[Federal Register Volume 65, Number 4 (Thursday, January 6, 2000)]
[Rules and Regulations]
[Pages 810-959]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 00-2]



[[Page 809]]



Part II





Department of Energy





_______________________________________________________________________



18 CFR Part 35



Regional Transmission Organizations; Final Rule

  Federal Register / Vol. 65, No. 4 / Thursday, January 6, 2000 / Rules 
and Regulations  

[[Page 810]]



DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM99-2-000; Order No. 2000]


Regional Transmission Organizations

Issued December 20, 1999.
AGENCY: Federal Energy Regulatory Commission

ACTION: Final Rule.

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SUMMARY: The Federal Energy Regulatory Commission (Commission) is 
amending its regulations under the Federal Power Act (FPA) to advance 
the formation of Regional Transmission Organizations (RTOs). The 
regulations require 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 RTO. The Commission 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: This Final Rule will become effective March 6, 2000.

FOR FURTHER INFORMATION CONTACT:

Alan Haymes (Technical Information), Federal Energy Regulatory 
Commission, 888 First Street, NE, Washington, DC 20426, (202) 219-2919.
Brian R. Gish (Legal Information), Federal Energy Regulatory 
Commission, 888 First Street, NE, Washington, DC 20426, (202) 208-0996.
James Apperson (Collaborative Process), Federal Energy Regulatory 
Commission, 888 First Street, NE, Washington, DC 20426, (202) 219-2962.

SUPPLEMENTARY INFORMATION: 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 access 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 issued 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]) or the Public Reference 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.

Table of Contents

I. Introduction and Summary
II. Background
    A. The Foundation for Competitive Markets: Order Nos. 888 and 
889
    B. Developments Since Order Nos. 888 and 889
    1. Industry Restructuring and New Stresses on the Transmission 
Grid
    2. Successes, Failures and Haphazard Development of Regional 
Transmission Entities
    3. The Commission's ISO and RTO Inquires; Conferences with 
Stakeholders and State Regulators
III. Discussion
    A. Existence of Barriers and Impediments to Achieving Fully 
Competitive Electricity Markets
    B. Benefits That RTOs Can Offer to Address Remaining Barriers 
and Impediments
    C. Commission's Approach to RTO Formation
    1. Voluntary Approach
    2. Organizational Form of an RTO
    3. Degree of Specificity in the Rule
    4. Legal Authority
    D. Minimum Characteristics of an RTO
    1. Independence (Characteristic 1)
    2. Scope and Regional Configuration (Characteristic 2)
    3. Operational Authority (Characteristic 3)
    4. Short-Term Reliability (Characteristic 4)
    E. Minimum Functions of an RTO
    1. Tariff Administration and Design (Function 1)
    2. Congestion Management (Function 2)
    3. Parallel Path Flow (Function 3)
    4. Ancillary Services (Function 4)
    5. OASIS and Total Transmission Capability (TTC) and Available 
Transmission Capability (ATC) (Function 5)
    6. Market Monitoring (Function 6)
    7. Planning and Expansion (Function 7)
    8. Interregional Coordination (Function 8)
    F. Open Architecture
    G. Transmission Ratemaking Policy for RTOs
    1. Pancaked Rates
    2. Reciprocal Waiving of Access Charges Between RTOs
    3. Uniform Access Charges
    4. Congestion Pricing
    5. Service to Transmission-Owning Utilities That Do Not 
Participate in an RTO
    6. Performance-Based Rate Regulation
    7. Other RTO Transmission Ratemaking Reforms
    8. Additional Ratemaking Issues
    9. Filing Procedures for Innovative Rate Proposals
    H. Other Issues
    1. Public Power and Cooperative Participation in RTOs
    2. Participation by Canadian and Mexican Entities
    3. Existing Transmission Contracts
    4. Power Exchanges (PXs)
    5. Effect on Retail Markets and Retail Access
    6. Effect on States with Low Cost Generation
    7. States' Roles with Regard to RTOs
    8. Accounting Issues
    9. Market Design Lessons
    I. Collaborative Process
    J. Implementation Issues
    1. Filing Requirements
    2. Deadline for RTO Operation
    3. Commission Processing Procedures
    4. Other Implementation Issues
    IV. Environmental Statement
    V. Regulatory Flexibility Act Certification
    VI. Public Reporting Burden and Information Collection Statement
    VII. Effective Date and Congressional Notification
    VIII. Document Availability
Regulatory Text
Appendix

Before Commissioners: James J. Hoecker, Chairman; William L. Massey, 
Linda Breathitt, and Curt Hebert, Jr.

I. Introduction and Summary

    In 1996 the Commission put in place the foundation necessary for 
competitive wholesale power markets in this country--open access

[[Page 811]]

transmission. 1 Since that time, the industry has undergone 
sweeping restructuring activity, including a movement by many states to 
develop retail competition, the growing divestiture of generation 
plants by traditional electric utilities, a significant increase in the 
number of mergers among traditional electric utilities and among 
electric utilities and gas pipeline companies, large increases in the 
number of power marketers and independent generation facility 
developers entering the marketplace, and the establishment of 
independent system operators (ISOs) as managers of large parts of the 
transmission system. Trade in bulk power markets has continued to 
increase significantly and the Nation's transmission grid is being used 
more heavily and in new ways.
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    \1\ See Promoting Wholesale Competition Through Open Access Non-
discriminatory Transmission Services by Public Utilities and 
Recovery of Stranded Costs by Public Utilities and Transmitting 
Utilities, Order No. 888, 61 FR 21,540 (May 10, 1996), FERC Stats. & 
Regs. para. 31,036 (1996) (Order No. 888), order on reh'g, Order No. 
888-A, 62 FR 12,274 (March 14, 1997), FERC Stats. & Regs. para. 
31,048 (1997) (Order No. 888-A), order on reh'g, Order No. 888-B, 81 
FERC para. 61,248 (1997), order on reh'g, Order No. 888-C, 82 FERC 
para. 61,046 (1998), appeal docketed, Transmission Access Policy 
Study Group, et al.  v. FERC, Nos. 97-1715 et al. (D.C. Cir.).
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    On May 13, 1999, the Commission proposed a rule on Regional 
Transmission Organizations (RTOs) that identified and discussed our 
concerns with the traditional means of grid management.2 In 
that Notice of Proposed Rulemaking (NOPR), the Commission reviewed 
evidence that traditional management of the transmission grid by 
vertically integrated electric utilities was inadequate to support the 
efficient and reliable operation that is needed for the continued 
development of competitive electricity markets, and that continued 
discrimination in the provision of transmission services by vertically 
integrated utilities may also be impeding fully competitive electricity 
markets. These problems may be depriving the Nation of the benefits of 
lower prices and enhanced reliability. The comments on the NOPR 
overwhelmingly support the conclusion that independent regionally 
operated transmissions grids will enhance the benefits of competitive 
electricity markets. Competition in wholesale electricity markets is 
the best way to protect the public interest and ensure that electricity 
consumers pay the lowest price possible for reliable service.
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    \2\ Regional Transmission Organizations, Notice of Proposed 
Rulemaking, 64 FR 31,390 (June 10, 1999), FERC Stats. & Regs. para. 
32,541 at 33,683-781 (1999).
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    Regional institutions can address the operational and reliability 
issues now confronting the industry, and eliminate any residual 
discrimination in transmission services that can occur when the 
operation of the transmission system remains in the control of a 
vertically integrated utility. Appropriate regional transmission 
institutions could: (1) Improve efficiencies in transmission grid 
management; 3 (2) improve grid reliability; (3) remove 
remaining opportunities for discriminatory transmission practices; (4) 
improve market performance; and (5) facilitate lighter handed 
regulation.
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    \3\ As discussed more fully later, appropriate regional 
institutions could improve efficiencies in grid management through 
improved pricing, congestion management, more accurate estimates of 
Available Transmission Capability, improved parallel path flow 
management, more efficient planning, and increased coordination 
between regulatory agencies.
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    Thus, we believe that appropriate RTOs could successfully address 
the existing impediments to efficient grid operation and competition 
and could consequently benefit consumers through lower electricity 
rates resulting from a wider choice of services and service providers. 
In addition, substantial cost savings are likely to result from the 
formation of RTOs.
    Based on careful consideration of the thoughtful comments submitted 
in response to the NOPR,4 the Commission adopts a final rule 
that generally follows the approach of the NOPR. Our objective is for 
all transmission-owning entities in the Nation, including non-public 
utility entities, to place their transmission facilities under the 
control of appropriate RTOs in a timely manner. Therefore, we are 
establishing in this rule minimum characteristics and functions for 
appropriate RTOs; a collaborative process by which public utilities and 
non-public utilities that own, operate or control interstate 
transmission facilities, in consultation with state officials as 
appropriate, will consider and develop RTOs; a proposal to consider 
transmission ratemaking reforms on a case-specific basis; an 
opportunity for non-monetary regulatory benefits, such as deference in 
dispute resolution and streamlined filing and approval procedures; and 
a time line for public utilities to make appropriate filings with the 
Commission to initiate operation of RTOs. As a result of this voluntary 
approach, we expect jurisdictional utilities to form RTOs. If the 
industry fails to form RTOs under this approach, the Commission will 
reconsider what further regulatory steps are in the public interest.
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    \4\ The Commission received 334 initial and reply comments in 
response to the NOPR. The commenters, and abbreviations for them as 
used herein, are listed in an Appendix to this Final Rule.
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    Pursuant to our authority under section 205 of the Federal Power 
Act (FPA) to ensure that rates, terms and conditions of transmission 
and sales for resale in interstate commerce by public utilities are 
just, reasonable and not unduly discriminatory or preferential, and our 
authority under section 202(a) of the FPA to promote and encourage 
regional districts for the voluntary interconnection and coordination 
of transmission facilities by public utilities and non-public utilities 
for the purpose of assuring an abundant supply of electric energy 
throughout the United States with the greatest possible economy, this 
rule requires the following.
    First, the Commission establishes 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

Industry participants, however, retain flexibility in structuring RTOs 
that satisfy the minimum characteristics and functions. For example, we 
do not propose to require or prohibit any one form of organization for 
RTOs or require or prohibit RTO ownership of transmission facilities. 
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 is not proposing a 
``cookie cutter'' organizational format for regional transmission 
institutions or the establishment of fixed or specific regional 
boundaries under section 202(a) of the FPA.
    We also establish 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

[[Page 812]]

future in terms of structure, operations, market support and geographic 
scope to meet market needs. In turn, the Commission will provide the 
regulatory flexibility to accommodate such improvement.
    Second, to facilitate RTO formation in all regions of the Nation, 
the Commission will sponsor and support 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.
    Third, we provide guidance on flexible transmission ratemaking that 
may be proposed by RTOs, including ratemaking treatments that will 
address congestion pricing and performance-based regulation. We also 
propose to consider on a case-by-case basis incentive pricing that may 
be appropriate for transmission facilities under RTO control.
    Finally, all public utilities (with the exception of those 
participating in an approved regional transmission entity that conforms 
to the Commission's ISO principles) that own, operate or control 
interstate transmission facilities must file with the Commission by 
October 15, 2000, a proposal for an RTO with the minimum 
characteristics and functions to be operational by December 15, 
2001,5 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. We expect that such 
proposals would include the transmission facilities of public utilities 
as well as transmission facilities of public power and other non-public 
utility entities to the extent possible. Through the required filings, 
public utilities will make known to the public any plans for RTO 
participation and any obstacles to RTO formation.
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    \5\ An RTO proposal includes a basic agreement filed under 
section 205 of the FPA setting out the rules, practices and 
procedures under which the RTO will be governed and operated, and 
requests by the public utility members of the RTO under section 203 
of the FPA to transfer control of their jurisdictional transmission 
facilities from individual public utilities to the RTO. Most RTO 
proposals by public utilities are likely to involve one or more 
filings under FPA sections 203 and 205, but the number and types of 
filing may vary depending upon the type of RTO proposed and the 
number of public utilities involved in the proposal. Under the Rule, 
a utility may file a petition for a declaratory order asking, for 
example, whether a proposed transmission entity would qualify as an 
RTO or if a new or innovative method for pricing transmission 
service would be acceptable, to be followed by appropriate filings 
under sections 203 and 205.
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    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. That filing must explain the extent to 
which the transmission entity in which it participates 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.
    The goal of this rulemaking is to form RTOs voluntarily and in a 
timely manner. The alternative to a voluntary process is likely to be a 
lengthy process that is more likely to result in greater 
standardization of the Commission's RTO requirements among regions. 
Although the Commission has specific authorities and responsibilities 
under the FPA to protect against undue discrimination and remove 
impediments to wholesale competition, we find it appropriate in this 
instance to adopt an open collaborative process that relies on 
voluntary regional participation to design RTOs that can be tailored to 
specific needs of each region.

II. Background

    In April 1996, in Order Nos. 888 6 and 889,7 
the Commission established the foundation necessary to develop 
competitive bulk power markets in the United States: non-discriminatory 
open access transmission services by public utilities and stranded cost 
recovery rules that would provide a fair transition to competitive 
markets. Order Nos. 888 and 889 were very successful in accomplishing 
much of what they set out to do. However, the orders were not intended 
to address all problems that might arise in the development of 
competitive power markets. Indeed, the nature of the emerging markets 
and the remaining impediments to full competition that became apparent 
in the nearly four years since the issuance of Order Nos. 888 and 889, 
and the insightful comments and information presented to us by a wide 
array of industry participants in this rulemaking proceeding have made 
clear that the Commission must take further action if we are to achieve 
the fully competitive power markets envisioned by those orders.
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    \6\ See supra note 1.
    \7\ Open Access Same-Time Information System (Formerly Real-Time 
Information Networks) and Standards of Conduct, Order No. 889, 61 FR 
21,737 (May 10, 1996), FERC Stats. & Regs. para. 31,035 (1996), 
order on reh'g, Order No. 889-A, 62 FR 12,484 (March 14, 1997), FERC 
Stats. & Regs. para. 31,049 (1997), order on reh'g, Order No. 889-B, 
81 FERC para. 61,253 (1997).
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A. The Foundation for Competitive Markets: Order Nos. 888 and 889

    In Order Nos. 888 and 889, the Commission found that unduly 
discriminatory and anticompetitive practices existed in the electric 
industry, and that transmission-owning utilities had discriminated 
against others seeking transmission access.8 The Commission 
stated that its goal was to ensure that customers have the benefits of 
competitively priced generation, and determined that non-discriminatory 
open access transmission services (including access to transmission 
information) and stranded cost recovery were the most critical 
components of a successful transition to competitive wholesale 
electricity markets.9
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    \8\ Order No. 888, FERC Stats. & Regs. para. 31,036 at 31,682.
    \9\ Id. at 31,652.
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    Accordingly, Order No. 888 required all public utilities that own, 
control or operate facilities used for transmitting electric energy in 
interstate commerce to (1) file open access non-discriminatory 
transmission tariffs containing, at a minimum, the non-price terms and 
conditions set forth in the Order, and (2) functionally unbundle 
wholesale power services. Under functional unbundling, the public 
utility must: (1) take transmission services under the same tariff of 
general applicability as do others; (2) state separate rates for 
wholesale generation, transmission, and ancillary services; and (3) 
rely on the same electronic information network that its transmission 
customers rely on to obtain information about its transmission system 
when buying or selling power.10 Order No. 889 required that 
all public utilities establish or participate in an Open Access Same-
Time Information System (OASIS) that meets certain specifications, and 
comply with standards of conduct designed to prevent employees of a 
public utility (or any employees of its affiliates) engaged in 
wholesale power marketing functions from obtaining preferential access 
to pertinent transmission system information.
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    \10\ Id. at 31,654-55.
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    During the course of the Order No. 888 proceeding, the Commission 
received comments urging it to require generation divestiture or 
structural institutional arrangements such as regional independent 
system operators (ISOs) to better assure non-discrimination. The 
Commission responded that, while it believed that

[[Page 813]]

ISOs had the potential to provide significant benefits, efforts to 
remedy undue discrimination should begin by requiring the less 
intrusive functional unbundling approach. Subsequent to issuance of 
Order No. 888, it has become apparent that several types of regional 
transmission institutions, in addition to the kinds of ISOs approved to 
date, may also be able to provide the benefits attributed to ISOs in 
Order No. 888.
    Order No. 888 set forth 11 principles for assessing ISO proposals 
submitted to the Commission.11 Order No. 888 also stated:
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    \11\ Order No. 888, FERC Stats. & Regs. para. 31,036 at 31,730.

    [W]e see many benefits in ISOs, and encourage utilities to 
consider ISOs as a tool to meet the demands of the competitive 
marketplace. As a further precaution against discriminatory 
behavior, we will continue to monitor electricity markets to ensure 
that functional unbundling adequately protects transmission 
customers. At the same time, we will analyze all alternative 
proposals, including formation of ISOs, and, if it becomes apparent 
that functional unbundling is inadequate or unworkable in assuring 
non-discriminatory open access transmission, we will reevaluate our 
position and decide whether other mechanisms, such as ISOs, should 
be required.12
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    \12\ Id. at 31,655.

Below, we summarize our experiences with functional unbundling from the 
date of issuance of Order Nos. 888 and 889.

B. Developments Since Order Nos. 888 and 889

    In the nearly four years since Order Nos. 888 and 889 were issued, 
numerous significant developments have occurred in the electric utility 
industry. Some of these reflect changes in governmental policies; 
others are strictly industry-driven. These activities have resulted in 
a considerably different industry landscape from the one faced at the 
time the Commission was developing Order No. 888, resulting in new 
regulatory and industry challenges.
    Order Nos. 888 and 889 required a significant change to the way 
many public utilities have done business for most of this century, and 
most public utilities accepted these changes and made substantial good 
faith efforts to comply with the new requirements. Virtually all public 
utilities have filed tariffs stating rates, terms and conditions for 
comparable service to third-party users of their transmission systems. 
In addition, improved information about the transmission system is 
available to all participants in the market at the same time that it is 
available to the public utility's merchant function and market 
affiliate as a result of utility compliance with the OASIS regulations.
    The availability of tariffs and information about the transmission 
system has fostered a rapid growth in dependence on wholesale markets 
for acquisition of generation resources. Areas that have experienced 
generation shortages have seen rapid development of new generation 
resources. For example, in the Northeast Power Coordinating Council 
(NPCC) region (including New England, New York and parts of eastern 
Canada), where there was deep concern about adequacy of generation 
supply only three years ago, approximately 30,000 MW of generation is 
proposed or actually under construction.13 That response 
comes almost entirely from independent generating plants, which are 
able to sell power into the bulk power market through open access to 
the transmission system. Power resources are now acquired over 
increasingly large regional areas, and interregional transfers of 
electricity have increased. The very success of Order Nos. 888 and 889, 
and the initiative of some utilities that have pursued voluntary 
restructuring beyond the minimum open access requirements, have placed 
new stresses on regional transmission systems--stresses that call for 
regional solutions.
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    \13\ Based on data supplied to the Commission by Resource Data 
International.
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1. Industry Restructuring and New Stresses on the Transmission Grid
    Open access transmission and the opening of wholesale competition 
in the electric industry have brought an array of changes in the past 
several years: Divestiture by many integrated utilities of some or all 
of their generating assets; significantly increased merger activity 
both between electric utilities and between electric and natural gas 
utilities; increases in the number of new participants in the industry 
in the form of both independent and affiliated power marketers and 
generators as well as independent power exchanges; increases in the 
volume of trade in the industry, particularly sales by marketers; state 
efforts to introduce retail competition; and new and different uses of 
the transmission grid.
    With respect to divestiture, since August 1997, generating 
facilities representing approximately 50,000 MW of generating capacity 
have been sold (or are under contract to be sold) by utilities, and an 
additional 30,000 MW is currently for sale. In total, this represents 
more than ten percent of U.S. generating capacity. In all, 27 utilities 
have sold all or some of their generating assets and seven others have 
assets for sale. Buyers of this generating capacity have included 
traditional utilities with specified service territories as well as 
independent power producers with no required service territory.
    Since Order No. 888 was issued, more than 40 applications have been 
filed for Commission approval of proposed mergers involving public 
utilities.14 Most of these merger proposals involve electric 
utilities with contiguous service areas, although some of the proposed 
mergers have been between utilities with non-contiguous service areas. 
In addition, an increasing number of applications involve the 
combination of electric and natural gas assets.
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    \14\ See Commission's website, www.ferc.fed.us/electric/mergers.
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    There has been significant growth in the volume of trading, and 
particularly the number of marketers, in the wholesale electricity 
market. For example, in the first quarter of 1995, according to power 
marketer quarterly filings, marketer sales traded by only eight active 
power marketers, totaled 1.8 million MWh. By the first quarter of 1999, 
such sales escalated to over 400 million MWh, traded by over 100 power 
marketers.15
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    \15\ See Commission's website, www.ferc.fed.us/electric/PwrMkt. 
The Commission recognizes that a significant portion of the sales 
represent the retrading of power by a number of different market 
participants, such that there may be multiple resales of the same 
generation. Nonetheless, the volume of and intensity of trading 
continues to increase in the wholesale electricity market.
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    The Commission has granted market-based rate authority to more than 
800 entities, of which nearly 500 are power marketers, (including over 
100 marketers affiliated with investor-owned utilities). The remaining 
entities include approximately equal numbers of affiliated power 
producers, investor-owned utilities and other utilities.16
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    \16\ See Commission's website, www.ferc.fed.us/electric.
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    State commissions and legislatures have been active in the past few 
years studying competitive options at the retail level, setting up 
pilot retail access programs, and, in many states, implementing full 
scale retail access programs. As of November 1, 1999, twenty-one states 
had enacted electric restructuring legislation, three had issued 
comprehensive regulatory orders, and twenty-six states plus the 
District of Columbia had legislation or orders pending or 
investigations underway.17 Fifteen states had implemented 
full-

[[Page 814]]

scale or pilot retail competition programs that offer a choice of 
suppliers to at least some retail customers. Eight states have 
initiated programs to offer access to retail customers by a date 
certain.
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    \17\ See the Energy Information Administration website, 
www.eia.doe.gov/cneaf/electricity/chg__str/regmap.html.
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    Because of the changes in the structure of the electric industry, 
the transmission grid is now being used more intensively and in 
different ways than in the past. The Commission is concerned that the 
traditional approaches to operating the grid are showing signs of 
strain. According to the North American Electric Reliability Council 
(NERC), ``the adequacy of the bulk transmission system has been 
challenged to support the movement of power in unprecedented amounts 
and in unexpected directions.'' 18 These changes in the use 
of the transmission system ``will test the electric industry's ability 
to maintain system security in operating the transmission system under 
conditions for which it was not planned or designed.'' 19 It 
should be noted that, despite the increased transmission system 
loadings, NERC believes that the ``procedures and processes to mitigate 
potential reliability impacts appear to be working reliably for now,'' 
and that even though the system was particularly stressed during the 
summer of 1998, ``the system performed reliably and firm demand was not 
interrupted due to transmission transfer limitations.'' 20
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    \18\ Reliability Assessment 1998-2007, North American Electric 
Reliability Council (September 1998), at 26 (Reliability 
Assessment).
    \19\ Id.
    \20\ Id.
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    An indication that the increased and different use of the 
transmission system is stressing the grid is the increased use of 
transmission line loading relief (TLR) procedures.21 And, 
according to published reports, the incidence of TLRs is growing. While 
in all of 1998 over 300 TLRs were called, in the first ten months of 
1999, over 400 TLRs have been called, resulting in over 8,000 MW of 
power curtailment in the three-month summer period beginning June 
1999.22
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    \21\ The TLR procedures are designed to remedy overloads that 
result when a transmission line or other transmission equipment 
carries or will carry more power than its rating, which could result 
in either power outages or damage to property. The TLR procedures 
are designed to bring overloaded transmission equipment to within 
NERC's Operating Security Limits essentially by curtailing 
transactions contributing to the overload. See North American 
Electric Reliability Council, 85 FERC para. 61,353 (1998) (NERC).
    \22\ Power Markets Week, November 8, 1999 at 1, citing NERC 
data.
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    It appears that the planning and construction of transmission and 
transmission-related facilities may not be keeping up with increased 
requirements. According to NERC, ``business is increasing on the 
transmission system, but very little is being done to increase the load 
serving and transfer capability of the bulk transmission system.'' 
23 The amount of new transmission capacity planned over the 
next ten years is significantly lower than the additions that had been 
planned five years ago, and most of the planned projects are for local 
system support.24 NERC states that, ``The close coordination 
of generation and transmission planning is diminishing as vertically 
integrated utilities divest their generation assets and most new 
generation is being proposed and developed by independent power 
producers.'' 25
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    \23\ Reliability Assessment at 26.
    \24\ Id. at 7.
    \25\ Id.
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    The transition to new market structures has resulted in new 
challenges and circumstances. For example, during the week of June 22-
26, 1998, the wholesale electric market in the Midwest experienced 
numerous events that led to unprecedented high spot market prices. Spot 
wholesale market prices for energy briefly rose as high as $7,500 per 
MWh, compared with an average price for the summer of approximately $40 
per MWh in the Midwest if the pricing abnormalities are 
excluded.26 This experience led to calls for price caps, 
allegations of market power, and a questioning of the effectiveness of 
transmission open access and wholesale electric competition.
---------------------------------------------------------------------------

    \26\ See Staff Report to the Federal Energy Regulatory 
Commission on the Causes of Wholesale Electric Pricing Abnormalities 
in the Midwest During June 1998, (Sept. 22, 1998) (Staff Price Spike 
Report) at 3-8 to 3-11. Unusually high spot market wholesale prices 
also occurred during the summer of 1999. The Commission is not aware 
that any formal evaluations of market data have been performed for 
that occurrence of price abnormalities.
---------------------------------------------------------------------------

    The Commission staff undertook an investigation of the pricing 
abnormalities. Staff's report concluded that the unusually high price 
levels were caused by a combination of factors, particularly above-
average generation outages, unseasonably hot temperatures, storm-
related transmission outages, transmission constraints, poor 
communication of price signals, lowered confidence in the market due to 
a few contract defaults, and inexperience in dealing with competitive 
markets.27
---------------------------------------------------------------------------

    \27\ Id. at v.
---------------------------------------------------------------------------

    The Commission's staff found that the market institutions were not 
adequately prepared to deal with such a dramatic series of events. 
Regarding regional transmission entities, the staff report observed: 
``The necessity for cooperation in meeting reliability concerns and the 
Commission's intent to foster competitive market conditions underscores 
the importance of better regional coordination in areas such as 
maintenance of transmission and generation systems and transmission 
planning and operation.'' 28 Support for this view comes 
from many sources. For example, the Public Utilities Commission of 
Ohio, in its own report on the high spot market prices, recommended 
that policy makers ``take unambiguous action to require coordination of 
transmission system operations by regionwide Independent System 
Operators.'' 29
---------------------------------------------------------------------------

    \28\ Id. at 5-8.
    \29\ Ohio's Electric Market, June 22-26, 1998, What Happened and 
Why, A Report to the Ohio General Assembly, at iii.
---------------------------------------------------------------------------

    On September 29, 1998, the Secretary of Energy Advisory Board Task 
Force on Electric System Reliability published its final 
report.30 The Task Force was convened in January 1997 to 
provide advice to the Department of Energy on critical institutional, 
technical, and policy issues that need to be addressed in order to 
maintain bulk power electric system reliability in a more competitive 
industry. The Task Force found that ``the traditional reliability 
institutions and processes that have served the Nation well in the past 
need to be modified to ensure that reliability is maintained in a 
competitively neutral fashion;'' that ``grid reliability depends 
heavily on system operators who monitor and control the grid in real 
time;'' and that ``because bulk power systems are regional in nature, 
they can and should be operated more reliably and efficiently when 
coordinated over large geographic areas.'' 31
---------------------------------------------------------------------------

    \30\ Maintaining Reliability in a Competitive U.S. Electricity 
Industry; Final Report of the Task Force on Electric System 
Reliability (Sept. 29, 1998) (Task Force Report). The Task Force was 
comprised of 24 members representing all major segments of the 
electric industry, including private and public suppliers, power 
marketers, regulators, environmentalists, and academics.
    \31\ Task Force Report at x-xi.
---------------------------------------------------------------------------

    The report noted that many regions of the United States are 
developing ISOs as a way to maintain electric system reliability as 
competitive markets develop. According to the Task Force, ISOs are 
significant institutions to assure both electric system reliability and 
competitive generation markets. The Task Force concluded that a large 
ISO would: (1) Be able to identify and address reliability issues most 
effectively; (2) internalize much of the loop flow caused by the 
growing number of transactions; (3) facilitate transmission access 
across a larger

[[Page 815]]

portion of the network, consequently improving market efficiencies and 
promoting greater competition; and (4) eliminate ``pancaking'' of 
transmission rates, thus allowing a greater range of economic energy 
trades across the network.32
---------------------------------------------------------------------------

    \32\ Id. at 76.
---------------------------------------------------------------------------

2. Successes, Failures, and Haphazard Development of Regional 
Transmission Entities
    Since Order No. 888 was issued, there have been both successful and 
unsuccessful efforts to establish ISOs, and other efforts to form 
regional entities to operate the transmission facilities in various 
parts of the country. While we are encouraged by the success of some of 
these efforts, it is apparent that the results have been inconsistent, 
and much of the country's transmission facilities remain outside of an 
operational regional transmission institution.
    Proposals for the establishment of five ISOs have been submitted to 
and approved, or conditionally approved, by the Commission. These are 
the California ISO,33 PJM ISO,34 ISO New 
England,35 the New York ISO,36 and the Midwest 
ISO.37 In addition, the Texas Commission has ordered an ISO 
for the Electric Reliability Council of Texas (ERCOT).38 
Moreover, our international neighbors in Canada and Mexico are also 
pursuing electric restructuring efforts that include various forms of 
regional transmission entities.39
---------------------------------------------------------------------------

    \33\ Pacific Gas & Electric Company, et al., 77 FERC para. 
61,204 (1996), order on reh'g, 81 FERC para. 61,122 (1997) (Pacific 
Gas & Electric).
    \34\ Pennsylvania-New Jersey-Maryland Interconnection, et al., 
81 FERC para. 61,257 (1997), order on reh'g, 82 FERC para. 61,047 
(1998) (PJM).
    \35\ New England Power Pool, 79 FERC para. 61,374 (1997), order 
on reh'g, 85 FERC para. 61,242 (1998) (NEPOOL).
    \36\ Central Hudson Gas & Electric Corporation, et al., 83 FERC 
para. 61,352 (1998), order on reh'g, 87 FERC para. 61,135 (1999) 
(Central Hudson).
    \37\ Midwest Independent Transmission System Operator, et al., 
84 FERC para. 61,231, order on reconsideration, 85 FERC para. 
61,250, order on reh'g, 85 FERC para. 61,372 (1998) (Midwest ISO).
    \38\ See 16 Texas Administrative Code Sec. 23.67(p). 
Furthermore, on June 18, 1999, S.B.7 was enacted to restructure the 
Texas electric industry allowing retail competition. The bill 
requires retail competition to begin by January 2002. Rates will be 
frozen for three years, and then a six percent reduction will be 
required for residential and small commercial consumers.
    \39\ See Policy Proposal for Structural Reform of the Mexican 
Electricity Industry, Secretary of Energy, Mexico (Feb. 1999); Third 
Interim Report of the Ontario Market Design Committee (Oct. 1998); 
TransAlta Enterprises Corporation, 75 FERC para. 61,268 at 61,875 
(1996) (recognition of the restructuring in the Province of Alberta, 
Canada to create a Grid Company of Alberta).
---------------------------------------------------------------------------

