accessed
using the CIPS link or the Energy Information Online icon. The full
text of this document will be available on CIPS in ASCII and
WordPerfect 8.0 format for viewing, printing, and/or downloading.
RIMS contains images of documents submitted to and issues
by the Commission after November 16, 1981. Documents from November 1995
to the present can be viewed and printed from FERC's Home Page using
the RIMS link or the Energy Information Online icon. Descriptions of
documents back to November 16, 1981, are also available from RIMS-on-
the-Web; requests for copies of these and other older documents should
be submitted to the Public Reference Room.
User assistance is available for RIMS, CIPS, and the Website during
normal business hours from our Help line at (202) 208-2222 (e-mail to
WebM[email protected]) of the Public Reference Room at (202) 208-1371
(e-mail to [email protected]).
During normal business hours, documents can also be viewed and/or
printed in FERC's Public Reference Room, where RIMS, CIPS, and the FERC
Website are available. User assistance is also available.
List of Subjects in 18 CFR Part 35
Electric power rates, Electric utilities, Reporting and
recordkeeping requirements.
By the Commission.
David P. Boergers,
Secretary.
In consideration of the foregoing, the Commission amends Part 35,
Chapter I, Title 18 of the Code of Federal Regulations, as follows:
PART 35--FILING OF RATE SCHEDULES
1. The authority citation for Part 35 continues to read as follows:
Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42
U.S.C. 7101-7352.
2. Part 35 is amended by revising Sec. 35.34 to read as follows:
Subpart F--Procedures and Requirements Regarding Regional
Transmission Organizations
Sec. 35.34 Regional Transmission Organizations.
(a) Purpose. This section establishes required characteristics and
functions for Regional Transmission Organizations for the purpose of
promoting efficiency and reliability in the operation and planning of
the electric transmission grid and ensuring non-discrimination in the
provision of electric transmission services. This section further
directs each public utility that owns, operates, or controls facilities
used for the transmission of electric energy in interstate commerce to
make certain filings with respect to forming and participating in a
Regional Transmission Organization.
(b) Definitions.
(1) Regional Transmission Organization means an entity that
satisfies the minimum characteristics set forth in paragraph (j) of
this section, performs the functions set forth in paragraph (k) of this
section, and accommodates the open architecture condition set forth in
paragraph (l) of this section.
(2) Market participant means:
(i) Any entity that, either directly or through an affiliate, sells
or brokers electric energy, or provides ancillary services to the
Regional Transmission Organization, unless the Commission finds that
the entity does not have economic or commercial interests that would be
significantly affected by the Regional Transmission Organization's
actions or decisions; and
(ii) Any other entity that the Commission finds has economic or
commercial interests that would be significantly affected by the
Regional Transmission Organization's actions or decisions.
(3) Affiliate means the definition given in section 2(a)(11) of the
Public Utility Holding Company Act (15 U.S.C. 79b(a)(11)).
(4) Class of market participants means two or more market
participants with common economic or commercial interests.
(c) General rule. Except for those public utilities subject to the
[[Page 12111]]
requirements of paragraph (h) of this section, every public utility
that owns, operates or controls facilities used for the transmission of
electric energy in interstate commerce as of March 6, 2000 must file
with the Commission, no later than October 15, 2000, one of the
following:
(1) A proposal to participate in a Regional Transmission
Organization consisting of one of the types of submittals set forth in
paragraph (d) of this section; or
(2) An alternative filing consistent with paragraph (g) of this
section.
(d) Proposal to participate in a Regional Transmission
Organization. For purposes of this section, a proposal to participate
in a Regional Transmission Organization means:
(1) Such filings, made individually or jointly with other entities,
pursuant to sections 203, 205 and 206 of the Federal Power Act (16
U.S.C. 824b, 824d, and 824e), as are necessary to create a new Regional
Transmission Organization;
(2) Such filings, made individually or jointly with other entities,
pursuant to sections 203, 205 and 206 of the Federal Power Act (16
U.S.C. 824b, 824d, and 824e), as are necessary to join a Regional
Transmission Organization approved by the Commission on or before the
date of the filing; or
(3) A petition for declaratory order, filed individually or jointly
with other entities, asking whether a proposed transmission entity
would qualify as a Regional Transmission Organization and containing at
least the following:
(i) A detailed description of the proposed transmission entity,
including a description of the organizational and operational structure
and the intended participants;
(ii) A discussion of how the transmission entity would satisfy each
of the characteristics and functions of a Regional Transmission
Organization specified in paragraphs (j), (k)and (l) of this section;
(iii) A detailed description of the Federal Power Act section 205
rates that will be filed for the Regional Transmission Organization;
and
(iv) A commitment to make filings pursuant to sections 203, 205 and
206 of the Federal Power Act (16 U.S.C. 824b, 824d, and 824e), as
necessary, promptly after the Commission issues an order in response to
the petition.
