[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\
---------------------------------------------------------------------------

    \40\ FERC Stats. & Regs. para. 31,089 at 31,076.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    \43\ See FERC Stats. & Regs. para. 31,089 at 31,108.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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

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.
---------------------------------------------------------------------------

    \49\ FERC Stats. & Regs. para. 31,089 at 31,126.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \50\ See FERC Stats. & Regs. para. 31,089 at 31,140.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

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

    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\
---------------------------------------------------------------------------

    \52\ FERC Stats. & Regs. para. 31,089 at 31,064 and 31,156.
---------------------------------------------------------------------------

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