    The PJM, New England and New York ISOs were established on the 
platform of existing tight power pools. It appears that the principal 
motivation for creating ISOs in these situations was the Order No. 888 
requirement that there be a single systemwide transmission tariff for 
tight pools. In contrast, the establishment of the California ISO and 
the ERCOT ISO was the direct result of mandates by state governments. 
The Midwest ISO, which is not yet operational, is unique. It was 
neither required by government nor based on an existing institution. 
Two states in the region subsequently required utilities in their 
states to participate in either a Commission-approved ISO (Illinois and 
Wisconsin), or sell their transmission assets to an independent 
transmission company that would operate under a regional ISO 
(Wisconsin).
    As part of general restructuring initiatives, several states now 
require independent grid management organizations. For example, an 
Illinois law required that its utilities become members of a FERC-
approved regional ISO by March 31, 1999, and Wisconsin law gives its 
utilities the option of joining an ISO or selling their transmission 
assets to an independent transmission company by June 30, 2000. In both 
states, the backstop is a single-state organization if regional 
organizations are not developed. Recently, Virginia,40 
Arkansas 41 and Ohio42 have also enacted 
legislation requiring their electric utilities to join or establish 
regional transmission entities.
---------------------------------------------------------------------------

    \40\ See Virginia Electric Utility Restructuring Act, S1269 
(Mar. 25, 1999). In Virginia, electric utilities are required by 
January 2001, to join or establish regional transmission entities.
    \41\ See The Arkansas Electric Consumer Choice Act of 1999, Act 
1, 82nd General Assembly (Apr. 1999).
    \42\ See Amended Substitute Senate Bill No. 3, 123rd General 
Assembly (July 6, 1999).
---------------------------------------------------------------------------

    The approved ISOs have similarities as well as differences. All 
five Commission-approved ISOs operate, or propose to operate, as non-
profit organizations. All five ISOs include both public and non-public 
utility members. However, among the five, there is considerable 
variation in governance, operational responsibilities, geographic scope 
and market operations. Four of the ISOs rely on a two-tier form of 
governance with a non-stakeholder governing board on top that is 
advised, either formally or informally, by one or more stakeholder 
groups. In general, the final decision making authority rests with the 
independent non-stakeholder board. One ISO, the California ISO, uses a 
board consisting of stakeholders and non-stakeholders.
    Four of the five ISOs operate a single control area, but the large 
Midwest ISO does not currently plan to operate a single control area. 
Three are multi-state ISOs (New England, PJM and Midwest), while two 
ISOs (California and New York) currently operate within a single state. 
The current Midwest ISO members do not encompass one contiguous 
geographic area. The ISO New England administers a separate NEPOOL 
tariff, while the other four administer their own ISO transmission 
tariffs.
    Three ISOs operate or propose to operate centralized power markets 
(New England, PJM and New York), and one ISO (California) relies on a 
separate power exchange (PX) to operate such a market.43 The 
Midwest ISO has not proposed an ISO-related centralized market for its 
region.44 In addition, at least one separate PX has begun to 
do business in California apart from the PX established through the 
restructuring legislation.45
---------------------------------------------------------------------------

    \43\ The California PX offers day-ahead and hour-ahead markets 
and the ISO operates a real-time energy market. Participation in the 
PX market is voluntary except that the three traditional investor-
owned utilities in California must bid their generation sales and 
purchases through the PX for the first five years. New York will 
offer day-ahead and real-time energy markets that will be operated 
by the ISO. PJM and New England offer only real-time energy markets, 
although PJM has proposed to operate a day-ahead market. The ERCOT 
ISO is the only other ISO that does not currently operate a PX.
    \44\ There are indications, however, that the Midwest ISO is 
considering the formation of a power exchange. See Joint Committee 
for the Development of a Midwest Independent Power Exchange, 
``Solicitation of Interest-Creation of an Independent Power Exchange 
for the U.S. Midwest,'' February 5, 1999.
    \45\ See Automated Power Exchange, Inc., 82 FERC para. 61,287, 
reh'g denied, 84 FERC para. 61,020 (1998), appeals docketed, No. 98-
1415 (D.C. Cir. Sept. 14, 1998) and No. 98-1419 (D.C. Cir. Sept. 14, 
1998).
---------------------------------------------------------------------------

    The existing ISOs are also evolving in terms of their governance 
structure and as a result of operating experience with the transmission 
systems and the various markets they operate. For example, the 
Commission rejected the original governance proposals for two ISOs: the 
New England ISO and New York ISO. In both cases, the Commission 
concluded that the vertically integrated utility members of the ISO 
would have too much voting power in the various advisory committees 
that provide advice and recommendations to the non-stakeholder Boards. 
The ISOs resubmitted governance proposals that gave balanced 
representation to the various sectors of stakeholders, and the 
Commission subsequently approved both revised governance structures.
    In addition, the Commission has considered a number of significant 
modifications of market rules proposed by the existing ISOs in the 
seven months since issuance of the RTO

[[Page 816]]

NOPR. In particular, a number of rules for the California ISO and New 
England ISO have been modified, affecting the products traded in, and 
the timing of, the markets for energy, ancillary services, balancing 
services and transmission.
    An additional few transmission restructuring proposals that were 
pending as of the date of issuance of the RTO NOPR have been approved 
by the Commission, and others have been filed since that date. In July 
1999, the Commission granted a petition for declaratory order filed by 
Entergy Services Inc., in which the majority concluded that passive 
ownership of a transmission entity by a generating company or other 
market participant could meet the ISO principles contained in Order No. 
888. The order stated, however, that the passive ownership must be 
properly designed, such that the transmission entity is truly 
independent of the market participants.46 Another filing 
that was pending when the NOPR was issued was the request by 
FirstEnergy to sell its transmission assets to a newly-formed 
affiliate. The Commission approved the disposition of jurisdictional 
facilities, noting that the proposed action would not adversely affect 
competition, rates or regulation. In addition, the Commission noted 
that the creation of the transmission-owning affiliate would facilitate 
the subsequent transfer of FirstEnergy's transmission facilities to an 
RTO, which FirstEnergy pledged to do within two years of Commission 
approval of the disposition of facilities to its 
affiliate.47
---------------------------------------------------------------------------

    \46\ See Entergy Services, Inc., 88 FERC para. 61,149 (1999) 
(Commissioner Massey dissented from this order).
    \47\ See FirstEnergy Operating Companies, et al., 89 FERC para. 
61,090 (1999).
---------------------------------------------------------------------------

    Since issuance of the RTO NOPR, the Alliance Companies filed a 
proposal to create an RTO. Applicants suggest that the RTO could take 
one of two forms, either an ISO or a transco, but note that they prefer 
a transco configuration in which, at least initially, the five 
transmission-owning participants could hold five percent ownership 
stakes in the transco.48
---------------------------------------------------------------------------

    \48\ See Application of Alliance Companies in Docket No. ER99-
3144-000 (filed June 3, 1999). The Commission issued an order on 
this application concurrently with the issuance of this Final Rule. 
See Alliance Companies, 89 FERC para.____ (1999) (Alliance 
Companies).
---------------------------------------------------------------------------

    Not all efforts to create ISOs have been successful. For example, 
after more than two years of effort, the proponents of the IndeGO 
(Independent Grid Operator) ISO in the Pacific Northwest and Rocky 
Mountain regions ended their efforts to create an ISO.49 
More recently, members of the Mid-American Power Pool (MAPP), an 
existing power pool that covers six U.S. states and two Canadian 
provinces, failed to achieve consensus for establishing a long-planned 
ISO.50 In the Southwest, proponents of the Desert STAR ISO 
have not been able to reach agreement to date on a formal proposal 
after more than two years of discussion.51 In the interim 
period, some of the participants in the Desert STAR ISO have filed at 
the Commission a proposal to create the Mountain West Independent 
Scheduling Administrator, which would oversee the scheduling of 
transmission service within Nevada.52
---------------------------------------------------------------------------

    \49\ Recently, however, parties in the Pacific Northwest have 
resumed RTO discussions.
    \50\ However, trade press reports suggest that while MAPP 
members continue to try to reach consensus, the Midwest ISO is in 
discussion with MAPP members to join the Midwest ISO. See Inside 
FERC, July 26, 1999; The Energy Report, Nov. 1, 1999 at 931.
    \51\ Recent press reports, however, indicate that Desert STAR 
has incorporated as a non-profit organization, a first step toward 
the launch of an ISO. See Energy Daily, Nov. 5, 1999 at 2.
    \52\ See Application of Mountain West Independent Transmission 
Administrator in Docket No. ER99-3719-000 (filed July 23, 1999).
---------------------------------------------------------------------------

    Various reasons have been advanced to explain the difficulty in 
forming a voluntary, multi-state ISO. Reasons include: ``cost 
shifting,'' which involves increases in transmission rates for some 
parties; disagreements about sharing of ISO transmission revenues among 
transmission owners; difficulties in obtaining the participation of 
publicly-owned transmission facilities; concerns about the loss of 
transmission rights and prices embedded in existing transmission 
agreements; and the preference of certain transmission owners to sell 
or transfer their transmission assets to a for-profit transmission 
company in lieu of handing over control to a non-profit ISO.
3. The Commission's ISO and RTO Inquiries; Conferences With 
Stakeholders and State Regulators
    In light of the various restructuring activities occurring 
throughout the United States, the Commission has held 11 public 
conferences in nine different cities across the country to hear the 
views of industry, consumers, and state regulators with respect to the 
need for RTOs and their appropriate roles and responsibilities.
    The Commission initiated an inquiry in March 1998 pertaining to its 
policies on ISOs. A notice establishing procedures for a conference 
gave the following rationale:

    In Order Nos. 888 and 889 and their progeny, the Commission 
established the fundamental principles of non-discriminatory open 
access transmission services. Nevertheless, many issues remain to be 
addressed if the Nation is to fully realize the benefits of open 
access and more competitive electric markets.
* * * * *
    Given the dramatic changes taking place in both wholesale and 
retail electric markets and the many proposals under consideration 
with respect to the creation of ISOs or other transmission entities, 
such as transmission-only utilities, it is time for the Commission 
to take stock of its policies in order to determine whether they 
appropriately support our dual goals of eliminating undue 
discrimination and promoting competition in electric power 
markets.53

    \53\ Inquiry Concerning the Commission's Policy on Independent 
System Operators, Notice of Conference, Docket No. PL98-5-000, at 1-
2 (March 13, 1998).

Accordingly, the Commission held a series of eight conferences in 1998 
to gain insight into participants' views on the formation and role of 
ISOs in the electric utility industry. The first conference was held in 
April 1998 at the Commission's offices in Washington, D.C. Between May 
28 and June 8, 1998, the Commission held seven regional conferences in 
Phoenix, Kansas City, New Orleans, Indianapolis, Portland, Richmond and 
Orlando. As a result of these conferences, the Commission heard 
approximately 145 oral presentations and received a large number of 
written comments on the appropriate size, scope, organization and 
functions of regional transmission institutions. A number of different 
of viewpoints were expressed.54
---------------------------------------------------------------------------

    \54\ A summary of those views was included as Appendix A to the 
NOPR in this docket.
---------------------------------------------------------------------------

    On October 1, 1998, the Secretary of Energy delegated his authority 
under section 202(a) of the FPA to the Commission. In doing so, the 
Secretary stated that section 202(a) ``provides DOE with sufficient 
authority to establish boundaries for Independent System Operators 
(ISOs) or other appropriate transmission entities.'' 55 The 
Secretary also stated: ``FERC is also increasingly faced with 
reliability-related issues. Providing FERC with the authority to 
establish boundaries for ISOs or other appropriate transmission 
entities could aid in the orderly formation of properly-sized 
transmission institutions and in addressing reliability-related issues, 
thereby increasing the reliability of the transmission system.''
---------------------------------------------------------------------------

    \55\ 63 FR 53,889 (Oct. 7, 1998).
---------------------------------------------------------------------------

    On November 24, 1998, we gave notice in this docket of our intent 
to initiate a consultation process with State commissions pursuant to 
section

[[Page 817]]

202(a).56 The purpose of the consultations was to afford 
State commissions a reasonable opportunity to present their views with 
respect to appropriate boundaries for regional transmission 
institutions and other issues relating to RTOs. Conferences with State 
commissioners were held in St. Louis, Missouri, on February 11, 1999; 
in Las Vegas, Nevada, on February 12, 1999; and in Washington, D.C., on 
February 17, 1999. In all, we heard oral presentations by 
representatives of 41 state commissions during these consultations, 
with others monitoring or providing written comments.57 
During these sessions, we received much valuable advice. Furthermore, 
we have had additional consultations since issuance of the RTO NOPR in 
May 1999.
---------------------------------------------------------------------------

    \56\ Regional Transmission Organizations, Notice of Intent to 
Consult with State Commission, 63 FR 66,158 (Dec. 1, 1998), FERC 
Stats & Regs. para. 35,534 (1998).
    \57\ See Appendix for a list of commenters.
---------------------------------------------------------------------------

III. Discussion

A. Existing Barriers and Impediments To Achieving Fully Competitive 
Electricity Markets

    In the NOPR, the Commission expressed its belief that there remain 
important transmission-related impediments to a competitive wholesale 
electric market. The Commission grouped these remaining impediments 
into two broad categories: (1) The engineering and economic 
inefficiencies inherent in the current operation and expansion of the 
transmission grid, and (2) continuing opportunities for transmission 
owners to unduly discriminate in the operation of their transmission 
systems so as to favor their own or their affiliates' power marketing 
activities.58
---------------------------------------------------------------------------

    \58\ FERC Stats. & Regs. para. 32,541 at 33,696.
---------------------------------------------------------------------------

    With respect to engineering and economic inefficiencies, the NOPR 
noted that the transmission facilities of any one utility in a region 
are part of a larger, integrated transmission system which, from an 
electrical engineering perspective, operates as a single 
machine.59 Engineering and economic inefficiencies occur 
because each separate operator usually makes independent decisions 
about the use, limitations and expansion of its piece of the 
interconnected grid based on incomplete information, even though any 
action taken by one transmission provider can have major and 
instantaneous effects on the transmission facilities of all other 
transmission providers. The Commission noted that, while this was not a 
new phenomenon, the demands placed on the transmission grid had changed 
in recent years due to (1) increases in bulk power trade, (2) large 
shifts in power flows, and (3) an increasingly de-integrated and 
decentralized competitive power industry.60 As a consequence 
of these changes in trade patterns and industry structure, certain 
operational problems had become more significant and difficult to 
resolve.
---------------------------------------------------------------------------

    \59\ Id. at 33,697.
    \60\ See id.
---------------------------------------------------------------------------

    Engineering and Economic Inefficiencies. The NOPR identified a 
number of specific economic and engineering inefficiencies. First, the 
NOPR noted that the reliability of the nation's bulk power system was 
being stressed in ways that have never been experienced before, and 
questioned the continued feasibility of one-on-one coordination of an 
interconnected transmission grid encompassing more than 100 
transmission owners and 140 separate control areas.61 
Second, the NOPR observed that there were increasing difficulties in 
accurately computing Total Transmission Capacity (TTC) and Available 
Transmission Capacity (ATC), assessments that require reliable and 
timely information about load, generation, facility outages and 
transactions on neighboring systems, as well as consistency in 
methodologies among systems.62 Third, the NOPR noted that 
efficient congestion management required regional actions, and that the 
current methods for managing congestion (e.g., Transmission Line 
Loading Relief procedures in the Eastern Interconnection), which do not 
attempt to optimize regional congestion relief, were cumbersome, 
inefficient and disruptive to bulk power markets.63 Fourth, 
the NOPR expressed concern that the uncertainty associated with 
transmission planning and expansion had increased with the increasing 
number and distance of unbundled transactions and the wider variation 
in generation dispatch patterns. The NOPR pointed to a noticeable 
decline in planned transmission investments and expressed concern that, 
without a regional approach to planning and expansion, it would be 
difficult to address complex and controversial issues that arise when 
the benefits of an expansion do not necessarily accrue to the 
transmission system that must undertake the expansion.64 
Finally, the NOPR explained that pancaked transmission rates (where a 
separate access charge is assessed every time the transaction contract 
path crosses the boundary of another transmission owner) restrict the 
size of regional power markets. The Commission added that the 
balkanization of electricity markets hurts consumers who pay higher 
transmission rates and have access to fewer generation 
options.65
---------------------------------------------------------------------------

    \61\ See id. at 33,699.
    \62\ Id. at 33,700.
    \63\ Id. at 33,701-02.
    \64\ See id. at 33,702-03.
    \65\ Id. at 33,703.
---------------------------------------------------------------------------

    Continuing Opportunities for Undue Discrimination. With respect to 
continuing opportunities for undue discrimination, the NOPR observed 
that, when utilities control monopoly transmission facilities and also 
have power marketing interests, they have poor incentives to provide 
equal quality transmission service to their power marketing 
competitors.66 The NOPR explained that the Commission had 
made this point in Order No. 888:
---------------------------------------------------------------------------

    \66\ Id. at 33,704.

    It is in the economic self-interest of transmission monopolists, 
particularly those with high-cost generation assets, to deny 
transmission or to offer transmission on a basis that is inferior to 
that which they provide themselves. The inherent characteristics of 
monopolists make it inevitable that they will act in their own self-
interest to the detriment of others by refusing transmission and/or 
providing inferior transmission to competitors in the bulk power 
markets to favor their own generation, and it is our duty to 
eradicate unduly discriminatory practices.67
---------------------------------------------------------------------------

    \67\ Order No. 888, FERC Stats. & Regs. para. 31,036 at 31,682.

In the NOPR, the Commission noted that functional unbundling does not 
change the incentives of vertically integrated utilities to use their 
transmission assets to favor their own generation, but instead attempt 
to reduce the ability of utilities to act on those 
incentives.68
---------------------------------------------------------------------------

    \68\ As noted in the NOPR, in Order No. 888, the Commission 
received and considered numerous comments that functional unbundling 
was unlikely to work, and that more drastic restructuring, such as 
corporate unbundling, was needed. For example, the Federal Trade 
Commission advised the Commission that a functional unbundling 
approach ``* * * would leave in place the incentive and opportunity 
for some utilities to exercise market power in the regulated system. 
Preventing them from doing so by enforcing regulations to control 
their behavior may prove difficult.'' However, the Commission 
decided at the time to adopt the less intrusive and less costly 
remedy of functional unbundling. FERC Stats. & Regs. para. 32,541 at 
33,707.
---------------------------------------------------------------------------

    The NOPR expressed concern about continuing indications that 
transmission service problems related to discriminatory conduct remain 
and concluded that these problems are impeding competitive wholesale 
power markets.69 The NOPR also noted that

[[Page 818]]

instances of actual discrimination may be undetectable in a non-
transparent market and, in any event, it is often hard to determine, on 
an after-the-fact basis, whether an action was motivated by an intent 
to favor affiliates or simply reflected the impartial application of 
operating or technical requirement. The NOPR added that, while 
continued discrimination may be deliberate, it could also result from 
the failure to make sufficient efforts to change the way integrated 
utilities have done business for many years. The Commission expressed 
concern that the difficulty in determining whether there has been 
compliance with our regulations raises the question as to whether 
functional unbundling is an appropriate long-term regulatory solution.
---------------------------------------------------------------------------

    \69\ The NOPR described specific examples of undue 
discrimination that had been brought to its attention through formal 
complaints, informal complaints made to the Commission's enforcement 
hotline, oral and written comments made in conjunction with public 
conferences held by the Commission, and pleadings filed with the 
Commission in various dockets. The complaints generally involved: 
(1) Calculation and posting of ATC in a manner favorable to the 
transmission provider; (2) standards of conduct violations, (3) line 
loading relief and congestion management, and (4) OASIS sites that 
are difficult to use. See id. at 33,707-13.
---------------------------------------------------------------------------

    The NOPR explained that the Commission considers allegations of 
discrimination, even if not reduced to formal findings, to be a serious 
concern for two reasons. First, this can be indicative of additional, 
unreported, discriminatory actions, because there are significant 
disincentives to filing and pursuing formal complaints that would 
result in definitive findings.70 The NOPR expressed a 
concern that actual problems with functional unbundling may be more 
pervasive than formally adjudicated complaints would suggest. Second, 
the NOPR explained that allegations of discrimination are serious 
because, if nothing else, they represent a perception by market 
participants that the market is not working fairly. If market 
participants perceive that other participants have an unfair advantage 
through their ownership or control of transmission facilities, it can 
inhibit their willingness to participate in the market, thus thwarting 
the development of robust competition. The NOPR added that such 
mistrust can also harm reliability.71
---------------------------------------------------------------------------

    \70\ As noted in the NOPR, transmission customers are reluctant 
to make even informal complaints because they fear retribution by 
their transmission supplier; the complaint process is costly and 
time-consuming; the Commission's remedies for violations do not 
impose sufficient financial consequences on the transmission 
provider to act as a significant deterrent; and, in the fast-paced 
business of power marketing, there may be no adequate remedy for the 
lost short-term sales opportunities in after-the-fact enforcement. 
See FERC Stats. & Regs. para. 32,541 at 33,706.
    \71\ Id.
---------------------------------------------------------------------------

    The NOPR explained the potential for undue discrimination increases 
in a competitive environment unless the market can be made structurally 
efficient and transparent with respect to information, and equitable in 
its treatment of competing participants. Also, a system that attempts 
to control behavior that is motivated by economic self-interest through 
the use of standards of conduct will require constant and extensive 
policing and requires the Commission to regulate detailed aspects of 
internal company policy and communication. The NOPR added that 
functional unbundling does not necessarily promote light-handed 
regulation and undoubtedly imposes a cost on those entities that have 
to comply with the standards of conduct and abide by rules that limit 
the flexibility of their internal management activities. The NOPR 
stated that the perception that many entities that operate the 
transmission system cannot be trusted is not a good foundation on which 
to build a competitive power market, and it created needless 
uncertainty and risk for new investments in generation.72
---------------------------------------------------------------------------

    \72\ See id. at 33,714.
---------------------------------------------------------------------------

    Comments. Engineering and Economic Inefficiencies. Virtually all 
commenters support the NOPR's premise that engineering and economic 
inefficiencies exist in the operation, planning and expansion of the 
regional transmission grid and that these inefficiencies hinder 
electric system reliability and a fully competitive bulk power 
market.73 Many commenters state further that, in the new 
industry structure, coordinated regional transmission planning has 
become a thing of the past and new transmission additions that will 
benefit reliable grid operations are being delayed.74
---------------------------------------------------------------------------

    \73\ See, e.g., Duquesne, Entergy, Florida Power Corp., NU, 
Kentucky Commission, NECPUC, Ohio Commission, Texas Commission, DOE, 
American Forest, Arkansas Cities, East Texas Cooperatives, EPSA, 
First Rochdale, FMPA, Oglethorpe, PNGC, Powerex, Public Citizen, 
SoCal Cities, Sonat, Williams.
    \74\ See, e.g., EPRI, Florida Power Corp, Duquesne, Entergy, 
SoCal Cities, Merrill Energy, TAPS, IPCF, Powerex.
---------------------------------------------------------------------------

    FMPA states that grid fragmentation harms reliability.75 
NU and EPRI note that recent demand growth has meant new stresses on 
grid reliability and there is less coordination of generation and 
transmission planning. TXU Electric states that, as the shift from 
regulation to competition accelerates, and restructuring efforts 
proliferate, the regional transmission grid is being exposed to 
stresses that cannot be alleviated without regional solutions.
---------------------------------------------------------------------------

    \75\ FMPA at 24.
---------------------------------------------------------------------------

    WPPI describes a situation in 1997 in which the 345-kV transmission 
facility between MAPP and MAIN was overloaded as a result of 
transactions scheduled within MAPP, and Wisconsin operators became 
aware of the problem only when the constrained 345-kV facility 
automatically separated in response to the overload. WPPI explains 
that, with the 345-kV facility shut down, other transmission facilities 
in the region overloaded, causing the transmission system over a large 
region to come perilously close to a blackout. WPPI adds that, because 
transmission providers do not have information about their neighbors' 
on-system transactions to serve native load, they are unable to predict 
the impact of potential TLR events. WPPI says that, in the face of this 
uncertainty, transmission providers have to make overly conservative, 
but inaccurate assumptions which unnecessarily reduce the amount of 
transmission capacity available to the market.
    TAPS states that, when the owners of a constrained interface 
between MAPP and MAIN tried to remove the line for service for 
maintenance, they found that 500 MW of flow remained on the line even 
after all scheduled transactions were terminated. TAPS explains that 
there were so many transactions in the region at the time that 
transmission operators could not determine the source of this 500 MW 
loop flow and were unable to ask other parties to cut their schedules 
to permit the necessary maintenance.76 TAPS asserts that 
transmission owners have engaged in ``creative'' concepts such as CBM 
to reduce ATC and argues that price spikes are exacerbated, if not 
caused by the failure to have regional transmission information and 
control in one place.77
---------------------------------------------------------------------------

    \76\ TAPS, Appendix A, at 8
    \77\ TAPS, Appendix A at 2-5.
---------------------------------------------------------------------------

    TDU Systems complaint that the current system balkanizes regions 
into a series of submarkets, each with its own dominant incumbent 
transmission owner/generator that collects its own transmission toll.
    EPRI contends that the current off-line ATC calculations result in 
inconsistencies of ATC values. Entergy argues that the accuracy of ATC 
will continue to be a problem as long as contract path pricing is 
used.78
---------------------------------------------------------------------------

    \78\ Entergy at 8.
---------------------------------------------------------------------------

    Minnesota Power notes that reliability across the broader region 
suffers simply because of different standards for ATC calculations 
within and across NERC

[[Page 819]]

regions and, indeed, different terminology and operating practices. 
Minnesota Power states that: the market currently suffers as 
participants attempt to deal with multiple OASIS sites; existing 
tagging and reservation practices that limit transactions due to the 
complexity of arrangements; its transactions are subject to curtailment 
pursuant to two different procedures, NERC TLR and MAPP LLR; and 
congestion management alternatives to line loading relief have not 
succeeded because they lack regional coordination. Minnesota Power 
argues that energy price volatility will continue to increase unless 
there is a viable process, supported by transmission rights and 
secondary transfer markets, where a participant can secure transmission 
daily, or as needed, to bring the least cost supply to its customers.
    EPSA asserts that one of the major impediments to robust 
competitive bulk power markets is the current balkanization of the 
system with dozens of individual utilities, NERC Regional Councils, and 
security coordinators, and state laws and regulations imposing a 
patchwork of often inconsistent and incompatible rules for the use of 
the interstate transmission system. EPSA argues that the operational 
and economic inefficiencies detailed in the NOPR are not unique to 
certain region as and may be most pronounced in those regions where 
competition has yet to take hold.79
---------------------------------------------------------------------------

    \79\ EPSA specifically points to the SERC as a region where 
``state commissions and utilities may be arguing that they don't 
`need' RTOs to promote competitive markets,'' at a time when 
Southeastern markets trail the rest of the nation in proposed 
merchant plant development and power trading, ``both hallmarks of 
robust wholesale competition and workable open access policies.'' 
EPSA notes that SERC is the largest NERC region, both in load and 
peak demand, yet SERC and FRCC together constitute only 5.2 percent 
of the wholesale power trades nationwide.
---------------------------------------------------------------------------

    SoCal Edison states that existing transmission systems were 
designed to serve native load customers in a defined area, in the most 
efficient manner possible, in conjunction with the generation that it 
owned and operated, and were not designed to function as common 
carriers. SoCal Edison concludes that that radical changes in 
downstream generation markets are having, and will continue to have, 
significant and largely adverse effects of transmission systems. 
Consumers Energy echoes this concern, noting that it should be obvious 
that the current transmission system was designed to deliver locally 
generated power to local markets with interfaces used primarily for 
reliability purposes. Consumers Energy states that the system is simply 
not engineered to move large quantities of power from many distant 
generation sources to millions of end users.
    Williams concludes that problems with congestion management, 
pancaked transmission rates, parallel path or loop flows, inaccurate 
ATC postings, and transmission facilities management and expansion 
planning continue to impede the development of robust, competitive 
wholesale electric markets in the United States.
    PECO states that current TLR procedures allow one entity to cause 
the curtailment of numerous third party transactions on a regular basis 
to preserve power delivery in its single control area, regardless of 
the impact on other control areas. PECO argues that, while physical 
operation of the grid is maintained under these TLR procedures, 
reliable, inter-control area power delivery is not assured and market 
participants are denied fair access to the grid.
    Tampa Electric states that, within peninsular Florida, transmission 
users must often go to several individual transmission providers and 
OASIS nodes, sign multiple agreements with various providers and 
attempt to piece together and navigate through various partial paths to 
connect a power sale to a buyer. Tampa Electric concludes that access 
to transmission services within this region is not as open as it could 
be to facilitate an efficient, robust wholesale market.
    AEP states that coordination that previously existed in a fully 
integrated electric system of the construction of new generation and 
transmission facilities has eroded due to the separation of these 
functions. AEP states that congestion constraints could potentially 
inhibit the development of additional generation capacity or provide a 
disincentive to add generating capacity where needed. AEP also notes 
that the priorities of state regulatory agencies sometimes favor the 
needs of native load customers that can create conflicts among 
competing interest at the regional level. AEP also states that 
developers of new merchant generation plants have become less willing 
to share their long-term planning goals with transmission owners due to 
the business strategies that accompany a more competitive power market. 
However, AEP argues that removal of pancaking is not consistent with 
economic efficiency and may distort future transmission expansion 
because the cost of transmission should be based on distance and 
location.\80\
---------------------------------------------------------------------------

    \80\ AEP at 1, and Attachment to AEP's comments (Statement of 
Paul Moul). As discussed in the Transmission Ratemaking section 
(Section G), elimination of pancaked rates (multiple access charges 
assessed only because the transaction crosses a corporate boundary) 
does not constitute a prohibition on distance sensitive rates.
---------------------------------------------------------------------------

    Several commenters state that needed transmission expansion is not 
taking place because of a lack of pricing incentives to build new 
transmission.\81\ EPRI states that failure to satisfy grid expansion 
needs is resulting in increasing frequency and duration of power 
disturbances and outages costing $50 billion per year.
---------------------------------------------------------------------------

    \81\ See, e.g., Transmission ISO Participants, H.Q. Energy 
Services, Powerex.
---------------------------------------------------------------------------

    WPPI points out that transmission planning must be undertaken on a 
regional, not a state basis, noting that import capability from MAPP 
into Wisconsin is sometimes constrained by facilities located outside 
of Wisconsin, e.g., transformers and lines located in Illinois and 
Minnesota. On the other hand, Allegheny asserts that the industry has 
not failed to plan and coordinate on a regional basis and cites 
examples of study groups and planning committees, such as VEM 
(Virginia-ECAR-MAAC) and GAPP (General Agreement on Parallel Paths).
    Most commenters assert that pancaked transmission access charges 
prevent efficient access to regional markets and distort the generation 
market.\82\ A few commenters, however, question the benefits associated 
with eliminating rate pancaking. Southern Company observes that the 
severity of pancaking effects may vary from region to region.\83\
---------------------------------------------------------------------------

    \82\ See, e.g., FMPA, IMEA, NECPUC, Ohio Commission, Texas 
Commission, American Forest, Arkansas Cities, East Texas 
Cooperatives, Oglethorpe, PNGC, Powerex, Williams, WPSC.
    \83\ For illustration, Southern Company points out that a 
customer in its service area can transmit power 500 miles away for 
$3/MWh whereas a customer wanting to transmit power from Boston to 
Washington, DC (also a distance of 500 miles) will have to go 
through the three PJM, New England and NY ISOs and pay a total of 
approximately $14/MWh.
---------------------------------------------------------------------------

    Continuing Opportunities for Undue Discrimination. Comments dealing 
with continuing opportunities for undue discrimination fall generally 
into two camps. On the one side, transmission customers and some 
transmission providers agree with the NOPR's premise that opportunities 
for discrimination exist, that perceptions of discrimination are also a 
serious impediment to competitive bulk power markets, and that 
functional unbundling does not reflect the optimal long-term regulatory 
solution.\84\ On the other side,

[[Page 820]]

a number of transmission providers disagree with these premises.\85\
---------------------------------------------------------------------------