(4) Any proposal filed under this paragraph (d) must include an
explanation of efforts made to include public power entities and
electric power cooperatives in the proposed Regional Transmission
Organization.
(e) Innovative transmission rate treatments for Regional
Transmission Organizations.
(1) The Commission will consider authorizing any innovative
transmission rate treatment, as discussed in this paragraph (e), for an
approved Regional Transmission Organization. An applicant's request
must include:
(i) A detailed explanation of how any proposed rate treatment would
help achieve the goals of Regional Transmission Organizations,
including efficient use of and investment in the transmission system
and reliability benefits to consumers;
(ii) A cost-benefit analysis, including rate impacts; and
(iii) A detailed explanation of why the proposed rate treatment is
appropriate for the Regional Transmission Organization.
The applicant must support any rate proposal under this paragraph
(e) as just, reasonable, and not unduly discriminatory or preferential.
(2) For purposes of this paragraph (e), innovative transmission
rate treatment means any of the following:
(i) A transmission rate moratorium, which may include proposals
based on formerly bundled retail transmission rates;
(ii) Rates of return that:
(A) Are formulary;
(B) Consider risk premiums and account for demonstrated adjustments
in risk; or
(C) Do not vary with capital structure;
(iii) Non-traditional depreciation schedules for new transmission
investment;
(iv) Transmission rates based on levelized recovery of capital
costs;
(v) Transmission rates that combine elements of incremental cost
pricing for new transmission facilities with an embedded-cost access
fee for existing transmission facilities; or
(vi) Performance-based transmission rates.
(3) A request for performance-based transmission rates under this
paragraph (e) may include factors such as:
(i) A method for calculating initial transmission rates (including
price caps and any provisions for discounting);
(ii) A mechanism for adjusting initial rates, which may be derived
from or based upon external factors or indices or a specific
performance measure;
(iii) Time periods for redetermining initial rates; and
(iv) Costs to be excluded from performance-based rates.
(4) An innovative transmission rate treatment or any other rate
proposal made for an approved Regional Transmission Organization may be
requested as part of any filing that is made under paragraph (d) of
this section or in any subsequent rate change proposal under section
205 of the Federal Power Act (16 U.S.C. 824d). Unless otherwise ordered
by the Commission, an approved Regional Transmission Organization may
not include in rates any innovative transmission rate treatment under
paragraphs (e)(2)(i) and (e)(2)(ii)(C) of this section after January 1,
2005.
(f) Transfer of operational control. Any public utility's proposal
to participate in a Regional Transmission Organization filed pursuant
to paragraph (c)(1) of this section must propose that operational
control of that public utility's transmission facilities will be
transferred to the Regional Transmission Organization on a schedule
that will allow the Regional Transmission Organization to commence
operating the facilities no later than December 15, 2001.
Note to paragraph (f): The requirement in paragraph (f) of this
section may be satisfied by proposing to transfer to the Regional
Transmission Organization ownership of the facilities in addition to
operational control.
(g) Alternative filing. Any filing made pursuant to paragraph
(c)(2) of this section must contain:
(1) A description of any efforts made by that public utility to
participate in a Regional Transmission Organization;
(2) A detailed explanation of the economic, operational,
commercial, regulatory, or other reasons the public utility has not
made a filing to participate in a Regional Transmission Organization,
including identification of any existing obstacles to participation in
a Regional Transmission Organization; and
(3) The specific plans, if any, the public utility has for further
work toward participation in a Regional Transmission Organization, a
proposed timetable for such activity, an explanation of efforts made to
include public power entities in the proposed Regional Transmission
Organization, and any factors (including any law, rule or regulation)
that may affect the public utility's ability or decision to participate
in a Regional Transmission Organization.