    \84\ E.g., American Forest, Los Angeles, TAPS, UAMPS, Steel 
Dynamics, Turlock, Cinergy, Statoil, WPPI, NJBUS, MidAmerican, LG&E, 
Clarksdale, Michigan Commission, New Smyrna Beach, Industrial 
Consumers, IMPA, First Rochdale, East Texas Cooperatives, FMPA, TDU 
Systems, Canada DNR, Allegheny, IMEA, Sonat, Public Citizen, EPSA, 
CCEM/ELCON, UtiliCorp and FTC. [85]:United Illuminating, Southern 
Company, MidAmerican, Duke, PSE&G, FP&L, Entergy, FirstEnergy, 
Alliance Companies, Lenard and Florida Power Corp.
    \85\ United Illuminating, Southern Company, MidAmerican, Duke, 
PSE7G, FP&L, Entergy, First Energy, Alliance Companies, Lenard and 
Florida Power Corp.
---------------------------------------------------------------------------

    Comments Asserting That Discrimination Still Exists. AMP-Ohio 
points to an event last summer when it was unable to transmit power 
from a generator on AEP's system to a load on the FirstEnergy system 
and was forced to purchase power from FirstEnergy at $4000/MWh. AMP-
Ohio contends that AEP and FirstEnergy were simultaneously reporting 
zero ATC during the hour, i.e., an event that cannot be rationalized by 
AMP-Ohio (i.e., an interface that is fully loaded in both directions at 
the same time would, in AMP-Ohio's view, cancel out).
    UAMPS argues that three transmission owners that jointly own 
segments of a single transmission line have avoided releasing the 
capacity of this line under their open access tariffs through a series 
of contractual arrangements that distributes transmission rights 
directly to each of their merchant functions. As a result, only the 
transmission owners' merchant functions have the ability the schedule 
transmission service over the line. UAMPS contends that this example, 
and others, confirm the Commission's perception that the remedies 
mandated in Order No. 888 have not eliminated discrimination. UAMPS 
states that it is intuitively obvious that when the transmission 
function and merchant function ultimately serve the same master, 
neither can be truly independent.
    Hogan contends that, without an efficient regional spot market and 
its ease of access, the problems of discrimination will persist. FTC 
concludes that several years of industry experience confirm the concern 
that discrimination remains in the provision of transmission services 
by utilities that continue to own both generation and transmission. FTC 
concludes that reliance on behavioral rules have proved to be less than 
ideal.
    Cinergy contends that reliance on CBM by some transmission 
providers this summer provided their native load an unfair operational 
edge over network service in the import of power through interconnects 
that were the subject of TLR orders. Cinergy argues that the more 
severe impact on market efficiency is caused by the lack of information 
underlying the transmission provider's implementation of TLRs, and 
raises significant opportunities for transmission providers to use 
alleged reliability reasons to hide conduct actually motivated to 
protect their own or their affiliate's own power market. Cinergy 
concludes that market participants will never know the real answer 
because it may be impossible to prove abuse of the TLR procedures with 
access to information on the nature and cause of constraints and the 
lack of consistency in implementing TLRs across the regions. Cinergy 
adds that, even where there may be sufficient evidence to prove 
discrimination, potential complainants may fear retribution by the 
transmission provider, and may also be hesitant to file complaints 
because of the litigation costs of the complaint process and the lack 
of remedy for lost short-term market opportunities.
    Enron/APX/Coral Power state that the following types of relatively 
overt, although difficult to detect, discrimination occur: (1) Offers 
of attractive transmission service to a transmission owner's affiliate 
or merchant function that are not similarly offered to others; (2) 
advance notification to the affiliate or merchant function of the 
availability of transmission service or the availability of a new 
service; and (3) changes in procedures, such as scheduling deadlines, 
for obtaining transmission service in ways that benefit the affiliate 
or merchant function. Enron/APX/Coral Power (as well as CCEM/ELCON, 
UtiliCorp and EPSA) also argue that a ``principal form of 
discrimination grows out of the exemption from the pro forma OATT and 
OASIS that is enjoyed by transmission bundled with service to captive 
`native-load' customers.'' Enron/APX/Coral Power believes that, if the 
Commission were to conduct an investigation of compliance with the 
Commission's open access requirements and the uses of their own 
transmission system during periods of extreme peak loads and volatile 
prices during the past summer, the Commission would uncover evidence of 
widespread abuses. According to Enron/APX/Coral Power, these abuses 
would include instances where the transmission provider imported power 
on a network basis, as if it were intended to service captive, native 
load customers, only to turn around and sell that power competitively, 
off-system; where scheduling requirements or deadlines were changed 
without adequate notice to third parties; and where ATC amounts that 
either were not posted or were posted in an untimely manner.
    NASUCA concludes that, despite Order No. 888, there is still reason 
for concern that continued discrimination in the provision of 
transmission services by vertically integrated utilities may be 
impeding competitive electric markets.
    EPSA states that the prospect of real competition continues to be 
threatened by (1) arbitrary and discriminatory curtailment and line 
loading relief policies, and (2) needlessly complex and overly 
restrictive transmission planning, expansion and interconnection 
practices.
    TAPS argues that the anticompetitive effects of allowing a subset 
of competitors to control essential facilities have been long 
recognized.\86\ TAPS provides specific examples that it claims show 
that discrimination exists: (1) The price spikes in June 1998 and 
Summer of 1999 where the asserted ATC was inadequate to allow external 
generation resources to meet the needs of the market; (2) failure of a 
transmission owner to provide necessary upgrades; and (3) a 
transmission owner taking negotiating positions contrary to a clear 
provision of the Open Access Transmission Tariff (OATT). In its reply 
comments, TAPS describes a recent situation where AEP, acting in its 
role as the NERC Security Coordinator, informed IMPA that it had 
implemented a TLR seven minutes earlier, too late for IMPA to replace 
the curtailed schedule with another transaction at market prices, which 
were $35/MWh. TAPS contends that IMPA had no effective choice but to 
make up the shortfall by purchasing emergency energy from AEP at $100/
MWh. In following hours that day, IMPA elected to purchase power from 
AEP at $35/MWh rather than continue its other purchase options (at $17/
MWh) and risk further curtailments. TAPS observes that AEP 
substantially profited from delayed communication of the TLR, by 
selling power to IMPA at nearly three times the then-market price. TAPS 
states that, even assuming AEP was acting properly on this occasion, 
this example illustrates the inherent conflict of interest in combining 
security coordinator functions with that of market participant. TAPS 
argues that this diminishes the faith in the market place and breeds 
mistrust. Based on the examples it provides and on the evidence 
reviewed in the NOPR, TAPS

[[Page 821]]

recommends that the Final Rule make formal findings that undue 
discrimination remains widespread throughout the industry.
---------------------------------------------------------------------------

    \86\ TAPS cites to a 1912 Supreme Court case involving the 
control of a railway terminal by several railroads which their 
competitors were required to use. See United States v. Terminal RR 
Ass'n, 224 U.S. 383, 397 (1912).
---------------------------------------------------------------------------

    Steel Dynamics states that the Commission needs to build confidence 
that transmission customers will not be victimized when markets get 
tight and claims the Commission's record to date has been uneven. Steel 
Dynamics cites a case in which the Commission determined that Niagara 
Mohawk Power Corporation had committed several violations of the OASIS 
posting requirements and standards of conduct in order to favor its 
marketing affiliate over a third-party user.
    Clarksdale states that it has experienced problems with the posting 
of ATC by Entergy on the OASIS. Clarksdale states that on July 21, 
1999, it attempted to purchase from Cajun Electric Cooperative 20 MW of 
power for whatever length of time that Cajun would have had it 
available up to one week. Entergy denied the transaction on the basis 
that the ATC between Entergy and Cajun was zero. Clarksdale complained 
and the next day the ATC for this interface was shown to be 1,700 
megawatts; however, by that time Cajun had sold the power to another 
entity and it was no longer available for Clarksdale. Clarksdale 
submits that the incident, along with others Clarksdale reported, 
compels the conclusion that the function of security coordination 
should be entirely separate from the transmission owner and from the 
generation owner and that participation in an absolutely independent 
RTO should be mandated by the Commission in the final rule.
    FMPA states that, whether because of discriminatory motivations or 
simply because of balkanized perspectives (or both), there have been 
numerous instances of Florida's dominant transmission owners falling 
short on the transmission planning performance. According to FMPA, 
Florida's dominant transmission owners have failed to promptly address 
regionally significant constraints (until addressing them became 
advantageous for their own merchant function), and have continued to 
impose discriminatory transmission-related construction requirements. 
FMPA claims that relying on functional separation rules to curb the 
self interest of market-interested transmitters when huge sums of money 
are at stake is like ``relying on words to hold back the tide.'' \87\
---------------------------------------------------------------------------

    \87\ FMPA at 23-24.
---------------------------------------------------------------------------

    WPPI states that it routinely experiences and observes subtle and 
difficult to detect problems in the marketplace. WPPI states that, 
because they are subtle and difficult to detect, they are not 
susceptible to any prompt and effective regulatory remedy. WPPI adds 
that prosecution of complaints is expensive and time consuming and 
customers do not have the ability to prosecute each such incident.
    WPPI contends that transmission owners are able to dispatch their 
resources in order to manipulate their exposure to TLRs, while 
customers cannot. WPPI characterizes this tactic as a ``shell game'' 
because it is purportedly accomplished by designating fictional sources 
and sinks and treating one transaction as two separate transactions. 
WPPI contends that these actions leave other transmission users to bear 
the costs of curtailments and denials of service. WPPI argues that 
these manipulations of TLRs are ``rampant.''
    WPPI states that during summer peak periods, when it claims power 
prices exceeded $5,000/MWh in the Eastern Interconnection, at least one 
Midwestern transmission-owning utility appears to have been able to 
abuse its control-area operator authority to gain a market advantage. 
According to WPPI, as a control-area operator, the transmission owner 
at issue declared that power shortages had created an emergency 
situation which allowed it to relax the transmission limitations that 
it had imposed on other market participants, enabling the transmission 
owner to acquire less expensive power from the MAPP region. WPPI claims 
that the transmission owner thereby gained a market advantage, at a 
time when market advantages were worth huge sums. WPPI claims that most 
if not all other control-area operators in the region played by the 
rules and did not abuse the system to access less expensive power for 
which ATC ostensibly was not available. WPPI asserts that utilities 
that are not control-area operators had no choice other than to buy 
high cost, locally generated power, and that they ``lack not only the 
right, but also the might'' \88\ to declare an emergency or to 
recalculate ATC to help themselves. WPPI and Cinergy maintain that this 
recent event provides a clear example of the continuing potential, 
under present industry structure, for vertically integrated utilities 
to abuse their transmission control to gain market advantages and for 
that reason, among others, the Commission should mandate that entities 
under its jurisdiction participate in RTOs.
---------------------------------------------------------------------------

    \88\ WPPI at 31.
---------------------------------------------------------------------------

    TDU Systems provide a number of examples which raise their concerns 
about undue discrimination, including: (1) Failure of an incumbent IOU 
to reduce its own out-of-region power sales during a period when the 
system was experiencing overloads and the transactions of other 
transmission users were jeopardized; (2) overly aggressive and 
selective enforcement of tariff requirements on transmission customers 
than are imposed on the transmission providers' own merchant function; 
(3) selectively targeting generating units that are jointly owned by 
competitors when redispatch of the transmission system is required to 
relieve line loading; (4) self-serving ATC calculations in 
circumstances when transmission customers have no way of knowing 
whether access is being denied legitimately or through manipulation for 
competitive gain; and (5) onerous and lengthy negotiations to obtain 
system studies. TDU Systems contend that there is a fire under the 
smoke of allegations of discrimination, and those complaining of the 
anecdotal nature of its information haven't provided any evidence to 
show that discrimination is not occurring.
    TXU Electric states that, if a truly successful, restructured 
competitive electric industry is to achieve its full potential, it is 
incumbent of all concerned, transmission providers, users and 
regulators alike, to move beyond the impediments of the past, including 
hidden motivations on the part of some, unfounded fears of hidden 
motivations on the part of others, and a general environment of 
distrust. TXU Electric adds that, transmission users and regulators 
must have confidence that the transmission grid is truly an open, non-
discriminatory and robust commercial highway and transmission providers 
must inspire that confidence. TXU Electric concludes that the 
Commission's voluntary collaborative approach is an important step in 
the right direction.
    LG&E states that, under the current system, transmission owners' 
operational decisions, even if well intentioned, are surrounded by a 
cloud of suspicion that, acting in the name of reliability, the 
transmission owner has enhanced its position in the generation market. 
LG&E agrees that this perception that the transmission system is not 
being operated in an even handed manner undermines confidence in the 
non-discriminatory open access implemented under Order No. 888.
    Virginia Commission agrees that allegations of discrimination 
represent only known problems, and there may be many unknown ones 
remaining given that it is difficult for transmission users

[[Page 822]]

to identify and demonstrate instances of discrimination.
    Canada DNR states that discriminatory behavior by transmission 
operators, identified in the NOPR as the second significant driver for 
establishment of RTOs, is not perceived as a key impediment to the 
evolution of efficient bulk power markets in Canada.
    Dynegy argues that transmission provides have the incentive and 
ability to discriminate in today's markets due to the combination of 
control over transmission with participation in power markets and the 
existing regulatory structure that exempts transmission providers from 
the open access rules of Order Nos. 888 and 889 for its bundled, native 
load customers. Dynegy argues that the ``native load'' exemption can be 
and is often manipulated to favor the transmission providers' own or 
affiliated merchant functions.
    PECO notes that, in their capacity as vertically integrated 
utilities, transmission providers have access to critical market 
sensitive information with respect to each transaction (e.g., source, 
sink), at a time when they are in direct competition in the same 
markets and with the same transmission customers whose market 
information they have. PECO argues that, in spite of the existence of 
functional unbundling and codes of conduct, the serious potential for 
conflicts of interest and abuse inherent in the current structure 
cannot be ignored.
    Comments Asserting That Discrimination Is Not a Problem. A number 
of commenters, mostly transmission owners, do not believe that 
significant discrimination problems remain with respect to wholesale 
transmission access pursuant to Order No. 888. As a general matter, 
those transmission owners whose actions are cited in other pleadings as 
examples of undue discrimination disagree with those characterizations 
of the cited events and declare that they provide non-discriminatory 
transmission service under their OATT. These transmission owners 
contend that the disputes cited in the pleadings are not the result of 
discriminatory practices; rather, they are the result of the priority 
accorded native load customers under the OATT, and good faith errors on 
the part of the transmission provider trying to administer complex 
rules and tariff changes that have necessitated fundamental changes to 
the structure of companies and the way they do business.
    EEI contends that many of the difficulties transmission customers 
encounter in obtaining price, availability and transmission service 
result in a technology gap that can be, and often is, interpreted as 
discriminatory behavior. EEI also contends that many allegations of 
discrimination are ``rooted at their heart'' on the scarcity of 
transmission resources and not overt attempts to discriminate against 
specific customers.
    PSE&G argues that supposition and anecdotal evidence of alleged 
abuses by transmission owners does not justify a radical change in the 
existing regulatory scheme. PSE&G contends that, while the incentive to 
maximize shareholder value is certainly a powerful force in the 
marketplace, the requirements of law, such as Order Nos. 888 and 889, 
will prevail.
    Duke argues that mere anecdotes of discrimination, involving 
unnamed parties and without reference to specific facts, are not 
evidence of anything, let alone discrimination, and cannot form the 
basis of a reasoned decision. Duke also lists a number of formal 
complaint proceedings where the Commission found the transmission 
provider to have acted properly. Entergy argues that those alleging 
discrimination, as competitors of transmission providers, have an 
economic incentive to make their own allegations. Entergy adds that, if 
perceptions of discrimination were impeding competitive markets, there 
would not be 20,000 MW of generation investment proposed in its region.
    United Illuminating complains that many of the allegations of undue 
discrimination presuppose that all utilities are the same, i.e., 
vertically integrated transmission, distribution and generation 
companies, and do not recognize that a number of utilities are 
divesting their generation business.
    Southern Company states that the goal of non-discriminatory 
transmission service is already being satisfied in the Southeast. 
Southern Company asserts that it has separated its transmission and 
reliability functions from its wholesale merchant function up to the 
level of ``very senior management.'' Southern Company submits that it 
is unaware of any pending allegations of discrimination against it. 
Southern Company adds that the Southeast is characterized by large 
transmission systems such as Southern Company, Tennessee Valley 
Authority, and Entergy and that these transmission systems are already 
planned and operated on a regional basis. Southern Company also points 
out that it alone covers a region as large as (if not larger than) many 
ISOs currently in existence. Under these circumstances, Southern 
Company believes that the Commission's open access initiatives have 
worked in the Southeast and that additional steps are not required to 
ensure non-discriminatory transmission service.
    MidAmerican asserts that complaints received by the Commission 
about alleged discrimination should not be the primary basis for 
determining if the market is successful. According to MidAmerican, if 
it is assumed that an adequate number of parties are competing 
successfully, it could be concluded that the complaints may be 
indications of ill-defined problems not yet resolved, isolated market 
flaws, or indications of a successful market with somewhat inadequate 
tools.
    Duke believes that its transmission organization is meeting the 
needs of its customers as evidenced by the very few and relatively 
insignificant complaints Duke has received regarding the administration 
of its OATT. Duke believes that Order No. 888 has been quite successful 
and, although it agrees with the Commission that elimination of 
balkanized transmission operations through the formation of larger, 
regional operations is ultimately preferred, Duke does not believe 
Order No. 888 should be abandoned hastily.
    Duke argues that disputes are primarily the result of the 
complexity of the priority scheme in the Commission's pro forma tariff, 
the rules for which are still being developed; the inherent tension 
between the Commission's comparability requirement and the requirements 
of state-regulated native load customers; and the obligation to ensure 
reliability of the transmission grid on a real time basis. Duke asserts 
that the vast majority of transactions occurring as a result of Order 
No. 888 do not produce transmission disputes and, to the extent that 
isolated instances of discrimination have occurred, the Commission has 
adequate authority to address the problem.
    Duke also maintains that a major source of confusion involves the 
rights of native load customers versus wholesale transmission users 
under the pro forma tariff and that this issue remains subject to 
disagreement and needs further clarification. Duke says its conclusion 
is reinforced by its experience as a market participant in areas where 
there are ISOs. Duke asserts that the establishment of ISOs in 
California, NEPOOL and PJM has not resulted in the elimination of 
disputes over tariff ambiguities. Duke questions the assertion that 
disagreements between customers and individual transmission owners are 
indicative of significant ongoing discrimination.
    Florida Power Corp. and FP&L's comments are similar to Duke's. 
Florida

[[Page 823]]

Power Corp. and FP&L state that they have not received any formal 
complaints alleging undue discrimination with regard to their OATT. 
Florida Power Corp. and FP&L agree that the increasing number of 
transactions has led to a concomitant increase in transmission 
disputes; however, they characterize the disputes as legitimate 
disagreements over policy or meaning of the pro forma tariff as opposed 
to true allegations of discriminatory conduct. Like Duke, Florida Power 
Corp. and FP&L believe that many of the allegations of potentially 
discriminatory conduct are attributable to two primary areas: (1) 
Rights of native load customers versus wholesale wheeling customers; 
and (2) disputes arising from the complex priority scheme in the pro 
forma tariff. According to FP&L, disputes will still occur until the 
issues relating to priority rights are resolved. FP&L argues that the 
Commission cannot expect that any remedy will eliminate discrimination 
claims in light of the Eighth Circuit Court's decision in Northern 
States Power Co. v. FERC.\89\
---------------------------------------------------------------------------

    \89\ See Northern States Power Co. (Minnesota) and Northern 
States Power Co. (Wisconsin), 83 FERC para. 61,098, clarified, 83 
FERC para. 61,338, reh'g, clarification and stay denied, 84 FERC 
para. 61,128 (1998), remanded, Northern States Power Co., et al. v. 
FERC, 176 F.3d 1090 (8th Cir. 1999), reh'g denied (unpublished order 
dated Sept. 1, 1999), order on remand, 89 FERC para. 61,178 (1999) 
(request to withdraw curtailment procedures pending) (Northern 
States).
---------------------------------------------------------------------------

    FPL and Florida Power Corp. argue that unsubstantiated allegations 
do not constitute evidence of discrimination and should be 
characterized as legitimate disputes over tariff interpretation, while 
EEI describes some of the allegations as ``one-sided characterizations 
of cases now being litigated.'' FPL also contends that some intervenors 
adopt the stance that, whenever the transmission provider and customer 
are in disagreement, it evidences discrimination. Florida Power Corp. 
states that, if undue discrimination exists outside of Florida, it is a 
function of the newness of the Commission's open access rules, and it 
is far too soon to declare functional unbundling ineffective. Florida 
Power Corp. agrees with the Commission's statement that it may be 
impossible to distinguish an inaccurate ATC presented in good faith 
from an inaccurate ATC posted for the purpose of favoring the 
transmission provider's marketing interests, but concludes that, once 
technical issues have been resolved about ATC calculations, the volume 
of disputes will be greatly diminished. Florida Power Corp. adds that 
there is no evidence of a pattern of industry-wide undue 
discrimination, and concludes that mere perceptions cannot provide a 
justification for generic remedial action.
    Entergy, FirstEnergy, Alliance Companies and Lenard argue that 
there is no credible or substantial evidence in the record that 
transmission owners have been engaging in discriminatory practices in 
providing transmission services under Order Nos. 888 and 889 and, 
therefore, the Commission should not, and lawfully cannot, rely on mere 
allegations of discriminatory conduct. FirstEnergy states that it has 
doubled its control area reservation and back office staff to handle 
the five percent of its transmission business that is wholesale related 
and still is having difficulty keeping pace with OASIS and tagging 
administrative processes. FirstEnergy asserts that due to relatively 
new processes associated with open access transmission, there are often 
good faith disputes over the proper interpretation of the Commission's 
requirements and these disputes should not be mischaracterized as 
continued discrimination.
    Commission Conclusion. Engineering and Economic Inefficiencies. In 
this Final Rule, we affirm our preliminary determination that the 
engineering and economic inefficiencies identified in the NOPR 
90 are present in the operation, planning and expansion of 
regional transmission grids, and that they may affect electric system 
reliability and impede the growth of fully competitive bulk power 
markets. The sources of these inefficiencies involve: difficulty 
determining ATC; parallel path flows; the limited scope of available 
information and the use of non-market approaches to managing 
transmission congestion; planning and investing in new transmission 
facilities; pancaking of transmission access charges; the absence of 
clear transmission rights; the absence of secondary markets in 
transmission service; and the possible disincentives created by the 
level and structure of transmission rates. Virtually all commenters 
agree that at least some of these inefficiencies exist. There is 
substantial agreement among commenters that most of the engineering and 
economic obstacles identified by the NOPR arise from the current 
industry structure and can be rectified through development of regional 
transmission entities.
---------------------------------------------------------------------------

    \90\ FERC Stats. & Regs. para. 32,541 at 33,697.
---------------------------------------------------------------------------

    As noted by Allegheny, the industry historically has done an 
excellent job of regional coordination in implementing voluntary 
standards to maintain the security of the transmission system through 
various study groups and planning committees. However, virtually all 
commenters agree that new competitive pressures are interfering with 
the use of traditional methods of coordinated regional transmission 
planning. As a result, new transmission additions that will benefit 
reliable grid operations are being delayed. Some commenters state that 
the increasing frequency and duration of power outages have cost the 
economy billions of dollars, and they predict that unless this problem 
is addressed now the reliability of power supply will worsen. The 
traditional use of regional coordination through study groups and 
planning committees is no longer effective because these entities are 
usually not vested with the broad decisionmaking authority needed to 
address larger issues that affect an entire region, including managing 
congestion, planning and investing in new transmission facilities, 
pancaking of transmission access charges, the absence of secondary 
markets in transmission service, and the possible disincentives created 
by the level and structure of transmission rates.
    We recognize, as some commenters point out, that the degree to 
which these inefficiencies act as obstacles to electric competition and 
reliability varies from system to system. However, we believe it is 
clear that such inefficiencies exist and are sufficiently widespread 
that they must be addressed to prevent them from interfering with 
reliability and competitive electricity markets.
    Continuing Opportunities for Undue Discrimination. As noted, many 
transmission customers and some transmission providers argue that there 
are continuing opportunities for undue discrimination under the 
existing functional unbundling approach. A number of the commenters 
provide examples of events that, in their view, indicate that 
transmission owners are engaging in undue discrimination. These 
commenters also generally believe that even the perception of undue 
discrimination is a significant impediment to the evolution of 
competitive electricity markets. A number of transmission providers 
challenge the relevancy of these examples, characterizing them as 
unsubstantiated or anecdotal allegations that do not rise to the level 
of evidence of undue discrimination necessary to support generic 
action. These transmission providers further contend that many disputes 
simply reflect good faith efforts of transmission providers to 
interpret the Commission's pro forma tariff and standards of conduct. 
These

[[Page 824]]

commenters also generally share the view that the Commission should not 
base its decisions in this rule on mere perceptions that may be 
prevalent in the industry.
    For the most part, the challenges mounted by these commenters are 
focused against a determination by the Commission that it should 
mandate participation in RTOs in this Rule. As noted in Section C.1 of 
this Rule, we have also determined that a measured and appropriate 
response to the evidence presented and concerns raised is to adopt a 
voluntary approach to the formation of RTOs. However, as discussed 
below, we do conclude that opportunities for undue discrimination 
continue to exist that may not be remedied adequately by functional 
unbundling. We further conclude that perceptions of undue 
discrimination can also impede the development of efficient and 
competitive electric markets. These concerns, in addition to the 
economic and engineering impediments affecting reliability, operational 
efficiency and competition, provide the basis for issuing this Final 
Rule.
    At the outset, it is important to note that the conclusion that 
there are continuing opportunities for undue discrimination should not 
be construed as a finding that particular utilities, or individuals 
within those utilities, are acting in bad faith or deliberately 
violating our open access requirements or standards of conduct. 
However, we cannot ignore the fact that the vertically integrated 
structure reflected in the industry today was created to support the 
business objectives of a franchised monopoly service provider that 
owned and operated generation, transmission and distribution facilities 
primarily to serve requirements customers at wholesale and retail in a 
non-competitive environment. Clearly, there are aspects of this 
vertically integrated structure that are difficult to transition into a 
competitive market. As we noted in the NOPR and Order No. 888, 
vertically integrated utilities have the incentive and the opportunity 
to favor their generation interests over those of their competitors. If 
a transmission provider's marketing interests have favorable access to 
transmission system information or receive more favorable treatment of 
their transmission requests, this obviously creates a disadvantage for 
market competitors.
    While we have attempted to rely on functional unbundling to address 
our concerns about undue discrimination, there are indications that 
this is difficult for transmission providers to implement and difficult 
for the market and the Commission to monitor and police. In cases in 
which the Commission has issued formal orders, we have found serious 
concerns with functional separation and improper information sharing 
with respect to at least four public utilities.91 In 
addition, our enforcement staff is receiving an increasing number of 
telephone calls about standards of conduct issues, ranging from simple 
questions about what is permissible conduct to more serious complaints 
alleging actual violations of the standards of conduct. In a number of 
cases, our staff has verified non-compliance with the standards of 
conduct.92 The petitioners for rulemaking in Docket No. 
RM98-5-000 allege that there are common instances of ``unauthorized 
exchanges of competitively valuable information on reservations and 
schedules between transmission system operators and their own or 
affiliated merchant operation employees.'' 93 They also cite 
OASIS data showing an instance where a transmission provider quickly 
confirmed requests for firm transmission service by an affiliate, while 
service requests from independent marketers took much longer to 
approve. We believe that some of the identified standards of conduct 
violations are transitional issues resulting from a new way of doing 
business, and we acknowledge that many utilities are making good-faith 
efforts to properly implement standards of conduct. However, we also 
believe that there is great potential for standards of conduct 
violations that will never even be reported or detected. Moreover, as 
we stated in the NOPR,94 we are increasingly concerned about 
the extensive regulatory oversight and administrative burdens that have 
resulted from policing compliance with standards of conduct. The use of 
standards of conduct is not the best way to correct vertical 
integration problems. Their use may be unnecessary in a better 
structured market where operational control and responsibility for the 
transmission system is structurally separated from the merchant 
generation function of owners of transmission.
---------------------------------------------------------------------------

    \91\ See Wisconsin Public Power Inc. SYSTEM v. Wisconsin Public 
Service Corporation, 83 FERC para. 61,198 at 61,855, 61,860, order 
on reh'g, 84 FERC para. 61,120 (1998) (WPSC's actions raised 
``serious concerns'' as to functional separation; WP&L's actions 
demonstrated that it provided unduly preferential treatment to its 
merchant function); Washington Water Power Co., 83 FERC para. 61,097 
at 61,463, further order, 83 FERC para. 61,282 (1998) (utility found 
to have violated standards in connection with its marketing 
affiliate); Utah Associated Municipal Power Systems v. PacifiCorp, 
87 FERC para. 61,044 (1999) (finding that PacifiCorp had failed to 
maintain functional separation between merchant and transmission 
functions).
    \92\ See, e.g., Communications of Market Information Between 
Affiliates, Docket No. IN99-2-000, 87 FERC para. 61,012 (1999) 
(Commission issued declaratory order based on hotline complaint 
clarifying that it is an undue preference in violation of section 
205 of the FPA for a public utility to tell an affiliate to look for 
a marketing offer prior to posting the offer publicly).
    \93\ Petition at 15.
    \94\ FERC Stats. & Regs. para. 32,541 at 33,711-12.
---------------------------------------------------------------------------

    We also cannot dismiss the significance of reports of undue 
discrimination simply because they are not reduced to formal 
complaints. As many intervenors have asserted, the cost and time 
required to pursue legal channels to prove discrimination will often 
provide an inadequate remedy because, among other things, the 
competition may have already been lost.95 The fact that 
evidence of discrimination in the fast-paced marketplace is not 
systematic or complete is not unexpected. The fact remains that claims 
of undue discrimination have not diminished, and there is no evidence 
that discrimination is becoming a non-issue.
---------------------------------------------------------------------------

    \95\ For example, EPSA has told us: ``Furthermore, even if the 
exercise of such discrimination could be adequately documented and 
packaged in the form of a complaint under section 206 of the Federal 
Power Act under a more streamlined complaint process contemplated by 
the Commission, it would still be extremely costly and inefficient 
to deal with such complaints on a case-by-case basis. More than 
likely, the potential power transactions for which transmission 
principally was sought would disappear by the time a Commission 
ruling was obtained. Motion to Intervene and Comments of Electric 
Power Supply Association in Support of Petition for Rulemaking, 
Docket No. RM98-5-000 (filed Sept. 21, 1998), at 3.''
---------------------------------------------------------------------------

    Finally, we continue to believe that perceptions of discrimination 
are significant impediments to competitive markets. Efficient and 
competitive markets will develop only if market participants have 
confidence that the system is administered fairly.96 Lack of 
market confidence resulting from the perception of discrimination is 
not mere rhetoric. It has real-world consequences for market 
participants and consumers. As stated by NERC, there is a reluctance on 
the part of market participants to share operational real-time and 
planning data with transmission providers because of the suspicion that 
they could be providing an advantage to their affiliated marketing 
groups,97 and this can, in turn, impair the reliability

[[Page 825]]

of the nation's electric systems. Lack of market confidence may deter 
generation expansion, leading to higher consumer prices. Fears of 
discriminatory curtailment may deter access to existing generation or 
deter entry by new sources of generation that would otherwise mitigate 
price spikes of the type that have been experienced during peak periods 
in the last two summer peak periods. Mistrust of ATC calculations will 
cause transactions involving regional markets to be viewed as more 
risky and will unnecessarily constrain the market area, thereby 
reducing competition and raising prices for consumers. The perception 
that a transmission provider's power sales are more reliable may 
provide subtle competitive advantages in wholesale markets, e.g., 
purchasers may favor sales by the transmission provider or its 
affiliate, expecting greater transmission service reliability. We 
believe that the potential for such problems increases in a competitive 
environment unless the market can be made structurally efficient and 
transparent with respect to information, and equitable in its treatment 
of competing participants.
---------------------------------------------------------------------------

    \96\ For example, a representative of Blue Ridge told us: 
``There simply is no shaking the notion that integrated generation 
and transmission-owning utilities have strategic and competitive 
interests to consider when addressing transmission constraints. 
Functional unbundling and enforcement of [standard of] conduct 
standards require herculean policing efforts, and they are not 
practical.'' Regional ISO Conference (Richmond), Transcript at 20.
    \97\ NERC Reliability Assessment 1998-2007, at 39.
---------------------------------------------------------------------------

    In summary, we affirm our conclusion in the NOPR that economic and 
engineering inefficiencies and the continuing opportunity for undue 
discrimination are impeding competitive markets. As noted below, we 
conclude that RTOs will remedy these impediments and that it is 
essential for the Commission to issue this Final Rule.