(h) Public utilities participating in approved transmission
entities. Every public utility that owns, operates or controls
facilities used for the transmission of electric energy in interstate
commerce as of March 6, 2000, and that has filed with the Commission on
or before March 6, 2000 to transfer operational control of its
facilities to a transmission entity that
[[Page 12112]]
has been approved or conditionally approved by the Commission on or
before March 6, 2000 as being in conformance with the eleven ISO
principles set forth in Order No. 888, FERC Statutes and Regulations,
Regulations Preamble January 1991-June 1996 para.31,036 (Final Rule on
Open Access and Stranded Costs; see 61 FR 21540, May 10, 1996), must,
individually or jointly with other entities, file with the Commission,
no later than January 15, 2001:
(1) A statement that it is participating in a transmission entity
that has been so approved;
(2) A detailed explanation of the extent to which the transmission
entity in which it participates has the characteristics and performs
the functions of a Regional Transmission Organization specified in
paragraphs (j) and (k) of this section and accommodates the open
architecture conditions in paragraph (l) of this section; and
(3) To the extent the transmission entity in which the public
utility participates does not meet all the requirements of a Regional
Transmission Organization specified in paragraphs (j), (k), and (l) of
this section,
(i) A proposal to participate in a Regional Transmission
Organization that meets such requirements in accordance with paragraph
(d) of this section,
(ii) A proposal to modify the existing transmission entity so that
it conforms to the requirements of a Regional Transmission
Organization, or
(iii) A filing containing the information specified in paragraph
(g) of this section addressing any efforts, obstacles, and plans with
respect to conformance with those requirements.
(i) Entities that become public utilities with transmission
facilities. An entity that is not a public utility that owns, operates
or controls facilities used for the transmission of electric energy in
interstate commerce as of March 6, 2000, but later becomes such a
public utility, must file a proposal to participate in a Regional
Transmission Organization in accordance with paragraph (d) of this
section, or an alternative filing in accordance with paragraph (g) of
this section, by October 15, 2000 or 60 days prior to the date on which
the public utility engages in any transmission of electric energy in
interstate commerce, whichever comes later. If a proposal to
participate in accordance with paragraph (d) of this section is filed,
it must propose that operational control of the applicant's
transmission system will be transferred to the Regional Transmission
Organization within six months of filing the proposal.
(j) Required characteristics for a Regional Transmission
Organization. A Regional Transmission Organization must satisfy the
following characteristics when it commences operation:
(1) Independence. The Regional Transmission Organization must be
independent of any market participant. The Regional Transmission
Organization must include, as part of its demonstration of
independence, a demonstration that it meets the following:
(i) The Regional Transmission Organization, its employees, and any
non-stakeholder directors must not have financial interests in any
market participant.
(ii) The Regional Transmission Organization must have a decision
making process that is independent of control by any market participant
or class of participants.
(iii) The Regional Transmission Organization must have exclusive
and independent authority under section 205 of the Federal Power Act
(16 U.S.C. 824d), to propose rates, terms and conditions of
transmission service provided over the facilities it operates.
Note to paragraph (j)(1)(iii): Transmission owners retain
authority under section 205 of the Federal Power Act (16 U.S.C.
824d) to seek recovery from the Regional Transmission Organization
of the revenue requirements associated with the transmission
facilities that they own.
(iv)(A) The Regional Transmission Organization must provide:
(1) With respect to any Regional Transmission Organization in which
market participants have an ownership interest, a compliance audit of
the independence of the Regional Transmission Organization's decision
making process under paragraph (j)(1)(ii) of this section, to be
performed two years after approval of the Regional Transmission
Organization, and every three years thereafter, unless otherwise
provided by the Commission.
(2) With respect to any Regional Transmission Organization in which
market participants have a role in the Regional Transmission
Organization's decision making process but do not have an ownership
interest, a compliance audit of the independence of the Regional
Transmission Organization's decision making process under paragraph
(j)(1)(ii) of this section, to be performed two years after its
approval as a Regional Transmission Organization.
(B) The compliance audits under paragraph (j)(1)(iv)(A) of this
section must be performed by auditors who are not affiliated with the
Regional Transmission Organization or transmission facility owners that
are members of the Regional Transmission Organization.
(2) Scope and regional configuration. The Regional Transmission
Organization must serve an appropriate region. The region must be of
sufficient scope and configuration to permit the Regional Transmission
Organization to maintain reliability, effectively perform its required
functions, and support efficient and non-discriminatory power markets.