B. Benefits That RTOs Can Offer to Address Remaining Barriers and 
Impediments

    In the NOPR the Commission explained how the use of independent 
RTOs could help eliminate the opportunity for unduly discriminatory 
practices by transmission providers, restore the trust among 
competitors that all are playing by the same rules, and reduce the need 
for overly intrusive regulatory oversight.98 The Commission 
further identified a number of significant benefits of establishing 
RTOs: (1) RTOs would improve efficiencies in the management of the 
transmission grid; 99 (2) RTOs would improve grid 
reliability; (3) RTOs would remove opportunities for discriminatory 
transmission practices; (4) RTOs would result in improved market 
performance; and (5) RTOs would facilitate lighter-handed governmental 
regulation.100 The Commission requested comments on the 
benefits of RTOs and the magnitude of these benefits.
---------------------------------------------------------------------------

    \98\ FERC Stats. & Regs. para. 32,541 at 33,714.
    \99\ These efficiencies include, among other things, regional 
transmission pricing, improved congestion management of the grid, 
more accurate ATC calculations, more effective management of 
parallel path flows, reduced transaction costs, and facilitation of 
state retail access programs.
    \100\ FERC Stats. & Regs. para. 32,541 at 33,716-20.
---------------------------------------------------------------------------

    Comments. Description of Benefits. Many commenters support the 
establishment of RTOs throughout the United States to effectively 
remove the remaining impediments to competition in the power 
markets.101 Illinois Commission states that the pursuit of 
competition as the driving force for markets in the electric industry 
requires developing new institutions and accepting new practices, and 
RTOs are the logical next organizational step in the electric industry 
restructuring process. Entergy agrees that significant benefits can be 
achieved by the creation of properly-structured, large RTOs and that 
the Commission has accurately described many of those benefits in the 
NOPR. Ohio Commission believes that a properly structured RTO will 
facilitate efficient regional generation markets, while preventing 
incumbent holding companies from improperly exercising their market 
power.
---------------------------------------------------------------------------

    \101\ See, e.g., PJM, DOE, Illinois Commission.
---------------------------------------------------------------------------

    PG&E acknowledges that the benefits of Order No. 888 have been 
largely reaped, and still significant impediments to an efficient 
competitive marketplace remain in place where RTOs are not yet 
operational. Moreover, industry restructuring has led to new and 
complex operational issues that were unanticipated at the time Order 
No. 888 was issued. RTOs represent the most promising and efficient 
regulatory method for the Commission to address these issues. Without 
RTOs, it would be incumbent on the Commission to take very detailed and 
intrusive actions because the transmission grid cannot operate reliably 
and efficiently unless the competitive and operational issues are 
resolved.
    Ontario Power agrees that the electric power industry should now 
move beyond the functional unbundling approach prescribed in Order Nos. 
888 and 889. TDU Systems asserts that wholesale electric markets will 
benefit immensely if RTOs can simply provide transmission service on an 
unbiased basis, treating all customers fairly, and take the lead role 
in regional transmission planning.
    On the other hand, a number of vertically integrated utilities do 
not support government action to form RTOs. For example, Duke 
recognizes that there may be transmission functions performed today 
within individual company control centers, within existing control 
areas, or within existing reliability councils that may be better and/
or more efficiently performed by a regional transmission organization. 
However, Duke also believes that the industry is voluntarily working to 
identify such functions or processes and is effecting meaningful 
changes and improvements in a timely manner. Accordingly, Duke believes 
that this progress should not be pre-empted by regulatory mandates, and 
that there are insufficient data, at this time, to draw meaningful 
conclusions regarding the magnitude of benefits that will result from 
RTO formation.
    Similarly, MidAmerican argues that benefits of RTOs can be realized 
without RTOs. MidAmerican claims that existing regional organizations, 
such as MAPP, are capable of meeting the Commission's concerns about 
eliminating existing impediments to an efficient competitive 
marketplace. FP&L states that the NOPR does not attempt to quantify any 
of the claimed benefits of RTOs. FP&L is unaware of any data that 
specifically and objectively show that ISOs have saved ratepayers money 
in those areas where ISOs have been established. Nor is it aware of any 
specific quantification of any other actual or projected benefits of 
ISOs.
    Some commenters contend that the costs of establishing RTOs must 
not exceed the benefits. Cal DWR argues that significant start-up costs 
and costs associated with duplicative efforts have been higher than the 
NOPR appears to recognize. These costs entail not only costs of the new 
organization itself, but also market participants' costs in travel, 
staffing, and other expenses and investments necessary to participate 
or operate in new structures. Other commenters suggest that each 
proposal contained in the NOPR should be carefully evaluated for its 
cost consequences.\102\
---------------------------------------------------------------------------

    \102\ See, e.g., Cal DWR, California Board, Southern Company, 
Aluminum Companies.
---------------------------------------------------------------------------

    Seattle notes that its region has the lowest cost electricity in 
the Nation and an already thriving wholesale market with little price 
volatility. Assuming that an RTO is projected to result in additional 
transmission costs, Northwest consumers will be less willing to incur 
these costs than consumers in regions where power costs are high and 
wholesale prices are extremely volatile. Snohomish and Aluminum 
Companies assert that one of fatal flaws of the IndeGO proposal \103\ 
was that its demonstrable benefits did

[[Page 826]]

not clearly outweigh the costs of its start-up and operation. Snohomish 
requests that the Commission not impose an RTO with similar flaws upon 
the Northwest. A number of commenters also urge the Commission to 
reject any RTO filing for the Northwest or other regions that fails to 
provide a strong demonstration that its benefits will substantially 
outweigh its projected costs.\104\
---------------------------------------------------------------------------

    \103\ IndeGO is an independent grid operator proposal that has 
been discussed for the Pacific Northwest and Rocky Mountain area.
    \104\ See, e.g., Big Rivers, Chelan, California Board, 
Industrial Customers, Arizona Commission, EEI, Idaho Commission, 
Washington Commission.
---------------------------------------------------------------------------

    To ensure that RTOs are formed in a cost effective and efficient 
manner, SRP proposes a phased approach to RTO development that would 
allow RTOs to gradually take on new functions and responsibilities in 
response to the needs to the market. In addition, the Commission should 
require RTOs to establish criteria against which they will measure cost 
effectiveness and efficient performance and to make adjustments where 
criteria are not being met.
    Canada DNR states that structural differences between the Canadian 
and American electric power industries mean that there may be fewer 
potential benefits from the formation of RTOs in Canada than those 
identified by the Commission for the United States. Consequently, it 
believes that Canadian jurisdiction should be able to assess the costs 
and benefits of RTO proposals. In addition, it notes that some may find 
that, although the benefits do warrant the associated costs, they may 
address impediments to efficient electricity markets through other 
means.
    Comments on RTOs Improving Efficiencies in the Management of the 
Transmission Grid.\105\ PJM agrees with the Commission that placing as 
many grid management functions as possible under an RTO is the best 
means of bringing the benefits of RTOs to the marketplace. A number of 
commenters address specific RTO actions as examples of grid management 
efficiencies, including use of regional transmission pricing, accurate 
estimation of ATC, efficient planning for grid expansion, and 
facilitating state retail access programs.
---------------------------------------------------------------------------

    \105\ As noted earlier, many of the principal benefits of RTOs 
(e.g., congestion management, improved reliability, parallel path 
flow resolution) are discussed in greater detail later as RTO 
minimum characteristics and functions; however, some of the 
commenters cited here mention these benefits as part of their 
overall discussion of RTOs improving efficiencies in the management 
of the transmission grid.
---------------------------------------------------------------------------

    FMPA claims that a just and reasonable RTO transmission rate, with 
a unified regional loss factor or factors, would provide a regionally 
rational approach, which is not provided by the existing fragmented 
regime. Pancaking has long prevented FMPA and its members located on 
the Florida Power Corp. transmission system from economically 
delivering the output from their portions of the St. Lucie nuclear 
plant to their loads. Similarly, WPSC notes that without an RTO that 
encompasses the Midwest region, unjustified pancaked transmission rates 
may inhibit the efficient flow of power across the region.
    PacifiCorp supports the Commission goal of eliminating transmission 
pancaking, to the extent practical. PacifiCorp maintains that such a 
goal could be furthered by the creation of the most geographically 
expansive RTOs that are technically workable. The goal also could be 
met, however, if multiple RTOs within the western United States agree 
to reciprocally eliminate charges in connection with the ``export'' or 
``import'' of power from one RTO to another. In the western United 
States, such ``reciprocity'' agreements may be preferable to the 
creation of a single RTO that otherwise is too large to be efficient, 
safe and reliable, or of a single RTO for which operating principles 
must be unreasonably compromised to attract all necessary transmission 
owners.
    Allegheny asserts that even with an RTO, grid inefficiencies such 
as rate pancaking and congestion will continue unless an appropriate 
pricing mechanism is adopted. The various RTO structures, regardless of 
size and number, would still need to work cooperatively to ensure that 
the various interfaces are sufficient to maintain the reliable 
operation of the system. The formation of an RTO, by itself, does not 
bring a particular benefit.
    Rochdale asserts that a properly structured independent RTO, with a 
broad geographic scope, could eliminate incorrect calculations of ATC 
and TTC. Furthermore, the motive for discrimination and possible 
manipulation that exists where transmission owners with affiliated 
power marketers are responsible for reporting ATC and TTC would become 
moot. FMPA contends that, without an RTO, most market participants 
would remain unable to replicate or trust the transmission owners' ATC 
calculations. FMPA indicates that customers and regulators cannot 
properly review transmission providers' ATC accounting without access 
to their TTC starting points; however, existing Florida OASIS sites do 
not provide TTC information. In addition, ATC calculations require 
extensive application of engineering judgment. FMPA questions whether 
market-interested transmission providers can be trusted to exercise 
such judgment disinterestedly. Consequently, FMPA believes that an RTO 
could provide unbiased ATC information.
    Many commenters believe that RTOs would provide more efficient 
planning for transmission and generation investments.\106\ For example, 
Entergy agrees that the creation of RTOs can lead to more efficient and 
effective planning and expansion of the transmission system. However, 
to ensure efficient investment in the transmission system, Entergy 
proposes that the Commission encourage innovative pricing policies to 
replace traditional cost-of-service ratemaking in certain respects. 
Minnesota Power also agrees that an RTO would help identify the best 
place on the grid to locate new generation. It believes that the 
centralization of regional reliability planning is a big step forward 
for enabling independent power producers to build projects and also is 
a significant benefit to each transmission owner who deals with 
requests from generation groups.
---------------------------------------------------------------------------

    \106\ Comments are addressed in greater detail in the discussion 
of planning and expansion as an RTO minimum function.
---------------------------------------------------------------------------

    Illinois Commission and Texas Commission state that electricity 
consumers in states adopting retail direct access can directly and 
fully benefit from the operation of properly constituted RTOs and their 
concomitant improvements in system efficiency, reliability and market 
competition.
    Comments on RTOs Improving Grid Reliability. Many commenters agree 
that an RTO could provide improved reliability.\107\ Minnesota Power 
supports the formation of a single regional body that operates the 
regional grid and enforces reliability rules for the entire region. It 
suggests that a non-profit RTO can be expected to enforce reliability 
rules fairly and aggressively and, thus, require minimal Commission 
oversight. On the other hand, a for-profit RTO may be perceived as 
biased towards making a profit at the expense of reliability and may 
require additional scrutiny by the Commission.
---------------------------------------------------------------------------

    \107\ Comments are addressed in greater detail in the discussion 
of short-term reliability as an RTO minimum characteristic.
---------------------------------------------------------------------------

    Michigan Commission strongly supports creating an RTO for the 
Midwest that is large enough to ensure reliability. It is very 
concerned that splitting the Midwest region into improperly sized 
competing ISOs, RTOs, and/or Transcos will affect regional reliability 
and delay the benefits of competition. Also, splitting a region into 
multiple RTOs reduces

[[Page 827]]

access to economic generation due to increased transmission charges. 
Michigan Commission believes competition and reliability within the 
region will be served best if the Transmission Alliance and Midwest ISO 
are joined.
    Comments on RTOs Removing Opportunities for Discriminatory 
Transmission Practices. Many commenters, mostly transmission customers, 
agree that RTOs will remedy continuing opportunities for undue 
discrimination.\108\
---------------------------------------------------------------------------

    \108\ See, e.g., American Forest, TDU Systems, WPPI, Sonat, 
Illinois Commission, Arizona Commission, FMPA, Tampa Electric, 
Advisory Committee ISO-NE. Comments are addressed in more detail 
later in the discussion of existing discriminatory conduct.
---------------------------------------------------------------------------

    As both a buyer and seller of wholesale electricity, Oglethorpe 
supports the evolution of competitive markets for generation service. 
To ensure that competitive markets evolve and perform in a workable 
manner, market participants should be assured access to the 
transmission system on a fair and comparable basis, without regard to 
transmission ownership. It believes that true competition can occur 
only with widespread, open and nondiscriminatory access to the 
transmission system. UtiliCorp claims that removing control over access 
to transmission from the remaining large transmission-owning utilities 
and placing such control in properly structured RTOs will go a long way 
toward eliminating the remaining obstructions to effective competition 
in wholesale markets for electric power.
    Virginia Commission agrees that discrimination exists and that RTOs 
can help facilitate competition and police non-competitive activities. 
However, Virginia Commission believes that it is premature to conclude 
that there is no role for rigorous governmental regulation. Virginia 
Commission urges that the Commission not rely exclusively on RTOs to 
detect, prevent and penalize violations of the FPA and should itself 
provide for expedited handling of allegations regarding discrimination 
and market power abuses.
    On the other hand, a number of commenters, mostly transmission 
owners, do not believe that RTOs are needed to address undue 
discrimination because they do not believe that significant 
discrimination problems remain with respect to wholesale transmission 
access pursuant to Order No. 888.\109\ PSE&G argues that, if a 
misperception exists in the marketplace as to the trustworthiness or 
incentives of transmission owners as a whole, it may signal a need for 
an industry-wide educational campaign that discusses transmission 
operation and system reliability. However, such a misperception does 
not, in and of itself, warrant altering the structure of the industry.
---------------------------------------------------------------------------

    \109\ See, e.g., United Illuminating, Southern Company, 
MidAmerican, Duke, PSE&G, FP&L, Entergy, FirstEnergy, Alliance 
Companies, Lenard, Florida Power Corp.
---------------------------------------------------------------------------

    Comments on RTOs Resulting in Improved Market Performance. DOE 
asserts that open and comparable transmission access can reduce both 
concentration in generation markets (by expanding the boundaries of the 
relevant market) and the potential to discriminate through vertical 
control but cannot, in its view, eliminate all market power. The 
establishment of an independent RTO can and should substantially 
mitigate the potential exercise of market power through vertical 
control, because dispatch and related transmission services will be 
provided by an independent entity with no financial interest in 
wholesale market participants. Furthermore, the expected contribution 
of an RTO in reducing the risk of horizontal market power will be 
realized only if RTOs have sufficient ``critical mass.'' Appropriately 
sized RTOs are necessary to assure a transparent and fair marketplace 
for all generation.
    EPA notes that RTOs can play an important role in the development 
of environmentally preferred or ``green'' electricity products for use 
by states that are implementing retail electricity competition. As the 
operator of the transmission system, an RTO will have access to 
detailed information on the operations of individual generators as well 
as fuel type and air emissions, even where such information is 
considered confidential. RTOs are uniquely situated to assemble the 
information necessary to determine environmental attributes of specific 
retail electricity products for purposes of consumer information 
disclosure. EPA notes that this is already occurring in New England, 
where ISO-NE has agreed to provide the states with information on 
environmental attributes and resource mix for individual generators. In 
addition to facilitating consumer information disclosure, EPA notes 
that this information will support other state policies, such as 
renewable portfolio standards and generation performance standards.
    Comments on RTOs Facilitating Lighter-Handed Governmental 
Regulation. Although most commenters agree that properly-designed RTOs 
can be self-governing to a certain extent, the vast majority of 
commenters believe that the Commission has either overstated the 
reliance it should place on self-governance or has reached this 
conclusion prematurely. Most of these commenters suggest that there is 
insufficient evidence at this time to reach the conclusion that RTO 
formation would necessarily result in lighter-handed regulation. A 
number of commenters also caution that the Commission should not 
significantly reduce its oversight of RTOs until they are proven to be 
effective. British Columbia Ministry states that the structure of 
future RTOs should minimize additional layers of administration and 
oversight. However, at least one commenter, Cal DWR, noting that RTOs 
are themselves transmission monopolies subject to the FPA, argues that 
the Commission should continue its course of regulating RTOs to ensure 
compliance with legal and policy requirements.
    PJM generally supports the Commission's conclusion regarding light-
handed regulation. It notes that, where ISOs' decisions are independent 
and conducted through an extensive stakeholder processes to produce 
collaborative solutions to market issues, the Commission can defer 
confidently to those decisions. Under such circumstances, the 
Commission can be assured that ISO proposals to changes market rules 
and procedures would promote competitive markets and are not designed 
to favor any one group of market participants.
    PJM argues further that the Commission accord greater flexibility 
to properly structured RTOs to change market rules and procedures 
without Commission filings. An RTO with an established stakeholder 
process could publish some changes in market rules on its internet 
site, without requiring prior Commission approval. In the event that a 
market participant objected, it could file a complaint with the 
Commission. PJM says the benefit is that the market would not be 
hindered by delay in implementing new rules. Other rules could be 
permitted to go into effect upon filing, rather than at the end of the 
Commission review process.
    Some commenters suggest that the Commission be particularly 
deferential to decisions that result from ADR processes. For example, 
PNGC supports strong and broad dispute resolution power in an RTO. It 
argues that many small transmission users currently have no effective 
way to be heard regarding service complaints, outage restoration, and 
adequacy of equipment or maintenance because of the high cost of 
bringing such a dispute to the Commission. In addition, Desert STAR

[[Page 828]]

asserts that where the Commission has approved the charter governance 
and ADR processes of an RTO as being sufficiently broad-based and 
independent, the Commission should give some deference to decisions 
reached through the RTO's ADR processes. However, deference in dispute 
resolution to an RTO should not impair a transmission user's 
fundamental rights under section 211 of the FPA. Because the RTO will 
be a jurisdictional entity, the Commission is an appropriate appeals 
forum. Similarly, Seattle supports the Commission proposal to defer to 
RTOs on matters involving commercial, operating and planning practices, 
as well as to resolve disputes, but argues that it is too early to tell 
whether ISOs transcos or other forms of RTOs can be deferred to in lieu 
of regulatory filings.
    MidAmerican welcomes the Commission's proposed lighter-handed 
approach to regulation, but questions whether lighter-handed 
regulation, in fact, will be derived from the proposed rule. 
MidAmerican proposes that the Commission issue a policy statement to 
provide general guidance on how it intends to give deference to RTOs. 
For example, the policy should outline that, if a transmission owner 
follows RTO directives, it will be presumed that the transmission owner 
does not have transmission market power and that it is not capable of 
transmission market discrimination. The Commission should give 
deference to RTOs to design tariffs that include rate incentives and 
should permit returns on equity that compensate transmission owners for 
additional risks and for competitive market development.
    A number of commenters argue that there is as yet no evidence to 
support the conclusion that RTO formation should lead to lighter-handed 
regulation. Duke and Entergy argue that each of the existing ISOs has 
been mired in significant litigation with market participants, and the 
Commission's dockets are loaded with cases arising out of decisions 
made by ISOs. They and NECPUC suggest that this raises the possibility 
that RTOs represent a new layer of regulatory oversight of market 
activities, supplementing rather than replacing federal and state 
regulation. FP&L states that the independence and objectivity of the 
Florida Public Service Commission make it unnecessary to create a 
formal (and costly) separate entity to operate and oversee the Florida 
grid as an RTO.
    Other commenters suggest that the probability that RTOs can be 
self-regulating may be overstated. APPA argues that existing ISOs still 
represent the interests of the transmission owners that formed these 
ISOs. In addition, it argues that each ISO is a market participant 
because its revenue recovery is affected by the performance of 
transmission, ancillary services, and energy imbalance spot markets. It 
suggests that the right to self-regulation must be earned in the 
marketplace, not bestowed by regulators in advance.
    NECPUC argues that not only must an RTO be properly structured to 
be self-regulating, so must the utilities involved, or the RTO will 
constantly be involved in the business of dispute resolution. It 
suggests that during a transition phase, a certain level of active 
regulation may be inescapable. For example, it notes that the 
Commission stepped in quite definitively in developing the governance 
of the New England Power Pool. NECPUC believes that strong intervention 
by the Commission was effective at achieving progress when the parties 
in New England stalemated.
    PG&E claims that an RTO is uniquely situated to handle a number of 
responsibilities, including reliability enforcement and sanctions, 
market monitoring, and reporting non-reliability market-related 
violations. However, a single entity, no matter how well-structured and 
independent, cannot successfully fulfill several competing roles 
simultaneously, i.e., serve as judge, jury and advocate. While the RTO 
can do much to create region-specific processes that meet the needs of 
market participants, the Commission must retain ultimate oversight. The 
RTO is not a substitute for this function. With the tremendous volume 
of transactions flowing through an RTO, even small errors in energy or 
financial accounting can lead to huge cost shifts. Market participants 
need to have a remedy at the Commission if issues are not resolved 
adequately by the RTO.
    Other commenters believe that the Commission may have to play a 
strong role in ADR. Arizona Commission urges the Commission to give 
respect rather than deference to decisions reached through an RTO's ADR 
processes. TDU Systems state that the ability of an RTO transmission 
customer to obtain ultimate Commission review of a dispute with the RTO 
(or another RTO customer) should not be cut off. RTO tariffs should 
contain ADR provisions that allow for mediation or other low-cost forms 
of ADR so disputes can, if possible, be resolved without resort to the 
Commission. If this is not possible, the Commission should consider any 
dispute that comes to it after the conclusion of ADR at an RTO on a de 
novo basis.
    In dealing with disputes between RTOs and their customers, TDU 
Systems suggests that the Commission be sensitive to the issue of 
``minority rights.'' The Commission should ensure that transmission 
customers with complaints against their RTOs get due process and a full 
and fair opportunity to air their concerns. Just because a customer may 
take a position in a dispute not shared by many others does not mean 
that it is automatically wrong.
    Moreover, TDU Systems believe that the Commission, in considering 
the ADR issue, should make a distinction between ISOs or other RTOs 
that are not-for-profit or quasi-governmental in nature and for-profit 
RTOs. For-profit RTOs may not necessarily be well suited to be the 
arbiters of disputes, especially where they are an involved party. It 
would be inappropriate for the Commission simply to ``off load'' 
dispute resolution duties to a private for-profit entity, especially if 
the entity is an interested party in the dispute. ISOs, on the other 
hand, are more quasi-governmental in nature, and if fully independent, 
may be in a better position to attempt to resolve a dispute, subject to 
Commission review.
    Duke asserts that streamlined filings and approval procedures could 
reduce costs that would otherwise be borne by market participants. 
Reducing regulatory burdens could constitute one form of incentive to 
encourage RTO participation. The policy could be applied equally for 
non-profit and for-profit RTOs. On the other hand, TDU Systems argues 
that opportunities for streamlined RTO filings could set a very 
dangerous precedent, especially if applied to incentive rate filings of 
for-profit RTOs. RTOs will still be monopolies (although hopefully 
large horizontal ones, rather than smaller, vertically integrated 
ones). The norm for RTO filings should still be full Commission 
scrutiny. Entergy argues that the Commission should encourage proposals 
submitted by RTOs designed to increase regulatory efficiencies and 
reduce regulatory burdens imposed on RTOs. The Commission should 
specifically declare its willingness to entertain proposals to 
streamline filing requirements. The Commission could encourage 
innovative ways to reduce regulatory costs by authorizing performance-
based rates that reward RTOs for reducing regulatory costs.
    Commission Conclusion. We conclude that properly structured RTOs 
throughout the United States can provide significant benefits in the 
operation of the transmission grid. The comments received reinforce our 
preliminary determination in the NOPR

[[Page 829]]

that RTOs can effectively remove existing impediments to competition in 
the power markets.
    Description of Benefits. We conclude that RTOs will provide the 
benefits that we described in detail in the NOPR, and others that 
commenters mention.110 While we acknowledge that the level 
of RTO benefits may vary from region to region depending on the current 
transparency and efficiency of markets, the Commission believes that 
benefits from RTO's would be universal. These benefits will include: 
increased efficiency through regional transmission pricing and the 
elimination of rate pancaking; improved congestion management; more 
accurate estimates of ATC; more effective management of parallel path 
flows; more efficient planning for transmission and generation 
investments; increased coordination among state regulatory agencies; 
reduced transaction costs; facilitation of the success of state retail 
access programs; facilitation of the development of environmentally 
preferred generation in states with retail access programs; improved 
grid reliability; and fewer opportunities for discriminatory 
transmission practices.111 All of these improvements to the 
efficiencies in the transmission grid will help improve power market 
performance, which will ultimately result in lower prices to the 
Nation's electricity consumers.
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    \110\ The benefits described in this section are not intended to 
include all benefits that RTOs could provide. Some of the principal 
benefits of RTOs (e.g., more effective management of parallel path 
flows, improved congestion management) are addressed in later 
discussions of RTO minimum characteristics and functions.
    \111\ FERC Stats. & Regs. para. 32,541 at 33,716-20.
---------------------------------------------------------------------------

    As stated in the NOPR, we expect that RTOs can reduce opportunities 
for unduly discriminatory conduct by cleanly separating the control of 
transmission from power market participants. An RTO would have no 
financial interests in any power market participant, and no power 
market participant would be able to control an RTO. This separation 
will eliminate the economic incentive and ability for the transmission 
provider to act in a way that favors or disfavors any market 
participant in the provision of transmission services.
    Most commenters support the premise that RTOs can be beneficial in 
addressing the remaining transmission-related impediments to full 
competition in the electricity markets. Although we recognize certain 
differences in perspective about the existence of, or potential for, 
widespread discrimination by current transmission owners, no one 
seriously disputes the benefits of a marketplace where service quality 
and availability are uniform, where users of the network are treated 
equally, and where commercially important data are readily available to 
all. Although some commenters support the NOPR proposal only if the 
costs of establishing RTOs do not exceed the benefits, a subject 
discussed further below, most believe that the benefits listed in the 
NOPR are accurate and can be achieved through an RTO.
    We recognize that some commenters believe that either RTOs alone 
will not solve all of the identified problems, or individual benefits 
can be achieved in ways other than creating RTOs. Both of these 
observations may have some merit. However, we believe that the creation 
of RTOs is one action that can address all of the identified 
impediments to competition and provide all or most of the identified 
benefits.
    We also recognize that there are those who worry that the costs of 
establishing an RTO will outweigh the benefits. We believe this concern 
fails to account for the flexibility we have built into this rule. 
While many look at the high costs involved with respect to establishing 
some existing ISOs and PXs, this rule does not require an RTO to follow 
any specific approach. For example, this rule does not require the 
consolidation of control areas nor does it require the establishment of 
a PX. We are allowing significant flexibility with respect to how and, 
in some cases, when the minimum characteristics and functions are 
satisfied. Accordingly, we do not believe it will be necessary to 
expend the same level of resources that were expended, e.g., in 
California, to create an RTO satisfying our minimum characteristics and 
functions. We therefore conclude that the flexibility built into the 
Final Rule will allow RTOs to create streamlined organizational 
structures that are not overly costly. Moreover, with five ISOs now 
operating in the United States, there is considerable experience 
available regarding what works and what does not with respect to 
regional transmission entities. This experience should make it somewhat 
easier, and more cost efficient, to create new RTOs.
    As we stated in the NOPR, by improving efficiencies in the 
management of the grid, improving grid reliability, and removing any 
remaining opportunities for discriminatory transmission practices, the 
widespread development of RTOs will improve the performance of 
electricity markets in several ways and consequently lower prices to 
the Nation's electricity consumers. To the extent that RTOs foster 
fully competitive wholesale markets, the incentives to operate 
generating plants efficiently are bolstered. The evidence is clear that 
market incentives can lead to highly efficient plant operations. The 
incentives for more efficient plant operation can also affect existing 
generation facilities. Especially noteworthy is the recent experience 
that indicates improvements in the generation sector in regions with 
ISOs. Regions that have ISOs in place are undergoing dramatic shifts in 
the ownership of generating facilities. Large-scale divestiture and 
high levels of new entry in California and the Northeast are changing 
the ownership structure of these regions' generators. Access to 
customers and the presence of competing suppliers are creating the 
incentives for better-performing plants.
    By improving competition, RTOs also will reduce the potential for 
market power abuse. As discussed earlier, eliminating pancaked 
transmission prices will expand the scope of markets and bring more 
players into the markets. By eliminating the mistrust in the current 
grid management, entry by new generation into the market will become 
more likely as new entrants will perceive the market as more fair and 
attractive for investment. And with more players, the market becomes 
deeper and more fluid, allowing for more sophisticated forms of 
transacting and better matching of buyers and sellers.
    Estimation of Benefits. The full value of the benefits of RTOs to 
improve market performance cannot be known with precision before their 
development, and we do not yet have a sufficiently long track record 
with existing institutions with which to measure. The Commission staff 
has estimated a subset of the potential cost savings from RTOs as part 
of its National Environmental Policy Act analysis. In the Environmental 
Assessment (EA) for this rulemaking, three scenarios were developed to 
estimate potential economic and environmental effects of the 
rulemaking.112 The scenario analysis was conducted using a 
computer simulation model of the continental U.S. electric power system 
over the

[[Page 830]]

period 1997 to 2015.113 The Commission adopts staff's 
analysis.
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    \112\ One of these scenarios assessed transmission effects only, 
the second assessed generation efficiencies in addition to 
transmission effects, and the third posited increased entry of new 
supply and demand choices.
    \113\ The Integrated Planning Model (IPM) was developed for the 
U.S. Environmental Protection Agency by ICF Inc. See 3.3.1 of the 
Commission Staff's Environmental Assessment in this proceeding.
---------------------------------------------------------------------------

    The results of the EA modeling present a range of potential cost 
savings resulting from the changes in modeling assumptions in each 
scenario. Although this Final Rule does not mandate RTO formation, full 
development of RTOs as envisioned by the Commission in this rule could 
offer substantial economic benefits. The EA scenarios modeled resulted 
in average annual savings of up to $5.1 billion per year over the 2000-
2015 period. Based upon review of the EA scenarios and comparison with 
other existing analyses of competitive electric power markets, the best 
estimate from the EA analysis of annual benefits that could result from 
RTO formation is $2.4 billion per year. This estimate results from a 
scenario in which the modeling assumptions for transmission and 
generation efficiency are selected for consistency with other economic 
analyses of competitive power markets, including the Order No. 888 
Environmental Impact Statement analysis conducted by Commission staff 
in 1996.114
---------------------------------------------------------------------------

    \114\ Order No. 888, Final Environmental Impact Statement, FERC/
EIS-0096, FERC Stats. & Regs. para. 31,036 at 31,860-96.
---------------------------------------------------------------------------

    These estimates do not represent a complete economic analysis of 
the rulemaking because the EA analysis addressed only factors that may 
change the dispatch of power plants or future generating capacity 
decisions. The model accounts for production costs (capital additions, 
operations and maintenance expenses, and fuel) equal to roughly one-
third of the annual sales revenue now passing through the industry, and 
does not include such cost categories as existing (sunk) capital, the 
distribution system, and end user charges such as taxes. If other cost 
savings were realized, for example, from merger-like consolidation 
savings in the transmission grid, these savings would be additional to 
those estimated in the EA. Benefits from elimination of market power 
and improved intra-regional congestion management are also not included 
in the calculation and could represent significant additional savings.
    The costs of RTO formation are not explicitly captured in the EA 
analysis, nor are any potential costs associated with the provision of 
incentives for RTO formation or operation. Costs of RTO formation 
cannot be well estimated because of the wide range of design choices 
that the rule allows for a new RTO. For instance, the choice of 
building a dedicated telecommunications and data infrastructure, as 
opposed to relying on existing infrastructures, can have a large effect 
on the initial cost of an RTO.115
---------------------------------------------------------------------------

    \115\ See, e.g., California ISO, Cost Performance Benchmarking 
Study of Independent System Operators, revised version of Feb. 17, 
1999.
---------------------------------------------------------------------------

    Based on review of cost studies for existing ISOs, it appears 
unlikely that the costs of RTO formation will exceed RTO cost savings 
on an annualized basis over time. This is because most of the costs are 
capital investments that occur at the beginning of the RTO's operation. 
But whether the costs in the initial period are under $10 million or up 
to several hundred million dollars (and more likely between these two 
figures) for an RTO, they are small in comparison with the ongoing 
annual savings that RTOs may provide.
    As discussed above, our best estimate of cost savings from RTO 
formation is $2.4 billion annually, with potential cost savings 
estimated to be as high as $5.1 billion annually. This represents about 
1.1 to 2.4 percent of the current total costs of the U.S. electric 
power industry.116 Such savings can be considered in the 
context of recent analysis of the economic benefits of further industry 
restructuring.117 The wholesale cost savings the Commission 
is anticipating from the formation of RTOs are properly viewed as 
distinct from the larger savings that may result from competitive 
retail power markets. However, RTOs can also help achieve retail access 
and its associated benefits by creating a robust wholesale power 
market. In this sense the cost savings from retail access depend on the 
Commission fulfilling its RTO objectives.118
---------------------------------------------------------------------------

    \116\ Defined as revenue from sales to ultimate users, which 
were reported as $215 billion in 1997. See Energy Information 
Administration, Annual Energy Review 1997, DOE/EIA-0384(97) (July 
1998).
    \117\See, e.g., Department of Energy, Supporting Analysis for 
the Comprehensive Electricity Competition Act, DOE-PO-0059 (May 
1999).
    \118\ DOE's Economic Analysis of the Comprehensive Electricity 
Competition Act shows an estimated cost savings from a national 
policy of retail access to be $20 to $32 billion per year. See id.
---------------------------------------------------------------------------

    Light-Handed Regulation. One of the benefits of RTOs that we 
identified in the NOPR was that the existence of a properly structured 
RTO would reduce the need for Commission oversight and scrutiny, which 
would benefit both the Commission and the industry. We stated that to 
the extent an RTO is independent of power marketing interests, there 
would be no need for the Commission to monitor and attempt to enforce 
compliance with the standards of conduct designed to unbundle a 
utility's transmission and generation functions. We also stated that an 
independent RTO with an impartial dispute resolution mechanism could 
resolve disputes without resort to the Commission complaint process, 
and that it is generally more efficient for these organizations to 
resolve many disputes internally rather than bringing every dispute to 
the Commission. Further, we noted that the Commission has in the past 
indicated its willingness to grant more latitude to transmission 
pricing proposals from appropriately constituted regional groups 
119 and, to the extent that RTOs increase market size and 
decrease market concentration, the competitive consequences of proposed 
mergers would become less problematic and thereby help further 
streamline the Commission's merger decision-making process.
---------------------------------------------------------------------------

    \119\ Inquiry Concerning the Commission's Pricing Policy for 
Transmission Services Provided by Public Utilities Under the Federal 
Power Act, 59 FR 55031 (Nov. 3, 1994), FERC Stats. & Regs. para. 
31,005, at 31,140, 31,145, 31,148 (1994) (Transmission Pricing 
Policy Statement).
---------------------------------------------------------------------------

    We continue to believe that the types of reduced regulatory 
scrutiny mentioned in the NOPR, and summarized above, are possible and 
appropriate for RTOs. A number of commenters, however, have expressed 
concern that it is premature to reduce regulation of RTOs, and that 
RTOs will be monopolies that will require continued regulation. We 
believe that this concern stems from a misunderstanding of our concept 
of light-handed regulation. Admittedly, this concept is subject to 
varying interpretations.
    We clarify 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. Only when we determine that a 
different form of regulation will adequately protect the public 
interest, we will allow a reduced oversight role for the Commission.
    Furthermore, our encouragement of the use of ADR by participants in 
RTOs to resolve disputes without resort to formal complaint proceedings 
is not new. In our RTG Policy Statement, we encouraged RTGs to develop 
alternative dispute resolution procedures for resolving transmission 
issues, particularly technical and reliability issues. We also stated 
that we would be willing to entertain proposals for some degree of 
deference to decisions rendered pursuant to an ADR process, pursuant to 
procedures that are specified in an agreement and assure

[[Page 831]]

due process for all participants. 120 We stated there, and 
we reaffirm here, that while the Commission cannot delegate its 
authority, it can give deference to resolutions that meet the standards 
of the FPA.
---------------------------------------------------------------------------

    \120\ Policy Statement Regarding Regional Transmission Groups, 
58 FR 41626 (Aug. 5, 1993), FERC Stats. & Regs. para. 30,976 (1993) 
(RTG Policy Statement).
---------------------------------------------------------------------------

    We reiterated this concept in the eleven ISO principles we set 
forth in Order No. 888. We stated there that an ISO should provide for 
a voluntary dispute resolution process that allows parties to resolve 
technical, financial, and other issues without resort to filing 
complaints at the Commission.121 We have also expressed our 
willingness to grant some deference to changes to an open access tariff 
by an ISO concerning a regional solution to an identified regional 
problem based on what we understand is a broad consensus.122
---------------------------------------------------------------------------

    \121\ Order No. 888, FERC Stats. & Regs. para. 31,036 at 31,732.
    \122\ See PJM Interconnection, L.L.C., 84 FERC para. 61,212 
(1998).
---------------------------------------------------------------------------

    Accordingly, we believe that some degree of deference can be 
granted on certain issues to independent RTOs that have appropriate 
procedural mechanisms in place to ensure fair representation of 
viewpoints. We cannot delineate here precisely the degree of deference 
that is appropriate, or on what issues. To the extent some issues can 
be fairly resolved within a region without formal Commission 
procedures, a benefit accrues to both the parties and the Commission.
    In addition, we note that some of the innovative ratemaking 
policies discussed later in this Final Rule are consistent with light-
handed regulation, since we expect that these policies may result in 
reduced levels of regulatory scrutiny. We emphasize, however, that we 
will not delegate or fail to exercise our regulatory responsibilities. 
We also recognize that the degree of deference and reduced regulatory 
scrutiny accorded to an RTO may necessarily depend on the ability of 
the RTO to reach consensus solutions to regional issues.

C. Commission's Approach to RTO Formation

    The NOPR proposed an approach to RTO formation that embraces 
several general principles: first, as a matter of policy, we should 
strongly encourage transmission owners to participate voluntarily in 
RTOs; second, we should be neutral as to organizational form (e.g., ISO 
or transco) of an RTO as long as it satisfies our minimum 
characteristics and functions; and third, we should provide maximum 
flexibility as to the specifics of how an RTO can satisfy the minimum 
characteristics and functions. We sought comment on these principles 
and specifically asked whether we should generically mandate RTO 
participation 123 or whether market-based rates or merger 
approvals should be conditioned on RTO participation.124
---------------------------------------------------------------------------

    \123\ FERC Stats. & Regs. para. 32,541 at 33,762.
    \124\ Id.
---------------------------------------------------------------------------

    Based on the wide array of comments received, which we discuss 
next, and the voluminous record compiled in this rulemaking proceeding, 
we conclude that a voluntary approach to RTO formation represents a 
measured and appropriate response to the technical impediments to 
competition that have been identified as well as the lingering 
discrimination concerns that have been raised. We believe that 
voluntary formation of RTOs will address the fundamental economic and 
engineering issues which confront the industry and the Commission, and 
will help eliminate any actual or perceived discriminatory conduct by 
entities that continue to control both generation and transmission 
facilities.125 Further, we believe that the voluntary 
process adopted in this rule, in conjunction with the innovative 
transmission pricing reforms that we will permit RTOs to seek, will be 
successful in achieving widespread formation of RTOs in a timely 
manner. Our adoption of a voluntary approach to RTO formation in this 
Final Rule does not in any way preclude the exercise of any of our 
authorities under the FPA to order remedies to address undue 
discrimination or the exercise of market power, including the remedy of 
requiring participation in an RTO, where supported by the record.
---------------------------------------------------------------------------

    \125\ These engineering, economic and discrimination issues are 
discussed in Section III.A above.
---------------------------------------------------------------------------

1. Voluntary Approach
    Comments. Comments as to whether the Commission should require 
formation of and/or participation in RTOs break down into five main 
categories: (1) The Commission should require formation of and 
participation in RTOs; (2) formation of and participation in RTOs 
should be voluntary; (3) the Commission should encourage voluntary 
RTOs, but with strong enforcement mechanisms; (4) RTOs should be 
voluntary, but if they do not form or if utilities do not participate, 
the Commission should mandate them; and (5) RTOs should be voluntary, 
but the requirements of the NOPR effectively create a mandate.
    Most investor-owned utilities argue that RTOs should be voluntary. 
Most municipal utilities, customer groups, consumer advocates, and 
marketers argue that the Commission should require RTOs. State 
commissions and cooperatives are more evenly split. These 
characterizations, however, are broad generalizations, and there are 
strong exceptions to each statement.
    Comments That the Commission Should Require Formation of and 
Participation in RTOs. The most extensive argument for mandating RTOs 
comes from TAPS and is representative of the positions of a number of 
public power utilities and other transmission customers. 126 
TAPS argues that the non-mandatory approach leaves the keys to reform 
in the hands of the wrong people--the monopolists who have market 
power--and that the voluntary creation of RTOs will give opportunities 
for monopolists to maintain their market power. TAPS presents extensive 
arguments as to the Commission's authority to mandate and its 
obligation under the FPA to do so. They state:
---------------------------------------------------------------------------

    \126\ E.g., APPA, Empire District, FMPA, Great River, Lincoln, 
UAMPS, UMPA.

    Only by mandating that jurisdictional utilities participate in * 
* * RTOs will the Commission protect against * * * utilities' 
inclinations to form alternative RTOs that are structured to 
perpetuate or enhance their competitive position. Compelling such 
participation is also the only way for the Commission to satisfy its 
statutory obligations to eradicate undue discrimination and protect 
against unjust and unreasonable pricing of both transmission service 
---------------------------------------------------------------------------
and wholesale generation sales.

TAPS further argues that past attempts to allow voluntary formation of 
RTOs have not been successful. Only where states have required ISOs or 
where the Commission has required them as part of a merger proceeding 
have effective ISOs been formed.
    TDU Systems also presents extensive arguments for a mandate. It 
argues that the need for a national system of RTOs is urgent; that the 
Commission cannot rely purely on voluntary actions of transmission 
owners; that only a mandate will create RTOs in a timely fashion; and 
that inducements are counterproductive. WPPI states that the financial 
incentive to protect a transmission owner's generation investment is 
much stronger than any transmission incentive FERC can give to induce 
RTO participation. First Rochdale argues that voluntary RTOs will 
create too great an emphasis on forcing parties to litigation and other

[[Page 832]]

costly, time consuming dispute resolution.
    Some investor-owned utilities support a mandate.127 For 
example, Cinergy presents arguments similar to those of TAPS, and 
believes that ``all jurisdictional utilities must be required to 
transfer control of their transmission facilities to a qualified ISO, 
which shall integrate those facilities into an RTO approved by the 
Commission.''
---------------------------------------------------------------------------

    \127\ E.g., Minnesota Power, WEPCO, PG&E, PECO.
---------------------------------------------------------------------------

    A number of marketers believe that RTOs must be mandated. Sonat is 
not convinced that incentives alone are sufficient to persuade 
transmission providers to follow through with RTO formation. NEMA 
believes that participation by all transmission owners should be 
mandatory, but that the form of the RTO should be allowed to evolve.
    Many industrial customers agree that RTOs must be required. PJM/
NEPOOL Customers argue that the goals of the Commission cannot be 
achieved without mandatory participation by all transmission owners in 
RTOs. They go further to state that experience from both the Midwest 
ISO/Alliance debate over formation of ISOs and from the natural gas 
industry demonstrates monopolists will not act effectively to eliminate 
discrimination without strong mandates attached to strong penalties.
    Residential consumer advocates and environmental organizations 
concur. Public Citizen says that the Commission should order the 
creation of three non-profit public transmission companies (one each 
for the Eastern, Western, and ERCOT interconnections) and order each 
public transco to purchase all of the transmission facilities needed to 
provide customers with transmission service.
    Project Groups recommends that the final rule be strengthened to 
require that if owners do not voluntarily transfer control of 
facilities to an approved RTO by a date certain, the Commission will 
either order the transfer (in the case of jurisdictional utilities) or 
take other actions designed to minimize the opportunities for resisting 
owners to use their facilities in anti-competitive ways.
    A number of state commissions support a mandatory RTO regime 
imposed by the Commission. Illinois Commission does not believe that 
the voluntary approach set out in the NOPR is likely to obtain its 
objectives and especially not in a timely manner, noting that voluntary 
efforts ``for more than six years'' have failed and that the 
encouragements and incentives contained in the NOPR are unlikely to 
change the situation. Indiana Commission points to its experience with 
the Midwest ISO/Alliance debates as indicating that the Commission must 
take a more assertive role. Montana Commission agrees, pointing to 
unwillingness of transmission owners to give up control and to concerns 
about cost-shifting. It recommends that the Commission strengthen the 
NOPR to ensure the prompt formation of RTOs using all the tools at its 
disposal. Pennsylvania Commission argues that in order to be stable, 
both as to their authority and with respect to membership 
participation, RTOs must be mandatory. Virginia Commission argues that 
the goal of independence is in conflict with a voluntary approach.
    Wisconsin Commission argues that the Commission should move forward 
quickly and require all transmission facilities to be placed under the 
control of an RTO. In the absence of any action from FERC to require 
utility membership, it states, it is unclear how any effort to resolve 
the ``Swiss cheese'' problems already experienced in the Midwest can 
succeed. Ohio Commission argues that it continues to believe that the 
mandatory participation and boundary drawing approach is more 
appropriate.
    Comments That Formation of and Participation in RTOs Should Be 
Voluntary. The most extensive presentation of the argument that RTOs 
should and must be voluntary comes from Indianapolis P&L and FP&L, 
which make mostly legal arguments that are addressed below. Southern 
Company argues that a voluntary, flexible RTO policy is consistent with 
desires of the states as reflected in statements given at the 
consultations with the states held by the Commission. It also avers 
that an RTO is not required to achieve the goals of the NOPR. Alliance 
Companies and Trans-Elect argue that voluntary formation is the key to 
RTO success, noting that the Commission's voluntary approach of 
encouraging regionalization of the transmission grid has been 
successful and there is no reason to doubt its continued success.
    EEI suggests that the voluntary approach is working well, 
indicating that five ISOs have been approved serving 46 percent of U.S. 
customers and 38 percent of total MWh sales. They state that four other 
regions have proposed or are about to propose RTOs which will result, 
within three years since the issuance of Order No. 888, in nearly 63 
percent of the nation's electricity customers being served by regional 
transmission entities. They go on to argue that a mandate could 
stimulate litigation that would slow this voluntary 
development.128
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    \128\ Other transmission-owning utilities supporting voluntary 
development and opposing mandates are Detroit Edison, Duke, Entergy, 
Florida Power Corp., SCE&G, Metropolitan, MidAmerican, NEPCO et al., 
NU, NSP, Montana-Dakota, Tampa Electric, TXU Electric, United 
Illuminating, CP&L, Central Maine and Virginia Power.
---------------------------------------------------------------------------

    A number of public power entities, including municipal utilities, 
cooperative utilities, Federal Power Marketing Administrations, and 
others, also support a voluntary approach. TVA argues that FERC's 
proposal to make RTO participation voluntary is a wise one, that as 
RTOs demonstrate their effectiveness and the benefits of RTOs become 
more evident, transmission owners likely will be persuaded to 
participate and the holes in the RTOs should disappear. CMUA argues 
that mandatory RTOs are not likely to be formed through collaborative 
processes and therefore are not likely to take into account broad 
stakeholder input. Tacoma Power supports voluntary formation because 
some utilities may not find that the cost savings are sufficient to 
warrant the expenditure necessary. Also, it states that public power 
utilities may face legal obligations or restrictions that inhibit their 
participation and that such utilities should not face penalties or 
sanctions for not participating.129
---------------------------------------------------------------------------

    \129\ Other public power and cooperative entities supporting 
voluntary formation of RTOs include Big Rivers, East Kentucky, 
Georgia Transmission, South Carolina Authority, SMUD, Seattle, JEA, 
LPPC, NRECA, Los Angeles, MEAG, Oglethorpe, Platte River, NPRB, 
NPPD, RUS and Tri-State.
---------------------------------------------------------------------------

    A number of state commissions support voluntary formation of RTOs. 
Alabama Commission argues that the Commission does not have authority 
to mandate RTOs. Florida Commission agrees and states that any action 
by the Commission must be on a case-by-case basis, and the Commission 
should defer to states in developing regional approaches. Michigan 
Commission believes that there is a solution short of mandating RTO 
formation, but that uses FERC's unique national perspective and 
authority to facilitate larger RTO formation. Wyoming Commission urges 
the Commission not to codify or mandate anything other than the general 
framework for RTOs and thereby allow the voluntary process an 
opportunity to work.130
---------------------------------------------------------------------------

    \130\ Other state commissions supporting voluntary formation 
include South Carolina, Iowa, New York, and Washington. Other 
entities supporting voluntary formation of RTOs include NYPP, SRP 
and Cal ISO.
---------------------------------------------------------------------------

    Comments That the Commission Should Encourage Voluntary RTOs But 
With Strong Enforcement Mechanisms. The Justice Department argues that 
the

[[Page 833]]

NOPR makes a strong case for mandating RTOs. It recommends that a 
regime of ``carrots and sticks'' be carefully designed to reasonably 
guarantee complete voluntary compliance, rather than merely promote 
greater voluntary compliance.
    Enron/APX/Coral Power argue that the Commission should take steps 
to induce transmission owners to participate in RTOs.131 
They doubt, however, that performance-based ratemaking alone will be a 
sufficient inducement and recommend Commission procedures to prevent 
transmission owners that fail to participate in RTOs from misusing 
their transmission systems to favor their own or affiliated uses of 
their systems. These could include regional proceedings to impose added 
safeguards against violations, presumptions of ineligibility for 
market-based rates, and presumptions that mergers are inconsistent with 
public interest absent membership in an RTO.
---------------------------------------------------------------------------

    \131\ Concurring are H.Q. Energy Services, Midwest Energy and 
Oregon Office.
---------------------------------------------------------------------------

    Comments That RTOs Should Be Voluntary, But if They Do Not Form, 
the Commission Should Mandate Them. PNGC argues that if a voluntary RTO 
encompassing the Pacific Northwest does not come about in a reasonably 
short time, the Commission should explore its authority or seek new 
authority to mandate participation in RTOs. Fertilizer Institute 
believes that the Commission has sufficient authority to mandate RTOs 
but would likely be bogged down in endless litigation should it do so, 
and so recommends that the Commission pursue a voluntary approach, but, 
should that not work, proceed with a requirement. WPSC argues that 
encouraging voluntary participation in RTOs is the appropriate starting 
place. However, the Commission must be prepared to take more direct 
action, including increased legislative authority, to ensure the 
participation of utilities that do not voluntarily choose to join an 
RTO.
    Comments That RTOs Should Be Voluntary, But the Requirements of the 
NOPR Effectively Create a Mandate. Puget states that if the Final Rule 
continues to reflect a position that nonparticipation in the RTO will 
result in negative regulatory consequences for the nonparticipant, then 
the RTO proposal cannot really be said to be voluntary. CP&L argues 
that mandatory filings, coupled with threats of withholding benefits 
and/or leveling penalties for those that do not choose to 
``voluntarily'' join and RTO, do not present a picture of a truly 
voluntary process.
    Comments on Sanctions for Non-Participation. Most vertically 
integrated public utilities oppose conditioning market-based rates and 
merger approval on RTO participation, while most transmission customers 
favor the Commission using conditioning authority. A number of 
utilities express concern that the Commission may be exceeding its 
legal authority, and that conditioning would undermine the voluntary 
nature of the RTO initiative. Florida Power Corp. argues that the 
Commission cannot impose penalties for failure to participate 
voluntarily in an RTO in contravention of the FPA. Puget contends that 
the possibility of penalties for non-participation means that no 
provision is made for participation to be truly voluntary. Duke 
expresses concern that potential revocation of market-based rate 
authorization and refusal to find a merger in the public interest are 
actions that make it legally or economically impossible for any public 
utility not to participate in an RTO. EEI observes that such linkage 
would change settled law requiring reasoned analysis or factual 
findings. Similarly, Consumers Energy submits that summary withdrawal 
of existing market-based rate authorization must be justified by 
substantial evidence of changed circumstances. CP&L claims that the 
Commission cannot impose RTO participation conditions on a proposed 
merger that go beyond the consistency with the public interest standard 
under the FPA.
    Two commenters suggest that the Commission must proceed on a case-
by-case basis. MidAmerican contends that there is no clear indication 
that the number of parties competing in generation markets is so small 
to cause inadequate levels of competition. Since changes to restructure 
the industry into RTOs will be costly and difficult for all parties, 
mandates or sanctions should be based only on willful violations of 
Commission policy. LG&E concurs that only where the record supports a 
case-specific finding that a transmission owner's failure to 
participate in an RTO will result in undue discrimination or the 
ability to exercise market power should the Commission take remedial 
steps to address the situation so that the Commission is on firm legal 
grounds.
    On the other hand, a number of commenters believe the Commission 
must require RTO participation as a condition of future market-based 
rate transactions and authorizations. TAPS notes that this is necessary 
for the Commission to meet its obligation to protect consumers from 
unjust and unreasonable rates if it intends to pursue a lighter-handed 
regulatory approach, adding that only RTOs of appropriate size and 
structure will be able to meet fully the Commission's statutory 
obligation to protect consumers. Oneok and New Smyrna Beach argue that 
manipulation and undetectable anticompetitive conduct for which there 
is no practical after-the-fact remedy are concerns that could be 
alleviated by an RTO and that, accordingly, denial of merger approval 
or market-based rate authorization is well within the Commission's 
authority when anticompetitive factors have not been mitigated.
    PJM/NEPOOL Customers, Great River, East Texas Cooperatives and PNGC 
support revoking market-based rate authorization to remedy inherent 
discrimination resulting from non-participation and also using non-
participation as a factor in merger analysis. APPA favors imposing the 
merger condition in the form of an immediate requirement to participate 
given the Commission's prior experience with conditioning mergers with 
commitments to join an ISO. merican Forest supports conditioning all 
future market-based rate transactions on participation. H.Q. Energy 
Services encourages the Commission to explore the full extent of its 
authority under the FPA to compel participation in RTOs.
    Enron/APX/Coral Power recommend that the Commission create a 
rebuttable presumption that RTO participation is required for approval 
of market-based pricing or a transfer of facilities under section 203 
of the FPA. For market-based rate authorizations, the Commission should 
establish a presumption that a decision by a transmission owner not to 
participate in an RTO is evidence that it is misusing its transmission 
facilities to advantage its merchant function. This presumption could 
be rebutted through a demonstration that stand-alone operation of the 
non-participant's grid serves the public interest as well as or better 
than participating in an RTO. They suggest that utilities currently 
with market-based rate authorizations should be ordered to show cause 
by the December 15, 2001, implementation deadline why their market rate 
authorizations should not be revoked. Enron/APX/Coral Power also 
recommend that all sales, leases, mergers and consolidations of 
transmission systems be conditioned on RTO participation based on a 
presumption that it is inconsistent with the public interest to dispose 
of transmission facilities without eliminating the incentive to

[[Page 834]]

discriminate by committing the operation of those facilities to an RTO.
    Industrial Consumers believes that the engineering and economic 
efficiencies of RTO participation loom so large that the Commission is 
justified in adopting a presumption that a decision by a transmission 
owner not to participate in an RTO is evidence that it is misusing its 
transmission facilities. Industrial Consumers recommends that the 
Commission assert jurisdiction over the transmission component of 
bundled sales, and order that the rates, terms and conditions offered 
under the OATT apply to all eligible customers. This would deprive 
vertically-integrated utilities of the incentive to resist RTO 
participation.
    State commission commenters tend to favor the Commission using 
conditioning authority, but some are not sure this will necessarily 
encourage participation in RTOs. Oregon Commission comments that unless 
a utility can demonstrate that it cannot manipulate the transmission 
system to its advantage or that an RTO is impossible, the Commission 
should revoke its ability to sell at market-based rates. Complaints of 
unfair practices without credible reasons should be prima facie 
evidence of market power. Pennsylvania Commission recommends that the 
Commission revisit previously granted market-based rate authorizations. 
Indiana Commission cautions, however, that a recalcitrant utility that 
does not join an RTO may not perceive loss of market-based pricing 
authorization as detrimental. Illinois Commission does not oppose 
conditioning merger and market-based rate approvals on RTO 
participation, but it also believes that the threat of these penalties 
may be inadequate to induce RTO participation.
    Comments on Consequences for Failure to File, or Filing Alternative 
Explanation. The majority of comments on this issue support the 
Commission taking additional action if adequate RTOs do not form. PJM/
NEPOOL Customers suggests that strict penalties must be assessed 
against actions inconsistent with RTO formation. Oneok suggests that 
certain benefits that are within the Commission's authority and 
discretion to grant or deny should be withheld from utilities unwilling 
to participate. Project Groups recommend that the Final Rule provide 
that the Commission itself create RTOs if the stakeholders are unable 
or unwilling voluntarily to do so by a reasonable date certain. PNGC 
suggests that if RTOs do not form within a reasonable time, the 
Commission should explore its authority or seek new authority to 
mandate participation by all utilities.
    On the other hand, Duke is concerned that the Commission may not 
accept valid reasons for nonparticipation and use the October 15, 2000, 
alternative filings as vehicles to mandate RTO membership. Duke offers 
that the Commission cannot consider imposing penalties for non-
participation while simultaneously claiming that its policy on 
participation is voluntary. Seattle cautions that the Commission should 
exercise care not to unfairly sanction transmission-owning utilities 
that cannot participate in an RTO (e.g., where good cause is shown that 
participation would violate state and local legal obligation, or the 
costs of RTO participation outweighs the benefits).
    Commission Conclusion. Based on the record before us with respect 
to undue discrimination and market power, as well as with respect to 
economic and engineering issues affecting reliability, operational 
efficiency, and competition in the electric industry, it is clear that 
RTOs are needed to resolve impediments to fully competitive markets. 
However, we continue to believe, as we proposed in the NOPR, that at 
this time we should pursue a voluntary approach to participation in 
RTOs.
    We acknowledge that there are many commenters who are skeptical 
that a voluntary approach will be able to accomplish our stated 
objective, which, as we stated in the NOPR,132 is for all 
transmission-owning entities to place their transmission facilities 
under the control of RTOs in a timely manner. In general, they argue 
that those with a market advantage will not easily give it up, and that 
voluntary efforts to date have not been very successful in creating 
effective regional entities.
---------------------------------------------------------------------------

    \132\ FERC Stats. and Regs. para. 32,541 at 33,685.
---------------------------------------------------------------------------

    However, we believe that a voluntary approach as we have structured 
it, with guidance and encouragement from the Commission, is most 
appropriate at this time. Given the rapidly evolving state of the 
electric industry, we want to allow involved participants the 
flexibility to develop mutually agreeable regional arrangements with 
respect to RTO formation and coordination. Further, we want the 
industry to focus its efforts on the potential benefits of RTO 
formation and how best to achieve them, rather than on a non-productive 
challenge to our legal authority to mandate RTO participation.
    We believe the voluntary approach to RTO formation can be more 
successful now than in the past for several reasons. The pace of 
industry restructuring is accelerating. Many formerly vertically 
integrated utilities have recently recognized the strategic benefits to 
them of concentrating solely in one of the traditional utility areas 
(generation, transmission, or distribution). Moreover, the NOPR has 
focused industry attention on RTOs and their benefits. Further, this 
Final Rule is providing clear rules and guidance on what is necessary 
to form an RTO. Through this Final Rule, we are also committing the 
Commission to act as a catalyst in RTO discussions by initiating and 
encouraging a collaborative process. Finally, we have provided in this 
Final Rule for certain favorable ratemaking treatments for those who 
assume the risks of the transition to a new structure, which should, at 
a minimum, eliminate any rate disincentives to RTO formation.
    We are not adopting as a generic policy in this Final Rule either 
that RTO participation is required in order to retain or obtain market-
based rate authorization for wholesale power sales, or that RTO 
participation is required for a disposition of jurisdictional 
facilities to be in the public interest. However, in response to those 
who argue that the Commission has a statutory responsibility to remedy 
undue discrimination and anticompetitive effects when evaluating 
market-based rate and merger requests, we recognize that we may have to 
consider, in individual cases, issues that arise as to whether market 
power has been mitigated in the absence of RTO participation or as to 
whether a merger would be in the public interest without RTO 
participation.
    While we have concluded on this record that it is in the public 
interest to provide for a voluntary approach to RTO formation that 
relies upon encouragement, guidance, and support from the Commission, 
this does not mean that all aspects of this Rule are voluntary. The 
filing requirements set forth in section 35.34(c) of the new 
regulations are mandatory. In other words, public utilities must file 
either an RTO proposal or a report on the impediments to RTO 
participation. In addition, to qualify as an RTO, an applicant must 
comply with the minimum characteristics and functions and other 
specific RTO requirements set forth in the new regulations. We will 
also expect that all transmission owners will participate in good faith 
in the collaborative process that we are establishing herein.
2. Organizational Form of an RTO
    Comments. A number of commenters address the proposal to allow 
flexibility

[[Page 835]]

in the type of structure allowed for RTOs. Several of those commenting 
recommend maintaining the NOPR's flexibility and that the Commission 
not prescribe either a transco, ISO or some other 
structure.133 FirstEnergy advocates flexibility and says 
that no one knows today what the best structure will be for the future 
so, therefore, the Commission should allow customization reflecting 
regional needs. Several commenters, such as APPA, argue that the 
Commission's flexibility on type of organization should go beyond the 
standard ISO and transco structures and include gridcos, wirecos, not-
for-profit and for-profit forms of each organization, and hybrid 
organizations.
---------------------------------------------------------------------------

    \133\ See, e.g., EEI, Lincoln, LG&E, SERC and Washington 
Commission.
---------------------------------------------------------------------------