(3) Operational authority. The Regional Transmission Organization
must have operational authority for all transmission facilities under
its control. The Regional Transmission Organization must include, as
part of its demonstration of operational authority, a demonstration
that it meets the following:
(i) If any operational functions are delegated to, or shared with,
entities other than the Regional Transmission Organization, the
Regional Transmission Organization must ensure that this sharing of
operational authority will not adversely affect reliability or provide
any market participant with an unfair competitive advantage. Within two
years after initial operation as a Regional Transmission Organization,
the Regional Transmission Organization must prepare a public report
that assesses whether any division of operational authority hinders the
Regional Transmission Organization in providing reliable, non-
discriminatory and efficiently priced transmission service.
(ii) The Regional Transmission Organization must be the security
coordinator for the facilities that it controls.
(4) Short-term reliability. The Regional Transmission Organization
must have exclusive authority for maintaining the short-term
reliability of the grid that it operates. The Regional Transmission
Organization must include, as part of its demonstration with respect to
reliability, a demonstration that it meets the following:
(i) The Regional Transmission Organization must have exclusive
authority for receiving, confirming and implementing all interchange
schedules.
(ii) The Regional Transmission Organization must have the right to
order redispatch of any generator connected to transmission facilities
it operates if necessary for the reliable operation of these
facilities.
[[Page 12113]]
(iii) When the Regional Transmission Organization operates
transmission facilities owned by other entities, the Regional
Transmission Organization must have authority to approve or disapprove
all requests for scheduled outages of transmission facilities to ensure
that the outages can be accommodated within established reliability
standards.
(iv) If the Regional Transmission Organization operates under
reliability standards established by another entity (e.g., a regional
reliability council), the Regional Transmission Organization must
report to the Commission if these standards hinder it from providing
reliable, non-discriminatory and efficiently priced transmission
service.
(k) Required functions of a Regional Transmission Organization. The
Regional Transmission Organization must perform the following
functions. Unless otherwise noted, the Regional Transmission
Organization must satisfy these obligations when it commences
operations.
(1) Tariff administration and design. The Regional Transmission
Organization must administer its own transmission tariff and employ a
transmission pricing system that will promote efficient use and
expansion of transmission and generation facilities. As part of its
demonstration with respect to tariff administration and design, the
Regional Transmission Organization must satisfy the standards listed in
paragraphs (k)(1)(i) and (ii) of this section, or demonstrate that an
alternative proposal is consistent with or superior to satisfying such
standards.
(i) The Regional Transmission Organization must be the only
provider of transmission service over the facilities under its control,
and must be the sole administrator of its own Commission-approved open
access transmission tariff. The Regional Transmission Organization must
have the sole authority to receive, evaluate, and approve or deny all
requests for transmission service. The Regional Transmission
Organization must have the authority to review and approve requests for
new interconnections.
(ii) Customers under the Regional Transmission Organization tariff
must not be charged multiple access fees for the recovery of capital
costs for transmission service over facilities that the Regional
Transmission Organization controls.
(2) Congestion management. The Regional Transmission Organization
must ensure the development and operation of market mechanisms to
manage transmission congestion. As part of its demonstration with
respect to congestion management, the Regional Transmission
Organization must satisfy the standards listed in paragraph (k)(2)(i)
of this section, or demonstrate that an alternative proposal is
consistent with or superior to satisfying such standards.
(i) The market mechanisms must accommodate broad participation by
all market participants, and must provide all transmission customers
with efficient price signals that show the consequences of their
transmission usage decisions. The Regional Transmission Organization
must either operate such markets itself or ensure that the task is
performed by another entity that is not affiliated with any market
participant.
(ii) The Regional Transmission Organization must satisfy the market
mechanism requirement no later than one year after it commences initial
operation. However, it must have in place at the time of initial
operation an effective protocol for managing congestion.
(3) Parallel path flow. The Regional Transmission Organization must
develop and implement procedures to address parallel path flow issues
within its region and with other regions. The Regional Transmission
Organization must satisfy this requirement with respect to coordination
with other regions no later than three years after it commences initial
operation.
(4) Ancillary services. The Regional Transmission Organization must
serve as a provider of last resort of all ancillary services required
by Order No. 888, FERC Statutes and Regulations, Regulations Preamble
January 1991-June 1996 para. 31,036 (Final Rule on Open Access and
Stranded Costs; see 61 FR 21540, May 10, 1996), and subsequent orders.
As part of its demonstration with respect to ancillary services, the
Regional Transmission Organization must satisfy the standards listed in
paragraphs (k)(4)(i) through (iii) of this section, or demonstrate that
an alternative proposal is consistent with or superior to satisfying
such standards.