    Numerous commenters state a preference in favor of for-profit 
transcos although many of these commenters still recommend that other 
structures be allowed at each region's option.134 In 
favoring transcos, commenters cite the greater efficiency due to a 
transco's profit motive.135 Commenters further argue that 
for-profit transcos can better serve the goal of independence because 
the transco would make all business decisions,136 can more 
cleanly divide Commission-regulated transmission from state-regulated 
distribution,137 and can operate more efficiently by 
integrating investment decisions, facility design, construction and O&M 
into a unified strategy.138 A few additional supporters of 
transcos prefer that they be not-for-profit.139 Gainesville 
recommends further that transcos in Florida become an instrumentality 
of the state.
---------------------------------------------------------------------------

    \134\ See, e.g., Allegheny, Entergy, INGAA and Trans-Elect.
    \135\ See, e.g., Sierra Pacific, H.Q. Energy Services and 
Detroit Edison.
    \136\ MidAmerican.
    \137\ CTA.
    \138\ Duke.
    \139\ LPPC, Los Angeles, Gainesville and Public Citizen.
---------------------------------------------------------------------------

    In contrast to the above, ISOs are preferred by a number of 
commenters.140 PJM argues that ISOs are necessary to ensure 
independence, provide more independent market monitoring and have a 
fiduciary duty to the public interest. PJM also notes that ISOs can 
meet the Commission's objectives more quickly than transcos. NASUCA 
reports that some of its members oppose for-profit transcos because of 
their ``natural incentive to extract monopoly rents from consumers.'' 
141 Some of those who prefer ISOs contend that transcos 
would favor transmission solutions over generation solutions to 
congestion.142 This argument is contested in the reply 
comments of Trans-Elect and others. NEPCO et al. maintains that the 
alleged bias in favor of transmission solutions can be overcome by 
using performance-based rates to replace standard rate base regulation.
---------------------------------------------------------------------------

    \140\ See, e.g., NASUCA, PJM and ICUA.
    \141\ NASUCA at 20.
    \142\ See, e.g., PJM and ISO-NE.
---------------------------------------------------------------------------

    Some commenters favor a hybrid involving an ISO with a gridco or 
with another type of organization.143 As noted above, many 
commenters recommend flexibility and believe that either an ISO or 
transco would satisfy the needs of an RTO if designed properly.
---------------------------------------------------------------------------

    \143\ See, e.g., ISO-NE.
---------------------------------------------------------------------------

    Several commenters cited problems that need to be worked out for 
both transcos and ISOs. Professor Joskow notes that ISOs would suffer 
efficiency losses from the separation between ownership and operation 
of transmission assets. This separation makes it harder to apply 
incentive regulation because it divides decisions that affect the costs 
of transmission between two organizations. On the other hand, Professor 
Joskow says that an ISO may be superior to a transco where transmission 
ownership is presently so balkanized that loop flow and congestion 
cannot be managed, but he asserts that this advantage may decline over 
time as the industry changes. Southern Company says that while some see 
ISOs as ineffective bureaucracies which add to transmission risk, the 
creation of transcos presents substantial tax and financial problems.
    A few commenters contend that the NOPR's provisions produce a bias 
in favor of ISOs even though this intent is not noted.144 
For example, Duke argues that the NOPR provisions for stakeholder 
participation in formation, governance and market monitoring functions 
seem more geared toward the ISO form of organization. These commenters 
recommend that the Final Rule not include such a bias.
---------------------------------------------------------------------------

    \144\ See, e.g., Sierra Pacific, Duke and Enron/APX/Coral Power.
---------------------------------------------------------------------------

    A number of commenters suggest multi-layered structural 
alternatives. For example, ISO-NE proposes an ISO and gridco operating 
in tandem. A non-profit ISO would direct the operation of the 
transmission system and run day-ahead and real-time power markets 
coupled with a grid entity that owns and maintains the transmission in 
the area operated by the ISO. This, they claim, would require a final 
rule that defines an RTO as an entity, or a combination of entities 
working in collaboration, that satisfies the minimum characteristics 
set forth in the NOPR. Under the model discussed by ISO-NE, the ISO 
would have responsibility for assuring open transmission access, 
operating the regional transmission assets (including provision of 
switching orders to the gridco), monitoring power markets, serving as a 
clearing agent and possibly serving as a clearinghouse, and maintaining 
short-term reliability. The gridco would own and maintain transmission 
assets, operate transmission assets in response to ISO directions 
consistent with safety requirements, and build new transmission 
facilities (including licensing, permitting and siting 
responsibilities). Joint responsibilities would include planning 
upgrades to transmission system.
    ISO-NE argues that ISOs alone would have disadvantages in the realm 
of transmission expansion due to fragmentation of transmission 
ownership. A gridco, however, could raise investment capital, bring 
parallel and complementary strengths to an ISO, and should bring crisp 
and decisive implementation of transmission planning and expansion 
decisions. Pairing an ISO with a gridco, ISO-NE argues, would eliminate 
the problems inherent in a transco by separating transmission ownership 
from market administration and market monitoring.
    Midwest ISO suggests a structure that it believes could meld the 
best of both ISOs and transcos, i.e., an ISO that would allow an 
independent transmission company to operate under the Midwest ISO. This 
model would not require that all transmission be owned by a single 
gridco--transmission owners could decide whether to operate directly 
through the ISO, or spin assets off to a gridco that would operate 
under the ISO. Midwest ISO argues that this proposal overcomes the 
problems encountered in expecting all transmission owners to divest 
their transmission assets to separate companies.
    PGE points out that, ``for an RTO to achieve * * * critical mass in 
the near term, it must be capable of managing a regional transmission 
market in which a variety of subsidiary transmission structures will be 
in place. Such subsidiary structures may include single-company and 
sub-regional ITCs, integrated utilities located in states that already 
have restructured their retail electric markets, integrated utilities 
located in states that have not yet restructured, and publicly-owned 
and federal utilities.'' PJM argues that ISOs

[[Page 836]]

should be present even in regions that form separate transmission-
owning companies to avoid continued conflict regarding the neutrality 
and commercial consequences of grid management decisions.
    Professor Hogan states that it is very unlikely that a pure transco 
model is viable at all. He further indicates that, ``the advantages of 
an independent transmission company can be pursued through the gridco 
model with an accompanying ISO.'' He suggests that this approach is 
already well advanced in the United States and elsewhere, and that by 
separating ownership of the wires from control of system operations, it 
would be easy to accommodate a complex pattern of ownership.
    ComEd says that characteristics and functions should be performed 
by two linked organizations that make up a binary RTO: a for-profit ITC 
under the oversight of an independent not-for-profit regional 
transmission board.
    Michigan Commission believes that wirecos, transcos and ISOs are 
all interim transitional organizations along the path toward very large 
RTO-like organizations. Even if vestiges of the smaller interim 
organizations continue to exist, they should operate under some kind of 
RTO umbrella to assure appropriate regional control. Missouri 
Commission proposes a zonal model in which the zones are areas where 
generation is integrated through the transmission grid in such a way as 
to minimize restrictions on sources of generation used in the area. In 
the future, independent transmission companies may form with the 
possibility that adjacent control areas will join to form larger zones. 
In such a case, an RTO is a collection of zones for purposes of 
administering the regional gatekeeper function and providing markets 
for transmission congestion. Each zone would be responsible for 
maintaining its transmission facilities and coordinating both the use 
and expansion of those facilities with the RTO.
    WEPCO proposes that each RTO should be composed of two parallel 
organizations to serve the same region under a common, independent 
board: a Regional Reliability Council to develop regional reliability 
rules and a not-for-profit ISO that operates under those regional 
rules.
    Cal DWR suggests a three-tiered structure that builds on existing 
organizations. Existing NERC regional councils should set broad 
governing criteria for ISO reliability issues, parallel path flow 
issues, and for regional planning. More than one ISO may be located in 
each NERC region. These should control area reliability, administer 
transmission terms and conditions, and create market mechanisms to 
manage congestion, among other functions. Transmission owners should 
support, but not duplicate the roles of NERC regional councils.
    Commission Conclusion. We will not limit the flexibility of 
proposed structures or forms of organization for RTOs. We are prepared 
to accept a transco, ISO, hybrid form, or other form as long as the RTO 
meets our minimum characteristics and functions and other requirements.
    Some of the commenters argue that the NOPR's requirements either 
favor one form of organization over others or make one or the other 
forms very difficult to construct. It is not our intention to favor or 
disfavor transcos, ISOs, or other organizational form. We acknowledge 
that some of our minimum requirements might affect transcos and ISOs 
differently, but there also may be different acceptable ways for an ISO 
or transco to satisfy the minimum requirements. However, we designed 
this Final Rule to be neutral as to organizational form, and we do not 
believe that the requirements for forming an RTO in this Final Rule 
favor any particular RTO structure.
    Arguments are made that an ISO is the better form of RTO because an 
ISO has no incentive either to favor transmission solutions to solve 
congestion constraints or to perpetuate congestion. ISOs are easier to 
form, in most cases, because there are fewer tax and mortgage 
consequences as there is no actual transfer of ownership.
    On the other hand, some argue that transcos are preferable because 
they introduce a profit motive for efficient operation and expansion. 
Performance-based rates are normally considered more effective with 
transcos than with ISOs. Advantages are cited for having the same 
entity both propose and carry out transmission expansion and 
maintenance.
    The transco and ISO forms of organization each has its advantages 
and disadvantages as do combination forms and other forms that have 
been suggested. In many cases, the situation facing transmission owners 
in a particular region may influence the appropriate form of 
organization to propose. In other cases it may be a matter of 
preference for how the participants wish to do business. Some may 
propose to start operation in one form and transform to another form at 
a future date. Tax consequences, public ownership, bond indentures and 
current organization will each have an impact on the decision of what 
form of organization a particular RTO will propose.
    This Rule does not necessarily require that a single organization 
perform all of the functions itself. To mention but a few examples, we 
specifically clarify in other parts of this Final Rule that the 
security coordinator function and the OASIS function could be shared 
with another RTO or contracted out, and that appropriate scope may be 
achieved in creative ways. We will entertain appropriate tiered or 
other structures. We require only that the RTO be responsible for 
ensuring that the requirements are met in a way that satisfies our 
Rule.
    Because of the differing conditions facing various regions, we 
offer flexibility in form of organization. We welcome innovative 
structures and forms that meet the needs of the market participants 
while satisfying the minimum requirements of this Rule.
3. Degree of Specificity in the Rule
    Comments. Many commenters believe that our proposed flexible 
approach is either still too rigid, or that it should provide clearer 
guidance. INGAA argues for less specificity in the Final Rule. INGAA 
points to the success of Order No. 636, wherein the Commission required 
open access, functional unbundling, and a new rate design, and it 
established specific requirements for operational control and pipeline 
capacity trading, all without having to specify the structure of the 
conforming gas transmission entity. NU similarly points to the 
precedent of the restructured gas industry. It states that the 
Commission should avoid the perils of imposing a rigid system pursuant 
to the mistaken belief that it can be easily and swiftly changed later 
to respond to future needs of the marketplace. CP&L also cautions that 
the principle of flexibility could prove illusory in practice and that 
there is a danger that, if guidance from the Commission takes the form 
of overly restrictive rules, it will stifle the development of 
innovative proposals. PG&E submits that the Commission should simply 
define a broad standard that provides for independence and evaluate 
particular RTO proposals on a case-by-case basis. South Carolina 
Commission also counsels that the Commission should not attempt to 
mandate a particular form of RTO, or establish its size or region, 
because this will not ensure that an efficient market will develop. It 
posits that any RTO policy should be flexible enough and dynamic enough 
to allow for both regional and

[[Page 837]]

organizational differences and for growth and changes in the future.
    SCE&G claims that the NOPR is overly prescriptive with respect to 
both scope and timing. TXU Electric submits that the NOPR's approach to 
reliance on minimum characteristics and functions seems to reflect a 
significant number of fundamental policy decisions that have already 
been made without the benefit of any of the very experimentation the 
NOPR extols. Southern Company argues that the Commission should recast 
the characteristics and functions as voluntary guidelines at this early 
stage in the development of RTOs, since it is unclear what the best 
form of RTO will be.
    ISO supporters, such as NYPP and Central Maine, recommend that the 
Commission reject proposals to impose rigid and inflexible rules on 
RTOs and remain flexible especially with regard to existing ISOs and 
RTO pricing. ISO-NE counsels that tolerance for a diversity of 
approaches is essential, as well as politically pragmatic, due to the 
fact that different regions will have different histories, industry 
elements, and local regulatory policies that need to be accommodated.
    FirstEnergy supports the NOPR's flexibility because there is no 
best model to deal with regional variations. Alliance Companies and 
Washington Commission also recommend that the Commission adhere to a 
flexible RTO policy, open to voluntary regional experimentation in the 
design of RTO structures. In addition, both Southern Company and Trans-
Elect recommend that the Commission maintain flexibility toward 
transcos. And while a transco supporter, Entergy, sees the NOPR as 
properly flexible in regard to for-profit and not-for-profit RTOs. 
Finally, Duke agrees that RTOs should satisfy key principles, as long 
as they are not so prescriptive as to promote only one type of RTO.
    On the other hand, Illinois Commission submits that the NOPR's 
minimalist approach will lead to creation of lowest common denominator 
RTOs that minimally comply with the characteristics and functions and 
general guidance as to geographic scope and membership. Project Groups 
suggests that the Commission expand and strengthen the minimum 
characteristics. TDU Systems recommends that the Commission resist 
calls to water down its Final Rule and urges more substance. TAPS 
claims that calls for more flexibility are really a cover for diluted, 
ineffective RTOs that will lack the scope, independence and authority 
to get the job done.
    Commission Conclusion. While many commenters think that our 
proposal to rely on guidance and flexibility to promote establishment 
of appropriate RTOs is either too rigid or too non-specific, we 
conclude that we struck an appropriate balance in the NOPR.
    Although we and the electric industry see many problems associated 
with the operation of the Nation's transmission systems and we see a 
general need for regional transmission solutions, we cannot at this 
time foresee the best organizational means to resolve every problem. 
Given this situation, we believe that the right balance is a minimally 
intrusive, solution-oriented approach that provides guidance and 
specifies only the fundamental RTO characteristics and functions.
    We do not agree with those commenters who contend that the NOPR 
approach adopted herein is either overly or insufficiently 
prescriptive. Certainly the minimum characteristics and functions do 
reflect a number of threshold requirements, but collectively, these 
requirements serve to define the minimum necessary to improve the 
operation of the Nation's transmission systems. While we agree that 
there is no best answer and we encourage regional innovation, we cannot 
simply define a standard of independence and nothing else. This would 
leave the industry without direction and provides no guidance on how we 
would evaluate the various RTO proposals.
    Finally, we do not agree with those who suggest that our electric 
regulation must follow our natural gas pipeline industry Order No. 636 
model, where the Commission did not attempt structural unbundling of 
the pipeline industry but simply relied on more limited, functional 
unbundling. The situations in the two industries are different 
regarding the need for regional entities. Most importantly, there was 
not in the gas industry the degree of vertical integration of 
production, transmission, and distribution that historically existed in 
the electric industry. In addition, the gas industry has no analog to 
loop flow, transmission loading relief, the need for large regional 
calculations of ATC, or the use of generation energy and reactive power 
output to manipulate transmission flow, among other reasons.
4. Legal Authority
    In the NOPR, we noted that sections 205 and 206 of the FPA, 16 
U.S.C. 824d and 824e, give the Commission both the authority and 
responsibility to ensure that the rates, charges, classifications, and 
services of public utilities (and any rule, regulation, practice, or 
contract affecting any of these) are just and reasonable and not unduly 
discriminatory, and to remedy undue discrimination in the provision of 
such services. We stated that in fulfilling its responsibilities under 
FPA sections 205 and 206, the Commission is required to address, and 
has the authority to remedy, undue discrimination and anticompetitive 
effects.145 We also noted that the Commission has the 
authority and responsibility under section 203 of the FPA to review 
mergers and other transactions involving public utilities, including 
dispositions of jurisdictional facilities by public utilities, and that 
the Commission may grant an application under section 203 upon such 
terms and conditions as it finds necessary to secure the maintenance of 
adequate service and the coordination in the public interest of 
jurisdictional facilities.
---------------------------------------------------------------------------

    \145\ FERC Stats. & Regs. para. 32,541 at 33,695.
---------------------------------------------------------------------------

    Further, we noted that section 202(a) of the FPA authorizes and 
directs the Commission ``to divide the country into regional districts 
for the voluntary interconnection and coordination of facilities for 
the generation, transmission, and sale of electric energy.'' The 
purpose of this division into regional districts is for ``assuring an 
abundant supply of electric energy throughout the United States with 
the greatest possible economy and with regard to the proper utilization 
and conservation of natural resources.'' Section 202(a) states that it 
is ``the duty of the Commission to promote and encourage such 
interconnection and coordination within each such district and between 
such districts.''
    We solicited comments on whether the Commission should generically 
mandate RTO participation by all public utilities to remedy undue 
discrimination under sections 205 and 206 of the FPA, whether market-
based rates for generation services could continue to be justified for 
a public utility that does not participate in an RTO, whether a merger 
involving a public utility that is not a member of an RTO would be 
consistent with the public interest, whether non-participants that own 
transmission facilities should be allowed to use the non-pancaked 
transmission rates of the RTO participants in that region, whether 
transmission services provided by a transmitting utility need to be 
under RTO control to satisfy the discrimination standards of sections 
211 and 212 of the FPA, and whether a public utility's lack of 
participation

[[Page 838]]

would otherwise be in violation of the FPA.146
---------------------------------------------------------------------------

    \146\ Id. at 33,762.
---------------------------------------------------------------------------

    Comments. The comments on the Commission's legal authority to 
mandate participation in RTOs span the spectrum from those asserting 
that we clearly have that authority to those asserting that we clearly 
do not, with others taking a less definitive position in between.
    Supporting Commission's Authority to Mandate RTO Participation. 
Representative of those asserting that the Commission has the authority 
to mandate RTO participation are the joint comments filed by APPA, 
ELCON, TAPS, and TDU Systems (``APPA et al. (WP)''). These parties 
argue that the FPA as presently constituted gives the Commission 
``ample'' legal authority to require participation by public utilities 
in properly structured and configured RTOs. APPA et al. assert that 
section 202(a) permits the Commission to determine rational and 
efficient regional boundaries; section 203 provides authority to 
require RTO participation as a standardized condition to mitigate the 
increased generation and transmission concentration brought about by 
mergers; ``it would be fully consistent with, and indeed required by'' 
FPA section 205 to insist on RTO participation as a condition necessary 
to yield competition robust enough to produce just and reasonable 
market-based rates; requiring RTO participation falls within the 
Commission's broad discretion to fashion a remedy for undue 
discrimination under FPA sections 205 and 206; and the Commission could 
reasonably conclude that it is no longer just and reasonable for 
transmission service to be planned, implemented, or priced on a less-
than-regional basis. Other commenters echo some or all of these points 
in asserting that the Commission currently has sufficient legal 
authority to mandate RTO participation.147
---------------------------------------------------------------------------

    \147\ E.g., UAMPS, PJM/NEPOOL Customers, Illinois Commission, 
Michigan Commission, Cinergy, Industrial Consumers, First Rochdale, 
East Texas Cooperatives, FMPA.
---------------------------------------------------------------------------

    Some other commenters emphasize the authority contained in 
particular statutory sections. One commenter states that FPA section 
202(a) is an express delegation of authority to the Commission to make 
policy, and the stated goal of that section of assuring an abundant 
supply of electric energy with the greatest possible economy provides 
ample authority to support the conclusion that transmission facilities 
should be operated by an RTO. This commenter states that it is well 
established administrative law that there is great deference given to 
an agency charged with policymaking responsibility.148 
Another commenter, FMPA, argues that the Commission's interconnection 
authority under FPA sections 202(b) and 210 provides ample basis for 
mandating RTO participation. According to FMPA, the Commission could 
find that RTO participation is necessary to ``make effective'' an 
interconnection, pursuant to FPA section 210, that has been rendered 
ineffective by fragmented and anticompetitive practices of transmission 
owners. FMPA also asserts that the Commission could use this authority 
through a rulemaking without following the individual procedural 
requirements of section 212.149
---------------------------------------------------------------------------

    \148\ Professor Koch, citing Chevron U.S.A., Inc. v. Natural 
Resources Defense Council Inc., 467 U.S. 837 (1984).
    \149\ Citing American Paper Institute, Inc. v. American Elec. 
Power Serv. Corp., 461 U.S. 402, 419-20 (1983).
---------------------------------------------------------------------------

    In addition to those commenters finding clear authority in the FPA 
for an RTO mandate, a number of commenters support the suggestion, as 
one commenter put it, that certain benefits and rights that are within 
the Commission's authority and discretion to grant or deny should be 
withheld from utilities unwilling to participate in an 
RTO.150 PNGC states that the Commission should use ``big 
sticks'' to obtain RTO participation, and Michigan Commission says the 
Commission ``should use every stick, carrot, orange-colored stick and 
tool it can.'' Some commenters assert specifically that the Commission 
has the authority, and should use its authority, to condition mergers 
under section 203 and condition market-based rate authority under 
section 205 of the FPA on RTO participation.151 Some 
commenters also favor limiting access to non-pancaked transmission 
rates of RTOs to those who participate in RTOs.152
---------------------------------------------------------------------------

    \150\ Oneok.
    \151\ E.g., Oneok, TAPS, APPA, PJM/NEPOOL Customers, Illinois 
Commission, Industrial Consumers, East Texas Cooperatives, FMPA, TDU 
Systems and PNGC.
    \152\ E.g., TDU Systems, PNGC and PJM/NEPOOL Customers.
---------------------------------------------------------------------------

    Even some commenters that generally oppose the idea of an RTO 
mandate acknowledge that market-based rate authority or mergers could, 
on a case-by-case basis, be conditioned on RTO participation. For 
example, Florida Power Corp. states that the Commission could find, 
``given certain factual circumstances,'' that the granting of market-
based rate authority would not be appropriate ``unless the entity 
agreed to commit its transmission facilities to an RTO.'' United 
Illuminating states that whatever conditioning authority the Commission 
may have for market-based rates or mergers could not be used as a basis 
for a generic rulemaking.
    NECPUC cites to other sections of the FPA that the Commission might 
rely upon to promote RTO establishment. It supports the use of the 
complaint process under section 206 of the FPA in specific cases. It 
also suggests the use of FPA section 207 proceedings, which can be 
initiated by state commissions, as a vehicle for requiring RTOs where 
the Commission finds interstate service inadequate or insufficient. 
NECPUC also urges the use of joint boards and cooperative procedures 
between the Commission and the states under FPA section 209 as a means 
of resolving RTO issues.
    Opposing Commission's Authority to Mandate RTO Participation. At 
the other end of the debate on the Commission's legal authority with 
respect to RTOs are those that assert that the Commission's authority 
to mandate RTOs is non-existent or very limited.153 A number 
of commenters emphasize that FPA section 202(a) is explicitly voluntary 
and therefore provides no support for the Commission's authority to 
mandate RTOs.154 FP&L states that it is questionable whether 
the Commission could use FPA section 202(a) as a tool to promote 
competition, given that section 202(a) is for the ``coordination and 
interconnection of facilities,'' and coordination is arguably 
inconsistent with competition.
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    \153\ E.g., Southern Company, Puget, Avista, CP&L, Duke, STDUG, 
FirstEnergy, NYPP, Indianapolis P&L, FP&L, Detroit Edison, Florida 
Power Corp., Florida Commission, Alabama Commission.
    \154\ E.g., EEI, United Illuminating, Southern Company, Central 
Maine, CP&L, Duke, NYPP, Florida Power Corp., Florida Commission.
---------------------------------------------------------------------------

    Some argue that the exercise of FPA section 206 authority to remedy 
discrimination on a generic basis by requiring RTOs would have to be 
supported by more explicit findings of discrimination than are 
contained in the NOPR.155 For example, Florida Power Corp. 
and United Illuminating contend that the Commission cannot use an 
industry-wide solution to remedy a problem that does not exist 
industry-wide,156 and the record does not demonstrate an 
industry-wide problem. EEI and others argue that the Commission may 
only impose a remedy that is reasonable and appropriate in light of the 
specific discriminatory

[[Page 839]]

findings made and the actual practices to be corrected, and the NOPR 
fails to demonstrate such a nexus. Southern Company notes that the 
Commission has not made any finding of discrimination and that the 
``perception'' of discrimination is an insufficient basis on which to 
invoke FPA sections 205 and 206. CP&L asserts that section 206 may give 
the Commission some authority with respect to requiring RTOs, but only 
in individual cases after hearings and substantial evidence of 
discriminatory practices. Southern Company contends that the 
Commission's remedial authority under section 206 must be construed in 
light of the voluntary nature of section 202(a) and the Commission 
cannot do anything indirectly under section 206 that it cannot do 
directly under section 202(a). Central Maine asserts that 
discrimination findings would not apply against a ``wires only'' 
company such as itself, and similarly, Indianapolis P&L argues that it 
has no ability to discriminate in favor of its own wholesale generation 
and therefore could not be forced to join an RTO as a remedy for 
discrimination.
---------------------------------------------------------------------------

    \155\ E.g., EEI, Central Maine, Southern Company, Duke, NYPP, 
Dalton Utilities, Indianapolis P&L, Florida Power Corp., Entergy.
    \156\ Citing Associated Gas Distributors v. FERC, 824 F.2d 981 
(D.C. Cir. 1987), cert. denied, 485 U.S. 1006 (1988).
---------------------------------------------------------------------------

    Some commenters question the Commission's authority to condition 
market-based rates or mergers on RTO participation. Central Maine 
argues that the Commission could not conclude on a generic basis that 
an RTO is needed in every market-based rate case, and that the 
Commission could not change its existing policy on market-based rates 
without substantial evidence and reasoned decisionmaking. CP&L states 
that the Commission cannot use FPA section 205 authority to grant 
market-based rates merely to advance preferred policies, and cannot use 
FPA section 203 to condition mergers absent specific findings in a 
particular case. Duke contends that the Commission has no authority to 
issue a rule that imposes sanctions for non-participation that would 
make non-participation practically or economically unfeasible. 
Similarly, NYPP states that mergers, market-based rates, and access to 
non-pancaked transmission rates are economic necessities, and using 
them as conditions would effectively require RTO participation. 
Indianapolis P&L asserts that it would be inequitable and unjustifiable 
to withhold market-based rate authority from a utility that has a good 
reason not to participate in an RTO, and further, that the Commission 
may not pressure a utility to engage in an activity that it may not 
require through direct regulation.157 Similarly, Puget 
states that if the Commission is not mandating RTOs, which is beyond 
its authority, then the rule must contain no penalties for non-
participation.
---------------------------------------------------------------------------

    \157\ Citing Altamont Gas Transmission Co., v. FERC, 92 F.3d 
1239, 1246 (D.C. Cir. 1996).
---------------------------------------------------------------------------

    Several commenters point to the recent court decision in Northern 
States 158 as limiting the Commission's authority with 
respect to RTOs.159 These parties assert that Northern 
States stands for the proposition that the Commission may not directly 
or indirectly interfere with state regulation of retail service, and 
that the NOPR would result in traditional utility retail 
responsibilities being shifted to RTOs. Specifically, for example, 
Puget alleges that redispatch and planned maintenance are reliability 
functions that affect the utility's ability to serve native load and 
are subject to state law. Indianapolis P&L asserts that Northern States 
makes clear that the Commission may act only under authority given by 
Congress.
---------------------------------------------------------------------------

    \158\ See Northern States, supra note 89.
    \159\ E.g., Southern Company, Puget, Indianapolis P&L, FP&L, 
Florida Commission.
---------------------------------------------------------------------------

    A variety of other legal arguments are made in opposition to any 
Commission efforts to mandate RTO participation. Southern Company 
contends that since there has been no finding that Order Nos. 888 and 
889 have failed, there has been no reasonable explanation as to why the 
Commission should change that policy. CP&L argues that the Commission's 
authority to enforce FPA section 205 is in the enforcement provisions 
of FPA sections 314, 316, and 317. CP&L also states that it would be 
discriminatory to have higher pancaked rates for non-participants in 
RTOs while participants get the advantage of non-pancaked rates. Duke 
and Florida Power Corp. assert that requiring involuntary wheeling and 
imposing common carrier status is outside the Commission's 
authority,160 and likewise, so is mandating RTOs. Florida 
Power Corp. contends that requiring RTO participation would force a 
utility to join an ISO or divest its transmission or generation assets, 
and the Commission cannot compel divestiture. Florida Power Corp. and 
Southern Company make the point that the Public Utility Holding Company 
Act granted the SEC, not the FERC, the authority to restructure the 
electric utility industry. Florida Power Corp. further argues that 
requiring RTO participation would be a ``taking'' of utility property 
for which just compensation would be owed, and that the ``taking'' 
problem is exacerbated by utilities being liable for facilities no 
longer under their control. Florida Commission states that the Energy 
Policy Act of 1992 indicated that the Commission should proceed with 
transmission access issues case-by-case, not generically.
---------------------------------------------------------------------------

    \160\ Citing Richmond Power & Light Co. v. FERC, 574 F.2d 610 
(D.C. Cir. 1978) and Otter Tail Power Co. v. U.S., 410 U.S. 366 
(1973).
---------------------------------------------------------------------------

    Other Comments On Legal Authority. DOE submitted comments strongly 
supporting the Commission's efforts to establish RTOs. DOE states that 
while the Commission has substantial authority to accomplish much of 
what needs to be done, Federal legislation clarifying Commission 
authority, especially with respect to non-jurisdictional utilities, 
would greatly facilitate RTO formation.
    One commenter raised the issue of what authority the Commission 
would rely upon to require the filings in proposed section 35.34(c). 
This commenter wants the Commission to clarify that the filings would 
be required pursuant to the information gathering authority under FPA 
sections 304, 307, and 311, and not under authority of section 205, 
which the commenter asserts provides no such authority.161
---------------------------------------------------------------------------

    \161\ Consumers Energy.
---------------------------------------------------------------------------

    There were only a few comments in response to the Commission's 
inquiry about sections 211 and 212 or other FPA standards. Florida 
Power Corp. submits that the Commission cannot rely on FPA sections 211 
and 212 to mandate RTOs. Florida Power Corp. notes that in Order Nos. 
888 and 888-A, the Commission recognized that it does not have the 
authority to order wheeling pursuant to FPA sections 211 and 212 except 
on a case-by-case basis after an evidentiary hearing resulting in 
specific findings. Florida Power Corp. argues that because the 
Commission is fashioning an industry-wide generic solution and not 
acting on a case-by-case basis, the Commission cannot rely on sections 
211 and 212 in this proceeding.
    NARUC also notes that Congress revised FPA sections 211 and 212 to 
provide FERC with authority to address requests for non-discriminatory 
transmission service on a case-by-case basis. NARUC argues that the 
goal of promoting regional flexibility is more readily served by case-
by-case consideration. In this way, NARUC believes that the Commission 
can use FPA sections 211 and 212 to take a more tailored approach 
rather than ``one-size-fits-all'' regulations that ignore market 
development and local conditions.
    Commission Conclusion. Much of the discussion in the comments on 
the Commission's legal authority with

[[Page 840]]

respect to RTOs focuses on whether the Commission has the statutory 
authority to mandate that transmission owners participate in an RTO. As 
discussed elsewhere in this Final Rule, we have decided not to mandate 
generically that all public utility transmission owners must join an 
RTO. We conclude that the Commission possesses both general and 
specific authorities to advance voluntary RTO formation. We also 
conclude that the Commission possesses 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.162 Of course, RTO participation is not the only 
remedy that the Commission might employ to address these problems.
---------------------------------------------------------------------------

    \162\ We need not decide in this case the extent of the 
Commission's authority to mandate generically RTO participation.
---------------------------------------------------------------------------

    FPA sections 205 and 206. As we stated in the NOPR, the Commission 
is granted the authority and responsibility by FPA sections 205 and 
206, 16 U.S.C. 824d and 824e, to ensure that the rates, charges, 
classifications, and service of public utilities (and any rule, 
regulation, practice, or contract affecting any of these) are just and 
reasonable and not unduly discriminatory, and to remedy undue 
discrimination in the provision of such services. In fulfilling its 
responsibilities under FPA sections 205 and 206, the Commission is 
required to address, and has the authority to remedy, undue 
discrimination and anticompetitive effects. The Commission has a 
statutory mandate under these sections to ensure that transmission in 
interstate commerce and rates, contracts, and practices affecting 
transmission services, do not reflect an undue preference or advantage 
(or undue prejudice or disadvantage) and are just, reasonable, and not 
unduly discriminatory or preferential.163 Additionally, as 
discussed in Order No. 888,164 there is a substantial body 
of case law that holds that the Commission's regulatory authority under 
the FPA ``clearly carries with it the responsibility to consider, in 
appropriate circumstances, the anticompetitive effects of regulated 
aspects of interstate utility operations pursuant to [FPA] sections 202 
and 203, and under like directives contained in sections 205, 206, and 
207.'' 165
---------------------------------------------------------------------------

    \163\ Once such a finding is made, the Commission is required to 
remedy it. 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).
    \164\ Order No. 888, FERC Stats. & Regs. para. 31,036 at 31,669.
    \165\ Gulf States Utilities Co. v. FPC, 411 U.S. 747, 758-59, 
reh'g denied, 412 U.S. 944 (1973). See City of Huntingburg v. FPC, 
498 F.2d 778, 783-84 (D.C. Cir. 1974) (Commission has a duty to 
consider the potential anticompetitive effects of a proposed 
Interconnection Agreement.)
---------------------------------------------------------------------------

    There are two principal contexts in which the authority of FPA 
sections 205 and 206 has been raised. One is the use of requiring 
participation in RTOs as a remedy for undue discrimination by public 
utilities. As discussed above, many commenters believe that the 
evidence of undue discrimination is sufficient to justify generically 
mandating RTO participation as a remedy, and many others argue that the 
record on undue discrimination is insufficient to impose a generic, 
industry-wide solution. We have concluded in our discussion elsewhere 
in this Rule that continuing opportunities for undue discrimination 
exist in the electric transmission industry. However, we have also 
concluded that a voluntary approach to eliminating such opportunities 
through RTO formation (including the filing requirements and Commission 
supported collaboration efforts identified herein) represents a 
measured and appropriate response to the significant undue 
discrimination and other competitive impediments identified in this 
record.
    The other context in which our authority under FPA sections 205 and 
206 is raised is whether permitting a public utility to charge market-
based rates for wholesale electricity sales can continue to be 
justified if the seller or its affiliate owns or operates transmission 
assets that have not been placed under the control of an RTO. The 
Commission has a responsibility under FPA sections 205 and 206 to 
ensure that rates for wholesale power sales are just and reasonable, 
and has found that market-based rates can be just and reasonable where 
the seller has no market power. The Commission has determined that to 
show a lack of market power, the seller and its affiliates must not 
have, or must have adequately mitigated, market power in the generation 
and transmission of electric energy, and cannot erect other barriers to 
entry by potential competitors.166 In the past, the 
Commission has found that an open access transmission tariff mitigated 
transmission market power.167
---------------------------------------------------------------------------

    \166\ See, e.g., Heartland Energy Services, Inc., 68 FERC para. 
61,233 at 62,060 (1994); Louisville Gas & Electric Company, 62 FERC 
para. 61,016 at 61,143-44 (1993) (Heartland). See also Louisiana 
Energy and Power Authority v. FERC, 141 F.3d 364 (D.C. Cir. 1998) 
(court upholds Commission's use of market-based rate authority).
    \167\ See, e.g., Heartland, 68 FERC at 62,061, 62,063-64.
---------------------------------------------------------------------------

    As discussed above, some commenters believe that the Commission 
should insist upon RTO participation as a condition necessary to yield 
competition robust enough to support market-based rates, while others 
argue that we cannot use market-based rate authority to advance 
preferred policies or as a penalty. We are not adopting in this Final 
Rule a generic policy that participation in an RTO is a necessary 
condition to a public utility receiving, or retaining, market-based 
rate authority, nor do we propose to use the denial of market-based 
rate authority as a penalty for not voluntarily complying with this 
Rule. However, we do have an obligation to ensure that rates for 
wholesale power sales are just and reasonable, and we adhere to our 
precedent that market-based rates can be just and reasonable only where 
transmission market power has been mitigated and there are no other 
barriers to entry.
    FPA section 202(a) and PURPA section 205. Section 202(a) of the 
FPA, the authority for which has been delegated to the Commission by 
the Secretary of Energy,168 authorizes and directs the 
Commission ``to divide the country into regional districts for the 
voluntary interconnection and coordination of facilities for the 
generation, transmission, and sale of electric energy.'' The purpose of 
this division into regional districts is for ``assuring an abundant 
supply of electric energy throughout the United States with the 
greatest possible economy and with regard to the proper utilization and 
conservation of natural resources.'' Section 202(a) of the FPA states 
that it is ``the duty of the Commission to promote and encourage such 
interconnection and coordination within each such district and between 
such districts.''
---------------------------------------------------------------------------

    \168\ 63 FR 53889 (Oct. 7, 1998).
---------------------------------------------------------------------------

    Some commenters assert that FPA section 202(a) gives us broad 
authority and discretion to promote RTOs to support an abundant supply 
of electric energy with the greatest possible economy, while others 
contend that the authority is limited by the ``voluntary'' nature of 
the provision. We need not decide the precise confines of section 
202(a) authority here. Clearly, this section gives the Commission the 
authority, after consultation with state commissions, to establish 
boundaries for regional districts for the voluntary interconnection and 
coordination of

[[Page 841]]

facilities in order to assure an abundant supply of electric energy 
with the greatest possible economy. We have decided in this Rule that 
we will exercise this authority, at least in the first instance, by 
allowing transmission owners, in consultation with other interested 
parties and state commissions, to propose to us what they believe to be 
appropriate regional districts. In this regard, we conclude that the 
Commission, pursuant to FPA section 202(a), clearly has the authority 
to direct public utilities as well as non-public utilities 
169 to consider the regional coordination that would result 
from joining an RTO and to participate in Commission-sanctioned RTO 
discussions.
---------------------------------------------------------------------------

    \169\ The legislative history, as well as the Commission's past 
use of section 202(a), indicates that the provision applies to both 
public utilities and non-public utilities. See S. Rep. No. 621, at 
49 (1935) (``public as well as private plants are included''); 
Reliability and Adequacy of Electric Service, Order No. 383, 41 FPC 
846,47 (1969) (information on coordination requested pursuant to 
section 202(a) from public and non-public utilities).
---------------------------------------------------------------------------

    As we are not in this Final Rule mandating any particular 
interconnection or coordination of facilities, we need not address 
whether the language in FPA section 202(a) referring to ``voluntary'' 
interconnection and coordination limits our authority. It is clearly 
the intent and requirement of this section that the Commission 
encourage and promote a regional approach, which is what we are doing 
in this Final Rule.
    Section 205 of PURPA 170 also supports the Commission's 
authority to encourage and promote regional coordination. This section, 
which addresses power pooling, gives the Commission the authority to 
exempt electric utilities from state laws or regulations which prohibit 
or prevent voluntary coordination, and to recommend to electric 
utilities to enter voluntarily into negotiations for pooling 
arrangements where opportunities for conservation, efficiency, and 
increased reliability exist. The Commission has previously interpreted 
section 205 of PURPA as essentially complementing the functions under 
section 202(a).171
---------------------------------------------------------------------------

    \170\ 16 U.S.C. 824a-1.
    \171\ In Public Service Company of New Mexico, 25 FERC para. 
61,469 at 62,038 (1983), the Commission stated that, ``Our mandate 
under PURPA to promote voluntary coordination is similar to that 
exercised by our predecessor, the Federal Power Commission, for more 
than 40 years under Section 202(a) of the Federal Power Act.'' 
Accord Pacific Gas and Electric Company, 38 FERC para. 61,242 at 
61,791 (1987) (PURPA ``reaffirms the Commission's authority to 
promote voluntary coordination of electric utilities'').
---------------------------------------------------------------------------

    FPA Section 203. The Commission has the authority and 
responsibility under section 203 of the FPA to review mergers and other 
transactions involving public utilities, including dispositions of 
jurisdictional facilities by public utilities. There are two aspects of 
this authority that relate to RTO formation. First, public utilities' 
transfers of control of jurisdictional transmission facilities to 
entities such as RTOs would require section 203 approval. Under section 
203 of the FPA, the Commission must approve a proposed disposition of 
jurisdictional facilities if it is consistent with the public interest.
    Second, the Commission may grant an application under section 203 
upon such terms and conditions as it finds necessary to secure the 
maintenance of adequate service and the coordination in the public 
interest of jurisdictional facilities. FPA section 203(b) explicitly 
gives the Commission authority to condition a public utility's proposed 
disposition of jurisdictional assets ``upon such terms and conditions 
as it finds necessary or appropriate to secure the maintenance of 
adequate service and the coordination in the public interest of 
facilities subject to the jurisdiction of the Commission.'' Thus, for 
instance, the Commission has used section 203 conditioning authority to 
require that all mergers be conditioned on the offer of comparable open 
access transmission.172 In the Commission's Merger Policy 
Statement, it was recognized that the development of fully competitive 
generation markets is in the public interest and that turning over 
control of transmission assets to an ISO might be an appropriate remedy 
for anticompetitive effects of a merger.173
---------------------------------------------------------------------------

    \172\ El Paso Electric Company and South West Services, 68 FERC 
para. 61,181 at 61,914-15 (1994), dismissed, 72 FERC para. 61,292 
(1995).
    \173\ Inquiry Concerning the Commission's Merger Policy Under 
The Federal Power Act, 61 FR 68595 (Dec. 30, 1996), FERC Stats. & 
Regs. para. 31,044 at 30,115, 30,121, 30,137 (1996).
---------------------------------------------------------------------------

    Some commenters urge the Commission to make RTO participation a 
standardized condition to all mergers in order to mitigate increased 
generation and transmission concentration, while others claim that RTO 
imposition as a section 203 condition would require specific findings 
in a particular case. We do not find as a generic matter in this 
proceeding that no merger could be consistent with the public interest 
in the absence of RTO participation. However, as noted in the Merger 
Policy Statement with respect to ISOs, turning control of transmission 
assets over to an RTO might be an appropriate remedy for the 
anticompetitive effects of a merger. In general, our processing of 
merger applications can be facilitated to the extent the merging 
parties have resolved potential anticompetitive issues through means 
such as RTO participation.
    Other Legal Issues. Commenters have suggested other statutory 
authorities that may be relevant to our efforts to encourage RTOs. 
These include FPA section 207, which upon state commission complaint 
authorizes the Commission to remedy inadequate or insufficient 
interstate service; FPA sections 202(b) and 210, which address the 
Commission's authority to order interconnections and make effective an 
interconnection; FPA section 209, which authorizes the Commission to 
refer matters to joint boards composed of Commission and state 
representatives; and FPA sections 211 and 212, which address the 
Commission's authority to require transmission services. We agree that, 
under appropriate circumstances, these authorities may indeed be 
relevant to RTO formation. However, we do not, and need not, rely upon 
them for what we are requiring in this Final Rule, so we will not 
address here what authority they might confer.
    In response to those commenters who assert that the Northern States 
\174\ court decision somehow limits our authority with respect to RTOs, 
we disagree. As reflected in our recently issued order on remand \175\ 
of the Northern States court decision, that decision addresses narrow 
circumstances involving transmission curtailment where the third-party 
transmission customer has redispatch options. We do not interpret the 
decision as limiting our authority to encourage or require RTO 
participation. Moreover, we note that formation of RTOs is likely to 
eliminate or significantly reduce the potential for the type of 
conflict encountered in Northern States.
---------------------------------------------------------------------------

    \174\ See Northern States, supra note 89.
    \175\ Northern States Power Co. (Minnesota) and Northern States 
Power Co. (Wisconsin), 89 FERC para. 61,178 (1999).
---------------------------------------------------------------------------

    With respect to the commenter seeking clarification of the 
authorities we are relying upon to require the filings we are mandating 
in this Rule, we clarify that we are relying upon the authorities 
contained in FPA sections 202(a), 304, 307, and 309 for the filings we 
are requiring under new sections 35.34(c) and (g). To the extent a 
public utility proposes to participate in an RTO, we will process that 
application pursuant to FPA sections 203, 205 or other sections as 
appropriate.

D. Minimum Characteristics of an RTO

    In the NOPR, we proposed minimum characteristics and functions for 
a transmission entity to qualify as an

[[Page 842]]

RTO. These characteristics and functions are designed to ensure that 
any RTO will be independent and able to provide reliable, non-
discriminatory and efficiently priced transmission service to support 
competitive regional bulk power markets. In the section that follows, 
we discuss the four minimum characteristics for an RTO, which are:
    (1) Independence from market participants;
    (2) Appropriate scope and regional configuration;
    (3) Possession of operational authority for all transmission 
facilities under the RTO's control; and
    (4) Exclusive authority to maintain short-term reliability.
    In our discussion below, we clarify and revise to some extent our 
discussion in the NOPR, but we affirm these as the minimum 
characteristics of an RTO.
1. Independence (Characteristic 1)
    As a first required characteristic, the Commission stated that all 
RTOs must be independent of market participants. To achieve 
independence, we proposed that RTOs must satisfy three conditions. 
First, the RTO, its employees, and any non-stakeholder directors must 
not have any financial interests in any market participants.\176\ 
Second, the RTO must have a decision-making process that is independent 
of control by any market participant or class of participants.\177\ The 
NOPR defined market participant as any entity or its affiliate that 
buys or sells electric energy in the RTO's region or in any neighboring 
region that might be affected by the RTO's actions. We said that this 
second condition would be judged on a case-by-case basis. However, the 
Commission also proposed, by way of example, that an RTO could satisfy 
this second condition with (a) a non-stakeholder governing board and 
(b) a prohibition on market participants having more than a de minimis 
(one percent) ownership interest in the RTO. Third, the RTO must have 
exclusive and independent authority to file changes to its transmission 
tariff with the Commission under section 205 of the FPA.\178\
---------------------------------------------------------------------------

    \176\ FERC Stats. & Regs. para. 32,541 at 33,726.
    \177\ Id. at 33,727.
    \178\Id. at 33,729.
---------------------------------------------------------------------------

    Comments. A large number of commenters address different facets of 
the independence characteristic. To make the summary of comments more 
manageable, we grouped the comments by key sub-issues: the basic 
principle; who is a market participant; RTO economic interests in 
market participants and energy markets; voting interests of one market 
participant and affiliates; voting interests of classes of market 
participants; passive ownership interests; RTO governing boards; role 
of state agencies; and section 205 filing rights.
    The Basic Independence Principle. In the NOPR, the Commission 
reiterated its earlier statement that ``the principle of independence 
is the bedrock upon which the ISO must be built'' and that this 
standard should apply to all RTOs, whether they are ISOs, transcos or 
variants of the two.\179\ Virtually all commenters agree with this 
principle. For example, EEI states that ``[a] decisionmaking process 
independent of the control of any market participant or class of market 
participants should be an important aspect of the independence 
principle.'' \180\ The TDU Systems say that ``[f]ull independence is 
vitally important to the success of RTOs * * * and cannot be safely 
compromised.'' \181\ The Nine Commissions urge that RTOs must be 
``truly independent of market participants in word, deed and 
appearance.'' \182\ Despite the almost unanimous acceptance of the 
principle, there are fundamental disagreements (discussed in later 
sections) among commenters as to how the principle should be 
implemented, especially for RTOs that would operate as stand alone, 
for-profit transcos.
---------------------------------------------------------------------------

    \179\ Id. at 33,726.
    \180\ EEI at 25.
    \181\ TDU Systems at 41.
    \182\ Nine Commissions at 8.
---------------------------------------------------------------------------

    Some commenters question whether complete independence comes at too 
high a cost. For example, FP&L recommends that the Commission ``not 
consider independence in a vacuum.'' It contends that ``it would make 
little sense to trade off the greatest degree of independence for the 
highest cost structure.'' \183\ Salomon Smith Barney makes a similar 
point. It contends that strict application of the independence standard 
could thwart the development of for-profit RTOs. Therefore, it urges 
the Commission ``not to promulgate rules that maintain absolute purity 
but also throttle the * * * voluntary formation of RTOs.'' \184\ 
Konoglie/Ford/Fleishman, three individuals from the financial 
community, express concern that independence will usually be 
interpreted to mean a separation between ownership and control as 
currently practiced in ISOs. They argue that, if the ISO model becomes 
the norm, it could lead to higher capital costs because those who own 
the transmission assets would not be able to make basic investment and 
operating decisions. They point out that ownership usually imparts 
control in most U.S. industries and that transmission operating and 
investment efficiencies are unlikely to be achieved unless this becomes 
the norm in a restructured U.S. electricity industry.
---------------------------------------------------------------------------

    \183\ FP&L at 32.
    \184\ Salomon Smith Barney at 5.
---------------------------------------------------------------------------

    PJM and WEPCO contend that a for-profit transmission company can 
never be independent because it will always be biased in its operating 
and investment decisions. Specifically, they assert that a for-profit 
transco will always be biased toward transmission solutions over other 
solutions (such as generation redispatch) and its own transmission 
assets over transmission assets owned by others. WEPCO, therefore, 
concludes that independence can be achieved only if there is an ISO 
operating over a for-profit transmission company.\185\
---------------------------------------------------------------------------

    \185\ WEPCO at 9.
---------------------------------------------------------------------------

    Other commenters argue that it would be naive to believe that 
independence, by itself, will lead to an effective RTO. They argue that 
an RTO may be completely independent but it must also have sufficient 
operational and decisionmaking authority if it is to be effective. For 
example, the TDU Systems assert that independence will not be 
sufficient if transmission owners attempt to reserve certain decisions 
for themselves. It points to the transco proposals of the Entergy and 
the Alliance Companies as examples of a proposed RTO having 
insufficient decisionmaking authority. NECPUC, representing six New 
England commissions, argues that an RTO must have independent funding 
and urges the Commission to include this as an explicit requirement in 
the final rule. NCPA states that an RTO will not be truly independent 
unless it is able to make and implement independent procurement 
decisions.
    Who Is a Market Participant? There is substantial disagreement 
among commenters about the proposed definition of market participant. 
Some commenters argue that it should be expanded; others contend that 
it should be narrowed. In the first group, Illinois Commission urges us 
to expand the definition of a stakeholder because ``[a] market interest 
can arise through functions and activities other than just buying or 
selling electricity.'' \186\ Enron/APX/Coral Power echo this point and 
contend that an RTO should ``not be subject to control by, and has no 
interest in the success of any vendor or buyer in the competitive 
functions of the

[[Page 843]]

industry.'' \187\ Duke recommends expanding the definition to include 
``any distribution company or neighboring transmission company and/or 
any buyer or seller of ancillary services.'' \188\ PJM urges that the 
definition of a market participant include any entity that owns 
transmission facilities or provides or buys transmission service.\189\
---------------------------------------------------------------------------

    \186\ Illinois Commission at 29.
    \187\ Enron/APX/Coral Power at 8.
    \188\ See Duke Power at 27. See also Midwest Municipals, Avista 
and American Forest.
    \189\ United Illuminating disagrees. It asserts that 
``transmission owners without power marketing interests'' should not 
be considered as market participants. United Illuminating at 37.
---------------------------------------------------------------------------

    TAPS, representing an informal group of transmission dependent 
utilities in 24 states, also urges us to adopt a broad definition of 
market participant to ensure RTO neutrality. It argues that millions of 
dollars of investments and operating costs will be affected by RTO 
decisions. It gives several examples of how RTO decisions can have 
major economic impacts. As a transmission planner, an RTO will have 
substantial responsibility for routing new transmission lines. 
Depending on its decisions, it can help or hurt one gas pipeline or 
another or one generator or another. As a transmission tariff 
administrator, it will have significant discretion in choosing how to 
price congestion. Any decision that it makes (e.g., zonal versus nodal 
pricing) could have significant impacts on the profitability of 
particular generators. As the supplier of last resort for ancillary 
services, it will have considerable discretion in defining the types 
and quantities of ancillary services that are needed. Depending on its 
decisions, some generators ``will win, and others will lose.'' \190\ 
Finally, as the ``transmission-request gatekeeper,'' it will have 
substantial influence on who gets service and on what terms. To ensure 
both the appearance and reality of neutrality in these various 
decisions, TAPS urges us to adopt a broad definition of market 
participant.
---------------------------------------------------------------------------

    \190\ TAPS at 63.
---------------------------------------------------------------------------

    In contrast, others contend that the proposed definition is too 
broad. CP&L states that a literal application of the proposed 
definition ``would make every single residential, commercial, 
industrial and wholesale electric customer (and all of their 
affiliates) market participants.'' \191\ It recommends that the 
definition be narrowed by changing it to ``those entities that are 
active in wholesale and non-regulated retail power markets using 
transmission of the RTO.'' \192\ LPPC asks that the Commission define 
the term ``affiliate'' because it is not defined anywhere in the NOPR. 
It also suggests that the definition of affiliate be limited to 
``common control'' rather than using the five-percent ownership 
interest standard of PUHCA.\193\
---------------------------------------------------------------------------

    \191\ CP&L at 23-24. American Forest believes that ``the 
Commission did not intend such a broad exclusion, and seeks 
clarification on this point.'' American Forest at 4.
    \192\ CP&L at 23-24.
    \193\ LPPC points out that the term ``affiliate'' is used in 
defining market participant but is not defined anywhere in the 
proposed rule.
---------------------------------------------------------------------------

    A number of commenters focus specifically on the question of 
whether a ``distribution only'' entity (i.e., an entity that performs 
the sole function of transporting electricity at distribution voltages) 
should be considered a market participant. Montana Power urges us 
against expanding the definition to include an entity that operates 
``distribution-only facilities.'' It argues that an RTO and a 
distribution entity are both ``delivery entities'' and efficiencies can 
be gained by having one entity provide ``total delivery service'' from 
high to low voltages. These efficiencies of vertical integration could 
include the savings that would result from having maintenance performed 
on both transmission and distribution facilities by the same crews, the 
sharing of shop and warehouse space and the sharing of various 
administrative support functions. Sierra Pacific generally supports 
this view and asserts that it does not believe that a ``transmission 
owner could so operate its facilities to materially assist affiliated 
transmission and distribution interests to the disadvantage of 
unaffiliated entities.'' 194
---------------------------------------------------------------------------

    \194\ Sierra Pacific at 17.
---------------------------------------------------------------------------

    Salomon Smith Barney takes a more cautious view. It states that an 
RTO owned by distribution entities ``could manipulate the grid to favor 
their customers over the customers of other distributors.'' 
195 Trans-Elect argues that the Commission's recent attempt 
to impose non-discriminatory curtailment procedures on all users of the 
grid in the NSP service territory demonstrates that this problem 
already exists.196 Arguing that it would be undesirable to 
lose distribution entities as potential investors in RTOs, Salomon 
Smith Barney recommends that the Commission require RTOs to follow 
market-based priority rules in curtailment situations to reduce the 
likelihood that an RTO would favor affiliated distribution entities.
---------------------------------------------------------------------------

    \195\ Salomon Smith Barney at 5.
    \196\ Trans-Elect at 5 citing Northern States Power Co. v. FERC, 
176 F.3d 1090 (8th Cir. 1999).
---------------------------------------------------------------------------

    Both Sierra Pacific and NEPCO et al. raise concerns about the 
interaction of the market participant definition and ``state-mandated 
backstop power supply obligations.'' NEPCO et al. asserts that all 23 
states that have opted for retail competition to date have usually 
imposed a default supplier obligation (which also is referred to as a 
``standard offer supplier'' or a `` provider of last resort'' 
obligation) on one party which is usually the incumbent provider. 
Sierra Pacific notes that the nature and duration of this mandated 
obligation varies from state-to-state ``but at least some of the 
programs are structured so that the POLR [provider of last resort] does 
not compete for new customers and has no incentive to retain existing 
POLR customers.'' 197 Both commenters argue that providers 
of last resort should not automatically be considered as market 
participants, even though they buy and sell electricity, because this 
would reduce the pool of potential transco investors. Sierra Pacific 
states that the Commission should ``leave the door open to consider the 
POLR issue on a case-by-case basis'' and that the final regulations 
should explicitly say that a provider of last resort would not be 
deemed a market participant if its state mandated obligation gives it 
no incentive to make such sales.198
---------------------------------------------------------------------------

    \197\ Sierra Pacific at 16.
    \198\ Id.
---------------------------------------------------------------------------

    Finally, NEPCO et al. raises the issue of incumbent utilities that 
have tried to divest themselves of their generating assets but have not 
yet succeeded. It points to its difficulties in divesting its minority 
ownership interests in nuclear plants. It requests that an entity not 
be automatically deemed a market participant because of these minority 
ownership interests especially if it has taken actions to eliminate its 
control over the retained ownership interest (e.g., through a long-term 
contract that would give marketing rights to a non-affiliated entity).
    RTO Economic Interests in Market Participants and Energy Markets. 
Many commenters, representing a wide range of industry constituencies, 
agree with the NOPR's proposal that the RTO, its employees and any non-
stakeholder directors must not have any financial interests in 
electricity market participants.199 Duke recommends that, 
where divestment is required, the Commission should continue its past 
practice of allowing employees to divest personal investments in a 
manner that

[[Page 844]]

does not cause them significant financial harm.
---------------------------------------------------------------------------

    \199\ One exception is Salomon Smith Barney. It argues that this 
requirement is ``altogether unreasonable, in that it could require 
the most qualified directors and employees to dispose of mutual 
funds, pension plans and old investments whose tax base makes 
disposition unreasonable.'' Salomon Smith Barney at 3.
---------------------------------------------------------------------------

    Most commenters agree that the focus should be on current financial 
interests.200 Several commenters point out that it would be 
virtually impossible for an RTO to hire knowledgeable and experienced 
employees if the Commission were to require no past financial 
connections to market participants. They assert that some of the most 
knowledgeable candidates for RTO positions, at least in an RTO's early 
years of operation, are likely to be individuals who have retired from 
companies that are market participants and it is likely that these 
individuals will be receiving pensions from their former employers. In 
situations like this, NASUCA urges the Commission to ``exclude from 
this prohibition * * * employee pension plans and other post-employment 
benefits received while a former employee of a market participant.'' 
201 Others urge that the Commission follow the precedent 
that was established in the Midwest ISO decision.202 
Individuals would not be automatically excluded from RTO employment or 
directorships if their pension does not directly depend on the economic 
performance of their former employers (e.g., a defined benefit pension 
plan). TDU Systems suggests that reasonable exceptions should be made 
``in the case of defined benefit pension plans, general mutual funds 
(as opposed to utility/energy sector funds) that hold stock or bonds of 
market participants, or other similar financial holdings where the 
holder cannot direct specific investments or benefit directly from 
stock performance.'' 203
---------------------------------------------------------------------------

    \200\ With respect to future financial interests, Salomon Smith 
Barney states that ``[p]rivate enterprises do not normally, control 
the lives of their ex-employees.'' Salomon Smith Barney at 3.
    \201\ NASUCA at 17.
    \202\ See Midwest Independent System Operator, 85 FERC para. 
61,250 (1998). See also Southern Company, Duke, TDU Systems and 
Avista.
    \203\ TDU Systems at 39.
---------------------------------------------------------------------------

    In the NOPR, we asked whether there was a need to ``define the 
financial independence requirement in more specific terms.'' 
204 The answer from almost all respondents was ``no.'' For 
example, TDU Systems recommend that we issue a general rule with a set 
of guidelines and then allow for its application on a case-by-case 
basis. Avista agrees and states that any financial independence 
standard ``require[s] case-by-case consideration as well as the common 
sense application of the rule of reason.'' 205 PJM/NEPOOL 
Customers states that RTOs will have the benefit of the conflict of 
interest standards that have been drafted for each of the functioning 
ISOs. They also recommend that the Commission commence a separate 
rulemaking on this issue.
---------------------------------------------------------------------------

    \204\ FERC Stats. & Regs. para. 32,541 at 33,727.
    \205\ Avista at 11.
---------------------------------------------------------------------------

    Some commenters contend that the NOPR's treatment of financial 
independence is too narrowly drawn. For example, Dynegy argues that 
while ISOs ``may ostensibly be independent of market participants--they 
are not independent of the market itself.'' 206 As evidence 
of this phenomenon, it points to instances when the California ISO has 
tried to impose price caps on energy prices. EPSA expresses a similar 
view and points to the price caps proposed by ISO New England and 
approved by this Commission during the June 1999 heat wave, when energy 
prices reached $1,600 a megawatt-hour, as another example of 
undesirable and inappropriate intervention by a transmission provider 
in energy markets. In crafting a definition of independence, EPSA urges 
the Commission to require that RTOs ``should be indifferent to the 
price at which the commodity they transport clears the market.'' 
207
---------------------------------------------------------------------------

    \206\ Dynegy at 35.
    \207\ EPSA Reply Comments at 12.
---------------------------------------------------------------------------

    Others argue that this conflict is unavoidable as long as the 
Commission imposes a requirement that RTOs be the supplier of last 
resort for certain ancillary services.208 According to these 
commenters, this obligation will often require that the RTO be a buyer 
in certain ancillary service markets. If the supplier of last resort 
obligation is also combined with a requirement that the RTO buy 
efficiently, then it is inevitable that the RTO will be interested in 
whether the prices are high or low (i.e., it is no longer simply a 
disinterested market operator).
---------------------------------------------------------------------------

    \208\ See NEMA at 19. See also EPSA Reply Comments.
---------------------------------------------------------------------------

    Active (Voting) Ownership Interests in the RTO. a. By Individual 
Market Participants and Their Affiliates. A number of commenters oppose 
a one-percent cap on allowed voting interests of market participants in 
RTOs as a necessary requirement for achieving 
independence.209 EEI states that such a cap is not 
``necessary, rational or supportable'' for achieving the goal of 
independence.210 It recommends that the Commission allow 
market participants or their affiliates to own up to ten-percent voting 
interests in RTOs. EEI also asks for a clarification of whether an 
ownership restriction would ``apply only to ownership in the RTO itself 
or does it also apply to ownership interests in the transmission 
facilities under the operational control of the RTO.'' 211 
PJM, which is organized as a non-profit limited liability corporation 
(LLC), asks the Commission to clarify whether its ``members'' would be 
considered owners.
---------------------------------------------------------------------------

    \209\ See, e.g., EEI, Duke, CP&L and PacifiCorp.
    \210\ EEI notes that the NOPR mentions the one percent cap on 
voting interests by market participants in the National Grid Company 
in England and Wales but observes that there was no obvious 
justification given at the time the decision was made.
    \211\ EEI at 26.
---------------------------------------------------------------------------

    CTA also argues for a higher cap. It states that the NOPR's 
emphasis on ownership is misplaced. Instead, the Commission should be 
concerned with the ``actual control over the day-to-day affairs of the 
system, not some arbitrary percent ownership test.'' 212 The 
Alliance Companies express the concern that, even though the one 
percent cap appears to have been proposed as a ``safe harbor,'' it 
could quickly become ``the only port of entry to Commission approval.'' 
213
---------------------------------------------------------------------------

    \212\ CTA at 4.
    \213\ Alliance Companies at 18.
---------------------------------------------------------------------------

    EEI observes that other government agencies allow five or ten 
percent ownership in voting shares before assuming that these ownership 
interests conveyed control.214 For example, it notes that 
the SEC definition of an ``affiliate'' under PUHCA is limited to 
entities that own or control more than five percent of the voting stock 
of a public utility. It also observes that this Commission, in 
determining whether a company is an affiliate of a natural gas pipeline 
or an electric utility, applies a rebuttable presumption of control 
only when a utility owns ten percent or more of a company's voting 
stock. Entergy states that ``there do not appear to be instances under 
U.S. law where one-percent ownership is considered to give rise to a 
risk of control.'' 215
---------------------------------------------------------------------------