(i) All market participants must have the option of self-supplying
or acquiring ancillary services from third parties subject to any
restrictions imposed by the Commission in Order No. 888, FERC Statutes
and Regulations, Regulations Preamble January 1991-June 1996 para.
31,036 (Final Rule on Open Access and Stranded Costs), and subsequent
orders.
(ii) The Regional Transmission Organization must have the authority
to decide the minimum required amounts of each ancillary service and,
if necessary, the locations at which these services must be provided.
All ancillary service providers must be subject to direct or indirect
operational control by the Regional Transmission Organization. The
Regional Transmission Organization must promote the development of
competitive markets for ancillary services whenever feasible.
(iii) The Regional Transmission Organization must ensure that its
transmission customers have access to a real-time balancing market. The
Regional Transmission Organization must either develop and operate this
market itself or ensure that this task is performed by another entity
that is not affiliated with any market participant.
(5) OASIS and Total Transmission Capability (TTC) and Available
Transmission Capability (ATC). The Regional Transmission Organization
must be the single OASIS site administrator for all transmission
facilities under its control and independently calculate TTC and ATC.
(6) Market monitoring. To ensure that the Regional Transmission
Organization provides reliable, efficient and not unduly discriminatory
transmission service, the Regional Transmission Organization must
provide for objective monitoring of markets it operates or administers
to identify market design flaws, market power abuses and opportunities
for efficiency improvements, and propose appropriate actions. As part
of its demonstration with respect to market monitoring, the Regional
Transmission Organization must satisfy the standards listed in
paragraphs (k)(6)(i) through (k)(6)(iii) of this section, or
demonstrate that an alternative proposal is consistent with or superior
to satisfying such standards.
(i) Market monitoring must include monitoring the behavior of
market participants in the region, including transmission owners other
than the Regional Transmission Organization, if any, to determine if
their actions hinder the Regional Transmission Organization in
providing reliable, efficient and not unduly discriminatory
transmission service.
(ii) With respect to markets the Regional Transmission Organization
operates or administers, there must be a periodic assessment of how
behavior in markets operated by others (e.g., bilateral power sales
markets and power markets operated by unaffiliated power exchanges)
affects Regional Transmission Organization operations and how Regional
Transmission Organization operations affect the efficiency of power
markets operated by others.
(iii) Reports on opportunities for efficiency improvement, market
power
[[Page 12114]]
abuses and market design flaws must be filed with the Commission and
affected regulatory authorities.
(7) Planning and expansion. The Regional Transmission Organization
must be responsible for planning, and for directing or arranging,
necessary transmission expansions, additions, and upgrades that will
enable it to provide efficient, reliable and non-discriminatory
transmission service and coordinate such efforts with the appropriate
state authorities. As part of its demonstration with respect to
planning and expansion, the Regional Transmission Organization must
satisfy the standards listed in paragraphs (k)(7)(i) and (ii) of this
section, or demonstrate that an alternative proposal is consistent with
or superior to satisfying such standards.
(i) The Regional Transmission Organization planning and expansion
process must encourage market-driven operating and investment actions
for preventing and relieving congestion.
(ii) The Regional Transmission Organization's planning and
expansion process must accommodate efforts by state regulatory
commissions to create multi-state agreements to review and approve new
transmission facilities. The Regional Transmission Organization's
planning and expansion process must be coordinated with programs of
existing Regional Transmission Groups (See Sec. 2.21 of this chapter)
where appropriate.
(iii) If the Regional Transmission Organization is unable to
satisfy this requirement when it commences operation, it must file with
the Commission a plan with specified milestones that will ensure that
it meets this requirement no later than three years after initial
operation.
(8) Interregional coordination. The Regional Transmission
Organization must ensure the integration of reliability practices
within an interconnection and market interface practices among regions.
(l) Open architecture.
(1) Any proposal to participate in a Regional Transmission
Organization must not contain any provision that would limit the
capability of the Regional Transmission Organization to evolve in ways
that would improve its efficiency, consistent with the requirements in
paragraphs (j) and (k) of this section.
(2) Nothing in this regulation precludes an approved Regional
Transmission Organization from seeking to evolve with respect to its
organizational design, market design, geographic scope, ownership
arrangements, or methods of operational control, or in other
appropriate ways if the change is consistent with the requirements of
this section. Any future filing seeking approval of such changes must
demonstrate that the proposed changes will meet the requirements of
paragraphs (j), (k) and (l) of this section.
Note: The following appendix will not appear in the Code of
Federal Regulations.
Appendix to Preamble--List of Petitioners
Abbreviation--Petitioner
1. AEP--American Electric Power System
2. Alliance Companies--American Electric Power Service Corporation,
Consumers Energy Company, Detroit Edison Company, FirstEnergy Corp.
and Virginia Electric and Power Company
3. CCEM--Coalition for a Competitive Electricity Market
4. CFA--Consumer Federation of America
5. Conectiv--Conectiv
6. CTA--Competitive Transmission Association, Inc.
7. Dairyland--Dairyland Power Cooperative
8. Duke--Duke Energy Corporation
9. Dynegy--Dynegy Inc.
10. East Texas Cooperatives--East Texas Electric Cooperative, Inc.,
Northeast Texas Electric Cooperative, Inc., Sam Rayburn G&T Electric
Cooperative, Inc., Tex-La Electric Cooperative of Texas, Inc.
11. EEI--Edison Electric Institute
12. Entergy--Entergy Services, Inc.
13. EPSA--Electric Power Supply Association
14. Independent Companies--New England Power Company, Montaup
Electric Company, National Grid Group, plc, Jersey Central Power and
Light Company, Metropolitan Edison Company, Pennsylvania Electric
Company, Vermont Electric Power Company and NSTAR Services Company
15. Industrial Consumers--Electricity Consumers Resource Council,
American Iron & Steel Institute and Chemical Manufactures
Association
16. ISO Participants--Baltimore Gas and Electric Company, Conectiv,
Consolidated Edison Company of New York, Inc., Northeast Utilities
Service Company, PP&L,Inc., Potomac Electric Power Company, Public
Service Electric and Gas Company
17. Metropolitan--Metropolitan Water District of Southern California
18. Midwest ISO Participants--Alliant Utilities, Ameren, Central
Illinois Light Company, Cinergy Corp., Commonwealth Edison Company,
Hoosier Energy Rural Electric Cooperative, Inc., Illinois Power
Company, Kentucky Utilities Company, Louisville Gas & Electric
Company, Northern States Power Company, Southern Indiana Gas &
Electric Company, Southern Illinois Power Cooperative, Wabash Valley
Power Association, Inc. and Wisconsin Electric Power Company
19. New Orleans--Council of the City of New Orleans
20. NRECA--National Rural Electric Cooperative Association
21. PECO--PECO Energy Company
22. Pennsylvania Commission--Pennsylvania Public Utility Commission
23. PP&L Companies--PP&L, Inc., PP&L EnergyPlus Co., LLC and PP&L
Montana, LLC
24. PSE&G--Public Service Electric and Gas Company
25. Puget Sound--Puget Sound Energy, Inc.
26. SMUD--Sacramento Municipal Utility District
27. Snohomish--Public Utility District No. 1 of Snohomish County,
Washington
28. SoCal Cities--Cities of Anaheim, Azusa, Banning, Colton, and
Riverside, California
29. SoCal Edison--Southern California Edison Company
30. South Carolina Authority--South Carolina Public Service
Authority
31. Southern Company--Southern Company Services, Inc. acting as
agent for Alabama Power Company, Georgia Power Company, GulfPower
Company, Mississippi Power Company and Savannah Electric and Power
Company
32. SRP--Salt River Project Agricultural Improvement and Power
District
33. Steel Dynamics--Steel Dynamics, Inc.
34. TANC/MID--Transmission Agency of Northern California/Modesto
Irrigation District
35. TAPS--Transmission Access Policy Study Group
36. TDU Systems--Alabama Electric Cooperative, Inc., Arkansas
Electric Cooperative Corporation, Golden Spread Electric
Cooperative, Kansas Electric Power Cooperative, Inc., North Carolina
Electric Membership Corporation, Old Dominion Electric Cooperative,
Seminole Electric Cooperative, Inc. and South Mississippi Electric
Power Association
37. Transmission Owners of NY--Central Hudson Gas & Electric
Corporation, Consolidated Edison Company of New York, Inc., Long
Island Power Authority, New York
[[Page 12115]]
State Electric & Gas Corporation, Niagara Mohawk Power Corporation,
Orange and Rockland Utilities, Inc., Rochester Gas & Electric
Corporation, Power Authority of the State of New York
38. United Illuminating--United Illuminating Company
[FR Doc. 00-5021 Filed 3-7-00; 8:45 am]
BILLING CODE 6717-01-P