    \214\ Most investor-owned utilities agree with EEI. An exception 
is Cinergy which urges the Commission to incorporate the one-percent 
ownership standard in the final regulations ``exactly as proposed'' 
because such a prohibition ``is vital to preserving a RTO's 
financial independence characteristic.'' Cinergy at 17.
    \215\ Entergy at 28.
---------------------------------------------------------------------------

    Several commenters question why there should be any limits on the 
amount of voting shares that can be held by a market participant. For 
example, Allegheny asserts that ``[t]he desire to maintain or obtain 
ownership of transmission assets by market participants should not be 
regarded as an evil to be avoided at all costs.'' 216 FP&L 
states that there is no need to

[[Page 845]]

prohibit affiliated transcos.217 It argues that the 
Commission should allow 100-percent ownership of voting equity and 
ensure non-discriminatory transmission access through codes of conduct 
and state commission oversight, in the case of a single state RTO. It 
observes that ``in the natural gas industry there are numerous transcos 
(pipelines) that are affiliated with gas producers, marketers and/or 
distribution companies and there is no basis to conclude that this 
structure would be less likely to succeed in the electric power 
industry.'' 218
---------------------------------------------------------------------------

    \216\ Allegheny Reply Comments at 10.
    \217\ In contrast, APPA states that affiliated transcos should 
be allowed ``only where such private companies operate under the 
direct, ongoing supervision of a strong, fully functional regional 
Independent System Operator.'' APPA at 28.
    \218\ FP&L at 26.
---------------------------------------------------------------------------

    Other commenters disagree and urge the Commission to adopt even 
stricter standards on ownership than those presented in the 
NOPR.219 For example, APPA recommends that the final rule 
prohibit any ownership interests in RTOs by market 
participants.220 APPA states that even a one-percent 
ownership would represent an unjustifiable and unnecessary exception to 
the independence standard. South Carolina Authority agrees with APPA 
and argues that the NOPR failed to present a ``public policy benefit'' 
for allowing even a de minimis ownership interest.221 NASUCA 
also shares this view. In addition, it asserts that as soon as the 
Commission allows any ownership by market participants it will be 
forced to continually track the share of each market participant, 
including affiliates. NASUCA argues that this would be ``time-
consuming, difficult and expensive'' and would represent the very 
antithesis of the independent, lightly regulated structure that the 
Commission wished to foster.
---------------------------------------------------------------------------

    \219\ See, e.g., Midwest Municipals, APPA, TDU Systems and 
Industrial Consumers.
    \220\ APPA clarifies that it does not oppose market participants 
owning ``for-profit'' transcos if the transcos come under the 
supervision of strong fully functional ISOs. Industrial Consumers 
recommend that a one-percent cap should be adopted in the final rule 
as a general requirement rather than as a possible safe harbor. In 
addition, it recommends that the cap be calculated on a corporate-
wide basis to avoid the situation of multiple affiliates each with a 
one-percent interest. See Industrial Consumers at 30.
    \221\ See South Carolina Authority at 18.
---------------------------------------------------------------------------

    TDU Systems concurs and observes that any ownership by market 
participants will trigger the ``chasing after conduct'' regulation that 
the Commission said it hoped to avoid.222
---------------------------------------------------------------------------

    \222\ TDU Systems at 41 citing FERC Stats. and Regs. para. 
32,541 at 31,145.
---------------------------------------------------------------------------

    In addition, TDU Systems criticizes EEI's ten percent proposal. TDU 
Systems asserts that EEI fails to understand the rationale for the 
``safe harbor'' proposal in the NOPR. TDU Systems argues that the 
regulatory purpose of a ``safe harbor'' is to ensure that ``no case-by-
case review of the regulatory agency is required.'' 223 
Therefore, TDU Systems contends that it would be inappropriate to adopt 
EEI's proposed ten percent because this percentage is not in the ``safe 
harbor'' but, as recognized by other regulatory agencies, raises a 
clear risk of control. Consumer Groups supports this view and points to 
one case in which a court decided that a three-percent ownership 
interest of a company's common stock was found to be ``sufficient to 
assert control over the corporation because the ownership of the other 
common shares was widely dispersed.'' 224
---------------------------------------------------------------------------

    \223\ TDU Systems Reply Comments at 14 (italicized in the 
original).
    \224\ Consumer Groups Reply Comments at 8.
---------------------------------------------------------------------------

    The Alliance Companies, who support a ceiling of five percent 
ownership in voting interests by market participants, state that they 
``are aware of no practical means of tracking who has an ownership 
interest at a threshold of less than five percent `` because SEC 
regulations require reporting of ownership in publicly traded companies 
only at five-percent ownership and above. In contrast, Cinergy asserts 
that enforcing a lower ownership limit should not be a problem. It 
states that the Commission could keep track of ownership interests 
``through transmission owners'' representations and subsequent audits 
if the need arises.'' 225
---------------------------------------------------------------------------

    \225\ Cinergy at 18.
---------------------------------------------------------------------------

    APPA, which argues for absolute and total prohibition on voting 
ownership by market participants, asserts that even with access to SEC 
data it will be difficult for the Commission to keep track of who 
really owns voting shares since they are often registered in ``street'' 
names. Therefore, it urges the Commission to impose a total prohibition 
on ownership by market participants. South Carolina Authority agrees 
and further argues that anything less would fail to achieve the 
Commission's characterization of an RTO as entity in which ``the 
control of transmission operation is cleanly separated from power 
market participants.'' 226 It concludes that ``[t]here is 
nothing `clean' about permitting incumbent transmission owners to 
indefinitely maintain an ownership interest, voting or otherwise, in 
the newly created RTO.'' 227
---------------------------------------------------------------------------

    \226\ South Carolina Authority at 8 (quoting from FERC Stats. & 
Regs. para. 32,541 at 33,718 (emphasis added by the quoter)).
    \227\ South Carolina Authority at 14.
---------------------------------------------------------------------------

    EPSA suggests a compromise that would allow greater flexibility 
with respect to initial ownership interests. It proposes that the 
Commission establish time limits on voting ownership. TDU Systems makes 
a similar recommendation with respect to passive ownership. While TDU 
Systems states that it would prefer an absolute prohibition on market 
participants owning voting shares, it suggests that the Commission 
might consider allowing transmission owners to ``hold passive, non-
voting ownership interests in excess of one percent as an extraordinary 
transition measure.'' 228 However, TDU Systems recommends 
that such interests be reduced to one percent or below in a 
``relatively short period of time.''
---------------------------------------------------------------------------

    \228\ TDU Systems at 42.
---------------------------------------------------------------------------

    b. By Classes of Market Participants. SRP asserts that the NOPR is 
flawed because it is not sufficient to place a limitation on the 
ownership interests that can be held by a single participant and its 
affiliates while ignoring the possibility that other owners may have 
similar interests. SRP urges the Commission to recognize that ``[a]n 
interest that may be considered de minimis, when viewed in isolation, 
could still result in effective control when aggregated for a group 
with common interests.'' \229\ Therefore, it recommends that limits be 
placed not only on the ownership interests of an individual market 
participant but also on the ownership interests by other market 
participants with similar economic interests. SRP does not recommend a 
specific percentage for a group cap, but Industrial Consumers urge the 
Commission to cap the voting interests of any group at five percent.
---------------------------------------------------------------------------

    \229\ Salt River at 11. United Illuminating agrees and states 
that if the Commission ``were to adopt a higher de minimis standard, 
such as five or ten percent ownership interest, it would be 
relatively easy for five or six market participants owning such 
percentages to control the operations of an RTO.'' United 
Illuminating at 39-40.
---------------------------------------------------------------------------

    FP&L contends that there is no need for ownership caps for a group 
of market participants because they will often have conflicting 
economic interests. It gives the example of a group of transmission 
owners with ownership interests in an RTO who also own affiliated power 
marketers. FP&L argues these marketing affiliates will compete against 
each other and this rivalry will mitigate the potential for collusion 
among the parent companies that jointly own the RTO. Alliance Companies 
agree with this view. They assert that ``[i]n today's competitive power 
markets, all market participants, including those traditionally 
classified within the same

[[Page 846]]

stakeholder group are likely to be competitors'' and, therefore, that 
it is unlikely that there will be a ``nexus of interest.'' \230\
---------------------------------------------------------------------------

    \230\ Alliance Companies at 21-22.
---------------------------------------------------------------------------

    EEI argues that ownership caps on groups of market participants 
would be ``impractical and extremely burdensome on Commission 
resources'' because the Commission would have to keep track of 
ownership levels by every market participant and also align market 
participants into specific groups with ``alleged common interests.'' 
\231\ In addition, it contends that this task would be difficult to do 
because markets are evolving and the business objectives of individual 
firms will change as they buy or sell assets. Moreover, while accepting 
that ``some market participants may have common interests at certain 
times'' EEI believes that such ``coalitions'' would be ``fragile, 
short-lived and unlikely to result in a serious threat to the 
independence of the RTO.'' \232\
---------------------------------------------------------------------------

    \231\ EEI Reply Comments at 21.
    \232\ Id.
---------------------------------------------------------------------------

    A number of commenters assert that a cap on voting interests will 
thwart capital formation in new and existing transmission facilities. 
For example, UtiliCorp contends that such a cap ``may potentially choke 
off significant sources of capital'' for the formation of for-profit 
transcos.\233\ Various commenters from the financial community argue 
that such a cap would make it difficult to create RTOs that function as 
for-profit transcos. Salomon Smith Barney states that current owners of 
transmission assets need to retain a larger ownership interest, at 
least for a transition period, in order to avoid heavy capital gains 
taxes. It estimates that many current transmission owners would have to 
pay capital gains taxes on about 35 to 50 percent of the current book 
value of their transmission assets if they were to sell these assets.
---------------------------------------------------------------------------

    \233\ UtiliCorp at 7.
---------------------------------------------------------------------------

    Alliance Companies asserts that restrictions on ownership would 
reduce the potential pool of investors (i.e., buyers of transmission 
assets) and therefore reduce the price that current owners could 
receive for their assets. They contend that this would be especially 
damaging because it would place limits on ownership by ``those entities 
that are most likely to understand the potential value of the business 
model.'' \234\ Alliance Companies states that the Commission should 
allow five-percent individual ownership interests by industry 
participants because this will provide confidence to other, non-energy 
industry investors that the transco will be a financial success.\235\ 
In general, the Alliance Companies and other commenters that share this 
view take the position that a one-percent cap for market participants 
will be a major impediment to the creation of for-profit transcos and 
that the de facto effect of such a cap will be to limit the industry to 
the ISO model.
---------------------------------------------------------------------------

    \234\ Alliance Companies at 19.
    \235\ In contrast, APPA asserts that ``if the underlying 
business model is sound, investors will come.'' APPA at 36.
---------------------------------------------------------------------------

    Passive (Non-Voting) Ownership Interests in the RTO. A number of 
privately-owned utilities stress that the final rule must distinguish 
between passive and voting interests in RTOs.\236\ For example, while 
EEI is willing to accept a ten-percent cap on ownership of voting 
interests by individual market participants, it states that ``[t]here 
should be no limit on the amount of passive ownership interest'' 
because ``[p]assive owners who lack voting rights have no ability to 
control the firm.'' \237\ Enron/APX/Coral Power also support this 
position. They urge the Commission to ``explicitly and unambiguously 
allow incumbent utilities and other power industry participants to 
possess passive but not controlling ownership interests in an RTO.'' 
\238\ Southern Company states that ``[p]assive ownership of 
transmission facilities--even up to 100 percent--should not be a 
concern.'' \239\ United Illuminating, while recommending that the 
Commission allow passive ownership, recommends that we should not issue 
generic rules because passive ownership is a ``complex matter that must 
be reviewed on a case-by-case basis.'' \240\
---------------------------------------------------------------------------

    \236\ See, e.g., EEI, Enron/APX/Coral Power and UtiliCorp.
    \237\ EEI at 26. EEI relies on a legal memorandum that concludes 
that passive ownership interests are ``necessarily permissible, no 
matter how large and no matter what other interests they are 
combined with.'' EEI Appendix H at 17.
    \238\ Enron/APX/Coral Power at 14.
    \239\ Southern Company at 42.
    \240\ United Illuminating at 7.
---------------------------------------------------------------------------

    EEI contends that some of the opposition to passive ownership by 
market participants may simply reflect a misunderstanding of the 
fiduciary responsibilities that the board of a for-profit transco has 
to its passive owners. EEI asserts that, under Delaware law and various 
model statutes, the fiduciary responsibilities of a for-profit transco 
board, its managers and owners that hold voting rights to a passive 
owner are limited to maximizing the value of the transmission assets 
and ``not the value of any other assets that may be held by the passive 
owner.'' \241\ According to EEI, a transco board has no fiduciary 
obligation to take actions to produce economic benefits for other 
assets such as generating units that happen to be owned by its passive 
owners. Entergy states that if there are any lingering doubts about the 
fiduciary obligation of the board and its voting members, a provision 
could be inserted in the ``transco's limited liability agreement that 
specifically directed that managers would have no fiduciary duty to 
consider the private interests of members'' and that such a provision 
would be enforceable under Delaware law.\242\
---------------------------------------------------------------------------

    \241\ EEI at 26.
    \242\ Entergy at 29.
---------------------------------------------------------------------------

    Consumer Groups, however, questions the legal feasibility of this 
approach. It cites to several law review articles which it argues raise 
doubts as to whether fiduciary duties assigned by a state law to the 
directors of a subsidiary corporation can be removed by private 
agreement. It also cautions the Commission not to get lost in ``a 
lawyer's duel over conflicting citations about the treatment of passive 
and affiliated ownership interests'' when the fundamental issue is the 
need to safeguard independence and ``avoid any appearance of 
partiality.'' \243\
---------------------------------------------------------------------------

    \243\ Consumer Groups Reply Comments at 9.
---------------------------------------------------------------------------

    EEI points to our recent decision in Entergy Services, Inc., as 
demonstrating that the Commission recognizes that passive ownership is 
not inconsistent with the independence principle under the ISO 
principles of Order No. 888.\244\ It asks that the Commission reach the 
same policy conclusion for any similar independence requirement in the 
final RTO rule. In contrast, the South Carolina Authority observes that 
while the Entergy decision could be read to imply that the Commission 
has ``prejudged this issue,'' the Commission should now use the 
opportunity of this NOPR to take another look at the issue.\245\
---------------------------------------------------------------------------

    \244\ EEI at 26 citing Entergy Services, Inc., 88 FERC para. 
61,149 (1999).
    \245\ South Carolina Authority at 22.
---------------------------------------------------------------------------

    EEI also points to actions or policies taken by other federal 
regulatory agencies that it argues support its contention that passive 
ownership does not necessarily convey control. It observes that the 
definitions of ``holding company,'' ``affiliate'' and ``subsidiary 
company'' in PUHCA are all tied to ownership of voting rather than non-
voting shares. Similarly, EEI states that the FCC ``attribution rules'' 
used to determine when broadcasters and cable companies own or control 
another

[[Page 847]]

broadcaster or cable company are keyed to voting rather than passive 
ownership interests. According to EEI, these policies demonstrate that 
other federal regulatory agencies do not believe that passive ownership 
conveys control and that the Commission should adopt a similar policy.
    EEI also contends that the Commission has already allowed a 
``passive economic interest'' in all of the ISOs that have been 
approved to date. Sierra Pacific makes a similar argument. Sierra 
Pacific contends that ``profits'' made by an ISO go back to the 
transmission owners even though they may have relinquished operational 
and decisionmaking control. It argues that ``this arrangement [in ISOs] 
is the essence of a passive ownership interest.'' \246\ The principal 
difference is that ``the passive ownership interest in a Transco 
involves ownership in the transco itself rather than the assets 
operated by the Transco.'' \247\ However, it argues that in substance 
both types of interests are the same since they allow the owner to 
share in the profits derived from operating their transmission 
facilities without having any influence over that operation. Sierra 
Pacific concludes by urging the Commission to allow passive ownership 
in both types of institutions to avoid creating ``an artificial 
incentive in favor of ISOs instead of Transcos.'' \248\
---------------------------------------------------------------------------

    \246\ Sierra Pacific at 11.
    \247\ Id.
    \248\ Sierra Pacific at 12.
---------------------------------------------------------------------------

    Enron/APX/Coral Power point to the example of National Grid Company 
(NGC) in England and Wales as a real world example of passive ownership 
of a for-profit transco by market participants. For several years after 
privatization in 1990, the regional electricity companies (RECs) were 
allowed to own NGC but were ``expressly barred from participating in 
day-to-day management or interfering with the ability of NGC to fulfill 
the purpose of privatization.'' \249\ However, in reply comments TDU 
Systems contends that Enron/APX/Coral Power fails to mention that this 
passive ownership arrangement was terminated after several years. 
Citing to a recent interview with Callum McCarthy, Great Britain's 
Director of Gas and Electricity Supply, TDU Systems points out that the 
RECs were ``told to divest these interests, and did so.'' \250\
---------------------------------------------------------------------------

    \249\ Enron/APX/Coral Power at 14.
    \250\ TDU Systems Reply Comments at 22.
---------------------------------------------------------------------------

    In contrast, TDU Systems and others ask the Commission not to allow 
passive ownership in the final rule.\251\ TDU Systems say that ``the 
line between passive and active ownership is often not a bright line.'' 
\252\ As an example, it states that in the recent Alliance transco 
filing, the divesting transmission owners ``hold supposedly passive 
ownership interests in the Transco, but retain the right to pass on a 
number of different business transactions.'' \253\ TDU Systems assert 
that if the Commission opens the door to ownership of RTOs by market 
participants, it will be forced to engage in substantial ``conduct 
policing.'' Salomon Smith Barney concurs and states that passive 
ownership ``will prove troublesome for both the utilities and FERC'' 
because it creates a ``need to constantly police supposedly passive 
ownership positions to make sure that they remain passive in all 
respects.'' \254\
---------------------------------------------------------------------------

    \251\ See, e.g., APPA, Industrial Consumers and South Carolina 
Authority.
    \252\ TDU Systems at 41.
    \253\ Entergy at 42.
    \254\ Salomon Smith Barney Reply Comments at 15.
---------------------------------------------------------------------------

    South Carolina Authority echoes this point. It argues that by 
allowing passive ownership the Commission would be put in the difficult 
job of determining ``how `passive' a particular `passive interest' 
really is.'' \255\ It urges the Commission not to compromise its 
``bedrock position on independence'' because it will lead to ``an 
endless series of extensive battles over ownership structure, corporate 
bylaws and rules, layered on top of continuing allegations of 
discrimination in the marketplace.'' \256\ It asks ``why * * * risk 
compromising the independence principle?'' \257\
---------------------------------------------------------------------------

    \255\ South Carolina Authority at 21.
    \256\ Id. at 24.
    \257\ Id.
---------------------------------------------------------------------------

    Just as several commenters raise capital formation arguments in 
support of the need to allow some voting interests by market 
participants, many of these commenters also raise similar arguments in 
support of allowing passive ownership.\258\ In general, they contend 
that current owners are not likely to sell transmission assets 
voluntarily to others if selling leads to a large capital gains tax 
payment. They contend that passive ownership provides a creative way to 
allow transfer of grid operations to an independent party while 
reducing the tax burden on current transmission owners.
---------------------------------------------------------------------------

    \258\ See, e.g., Entergy and Southern Company.
---------------------------------------------------------------------------

    In contrast, Consumer Groups asserts that there are mechanisms 
other than passive ownership that would ``permit `divestiture' without 
tax consequences'' and that an important advantage of these other 
mechanisms is that they would ``better assure independence.'' \259\ As 
one example, Consumer Groups asserts that a vertically integrated 
utility could spin off its transmission assets to its shareholders. 
While recognizing that the IRS Code seems to eliminate the favorable 
tax treatment if the spun-off corporation is sold within two years of 
the original distribution, Consumer Groups states that this is a 
rebuttable, not an absolute, prohibition and that a recent IRS proposed 
rule seems to suggest that favorable tax treatment could be retained if 
the spin-off of transmission assets is done in response to regulatory 
mandates. South Carolina Authority raises a different argument against 
regulatory policies to accommodate passive ownership. It asks why the 
Commission should feel obligated to minimize the federal corporate 
income tax responsibilities of privately owned utilities.
---------------------------------------------------------------------------

    \259\ Consumer Groups Reply Comments at 11.
---------------------------------------------------------------------------

    Several commenters recommend that we accept passive ownership at 
least as a necessary transition device. For example, Enron/APX/Coral 
Power state that ``there will likely need to be some years of passive 
ownership by industry participants before the RTOs will have 
demonstrated their viability as stand-alone transmission businesses 
that can successfully be taken public.'' \260\ ISO-NE, which favors a 
single grid company for all of New England, observes that because of 
``tax and other considerations, current owners of transmission assets 
may wish to avoid immediate divestiture, and may wish to retain 
indirect ownership.'' \261\ Salomon Smith Barney predicts that most 
utilities will want to dispose of passive and minority interests over 
time. NECPUC, representing the six New England commissions, echoes this 
point. It states that the Commission may have to accept 
``[t]ransitional periods in which the ownership interests of market 
participants are phased out over time.'' If such transitions are 
allowed, NECPUC urges us to ensure that they are ``carefully 
monitored.'' \262\ TDU Systems, as noted earlier, recommends that 
passive ownership should be used only as an ``extraordinary transition 
measure'' and should be allowed only for a short period of time.
---------------------------------------------------------------------------

    \260\ Enron/APX/Coral Power at 14.
    \261\ ISO-NE at 20.
    \262\ NECPUC at 11.
---------------------------------------------------------------------------

    RTO Governing Boards. Many commenters recommend that membership on 
RTO governing (i.e., decisional) boards be limited to non-
stakeholders.\263\ For example, the Justice

[[Page 848]]

Department urges the Commission to consider barring all market 
participants from any decision-making role. It says that this approach 
assures ``a clean structural break.'' \264\ If stakeholders are allowed 
on the governing board, the Justice Department recommends that 
independents (i.e., non-stakeholders) should constitute a majority of 
the board's voting members and that the board's voting rules not allow 
vetoes by any one class of stakeholders. Most commenters who support an 
independent board recommend that the maximum size of the board not be 
specified in the final rule but instead be left to the discretion of 
the participants. Two exceptions are the South Carolina Authority, 
which recommends that board size be limited to seven to nine directors, 
and the Midwest Municipals, which suggests that the Commission question 
any non-stakeholder board that has more than 10 to 15 members.
---------------------------------------------------------------------------

    \263\ See, e.g., Advisory Committee ISO-NE, APX, Avista, Desert 
STAR, Industrial Consumers, PJM, Reliant, South Carolina Authority 
and UtiliCorp. In general, these commenters adopt the convention 
used in the NOPR that a non-stakeholder is synonymous with a non-
market participant. See note 187 in FERC Stats. and Regs. para. 
32,541 at 33,726.
    \264\ Justice Department at 4. The Southern Company states that 
if the Commission requires non-stakeholders boards RTOs that are 
ISOs, then it must allow transmission owners the right to establish 
``performance standards'' for the RTO and the right to withdraw if 
the RTO fails to meet these standards. Southern Company at 40-41.
---------------------------------------------------------------------------

    Other commenters state that a danger of non-stakeholder boards, 
such as those already approved by the Commission for several ISOs, is 
that they become isolated and sometimes unresponsive to stakeholder 
concerns. UtiliCorp, for example, asserts that ``one of the most 
frequently heard criticisms of the ISOs currently in existence is their 
unresponsiveness and lack of accountability.'' 265 Several 
other commenters echo this concern and recommend that an independent 
board be required to consult formally and informally with advisory 
committees of stakeholders (i.e., a two-tier form of governance). For 
example, the Midwest Municipals recommend that RTOs with non-
stakeholder boards ``be required to have a senior management or 
advisory committee made up of market participants from each relevant 
market sector and subordinate, issue oriented committees'' similar to 
those that exist in the PJM, New York and New England 
ISOs.266 STDUG recommends that if a non-stakeholder board is 
formed ``it must be accompanied by some action forming mechanism that 
forces the board to listen and consider the concerns of all members or 
stakeholders in the RTO.'' 267
---------------------------------------------------------------------------

    \265\ UtiliCorp at 11.
    \266\ Midwest Municipals at 19.
    \267\ STDUG at 7-8.
---------------------------------------------------------------------------

    EPSA urges the Commission to pay close attention to the composition 
and functions of any committee structure that operates underneath a 
governing board because independent governance ``does not stop at the 
ISO board.'' 268 It contends that this is necessary for 
independence because advisory committees of stakeholders will often 
have de facto decisionmaking power. Dynegy makes specific 
recommendations for any stakeholder committees that operate below and 
report to an RTO board. It recommends that such committees be governed 
by ``segment voting''--each industry segment would have a proportional 
vote; each market participant would have to choose to participate in 
one market segment; and the votes within a segment would be split among 
however many entities choose to participate in that segment. It 
observes that this approach has been adopted or proposed in the PJM, 
NEPOOL and New York ISOs.
---------------------------------------------------------------------------

    \268\ EPSA at 15.
---------------------------------------------------------------------------

    Other commenters urge us not to prohibit stakeholder or hybrid 
boards consisting of stakeholders and non-stakeholders such as the one 
that exists in California. Cal ISO, noting that it is the only FERC-
jurisdictional ISO with a stakeholder board, states that ``[t]he Cal-
ISO stakeholder board has worked'' and urges us to confirm the 
acceptability of a stakeholder board in the final rule if the board is 
structured to ensure that no market participant or class of market 
participants can control the decisions of the RTO.269 
Dairyland points out that the Commission has encouraged and approved 
stakeholder boards under the independence principle for ISOs in Order 
No. 888.270 Dynegy recommends a hybrid governing board with 
``disinterested'' (i.e., non-stakeholder) members comprising one-third 
of the board and stakeholder members comprising the remaining two-
thirds.271 However, it observes that mandated stakeholder 
representation would be ``inappropriate'' for an RTO that is a for-
profit transco. California Board urges us to allow a variety of 
governance forms including stakeholder boards ``until and unless 
experience shows that one form'' is clearly superior to other forms of 
governance.272 TXU Electric states that ``stakeholder 
representation is a legitimate form of governance for a regional 
transmission organization'' and, in fact, is the required form of 
governance under the recently enacted Texas electric restructuring 
statute.273
---------------------------------------------------------------------------

    \269\ Cal ISO at 15. Cal ISO points out that this has been 
achieved through a board of governors in which (1) no one voting 
class is able to block or veto an action, and (2) no two classes 
together are able to form a sufficient majority to make decisions, 
and (3) no entity (including its affiliates and subsidiaries) is 
able to participate in more than one voting class. See Attachment A-
1 of Cal ISO.
    \270\ ``A governance structure that includes fair representation 
of all types of users would help to ensure that the ISO formulates 
policies, operates the system, and resolves disputes in a fair and 
non-discriminatory manner.'' Order 888, FERC Stats. and Regs. para. 
31,036 at 31,730-731
    \271 \ Dynegy recommends that five ``segments'' for the 
stakeholder representatives: transmission owners, transmission-
dependent utilities, marketers, end-users and independent power 
producers. Dynegy at 42.
    \272 \ California Board at 6.
    \273 \ TXU Electric at 9.
---------------------------------------------------------------------------

    Role of State Agencies. Commenters express a wide range of opinions 
on the appropriate role of state agencies. The comments fall generally 
into two categories: the role of state agencies during the 
developmental stage and the role of state agencies after an RTO begins 
operating.
    Many commenters believe that state commissions and other state 
agencies should have a major role in RTO development. NARUC argues that 
state commissions ``should fully participate in RTO formation and 
development.'' 274 State commissions generally take the 
position that their involvement is important because the size, scope 
and functions of an RTO will be critical for the success of their 
state-by-state retail choice programs.275 NECPUC notes that 
it had an important role in shaping the design of the ISO-NE before any 
formal filing was made at the Commission. Nine Commissions, 
representing state commissions from the East-Central, Midwest and 
Southwest regions, gives a specific example of how the Commission 
should defer to state commissions. They state that if a critical mass 
of state commissions in their region reach agreement on the appropriate 
boundaries for an RTO, then FERC ``should provide deference to that 
collective state determination.'' 276
---------------------------------------------------------------------------

    \274\ NARUC at 11.
    \275\ See, e.g., Illinois Commission.
    \276\ Nine Commissions at 6.
---------------------------------------------------------------------------

    Other commenters outside of the state regulatory community also 
address the issue of the appropriate role for state commissions. For 
example, Enron/APX/Coral Power say that state regulators and 
politicians should play a role in encouraging local transmission owners 
to join RTOs but ``[t]he role of states * * * should extend no 
further.'' 277
---------------------------------------------------------------------------

    \277 Enron/APX/Coral Power at A-3.\
---------------------------------------------------------------------------

    Once an RTO becomes operational, Enron/APX/Coral Power argue that 
state commissions should have no special

[[Page 849]]

role and, in fact, the RTO ``should be protected from local 
interference.'' Their argument for minimizing the role of state 
agencies is that ``no other commercial activity (with the possible 
exception of telecommunications) is more intrinsically in interstate 
commerce.'' Conlon, the former President of the California Public 
Utilities Commission, expresses a similar view (``local control, 
although desirable from a states' rights standpoint, should be 
sacrificed to get interstate control of the entire interconnection.'') 
278
---------------------------------------------------------------------------

    \278\ Conlon states that these are his views and are not 
necessarily the views of any present or former Commissioners or 
staff of the California PUC.
---------------------------------------------------------------------------

    On the issue of voting rights for state commissions, Enron/APX/
Coral Power argues that it would be inappropriate for any state 
commission to be a voting member of an RTO. Their rationale is that the 
state commission would lose its ability to monitor the relationship 
between the RTO and any entity that may be serving the state's domestic 
load if it is also a voting member of the RTO board. NECPUC expresses a 
similar view. While recommending that state commissions have extensive 
communication with the RTO and its participants, it concludes that 
state commissions ``should not have a vote in the governance of the ISO 
New England.'' 279 Arizona Commission says that states 
should have the right of ex officio membership but that ``FERC should 
not force the states to be voting members.'' 280 ISO-NE also 
shares this view. It contends that it would be ``awkward'' for a state 
official to serve as a voting director of an RTO for several reasons. 
First, it could create a conflict between the state official's duties 
as an RTO board member and his or her regulatory or administrative 
duties at the state level. ISO-NE argues that many state conflict of 
interest laws may expressly prohibit such service because of the 
conflicts it would create.281 Second, in the case of a 
multistate RTO, it may difficult for an official from one state to vote 
for decisions that are good for the residents of all the states served 
by the RTO. Third, the solution of having a board member from each 
state ``could create gridlock or unwieldy boards.'' 282
---------------------------------------------------------------------------

    \279\ NECPUC at 9.
    \280\ Arizona Commission at 5.
    \281\ In contrast, Reliant recommends that ``state officials 
should serve as board members in order to avoid conflicts in future 
decisions.'' It appears that Reliant is referring to future 
decisions of the state agencies. Reliant at 5.
    \282\ ISO-NE at 3.
---------------------------------------------------------------------------

    Florida Commission makes a distinction between for-profit and non-
profit RTOs. It says that it would be inappropriate for members of a 
state regulatory body or other state officials to serve on the board of 
a for-profit transco. However, Florida Commission believes that it may 
be appropriate for a state commissioner to serve on the board of a non-
profit RTO if disputes involving the RTO and other parties do not come 
before the state commission.
    Washington Commission expresses a different view. In its opinion, 
the role of state commissions should vary depending on the type of 
board. It recommends that state involvement could be limited to the 
selection of the non-affiliated board members for a non-stakeholder or 
hybrid board. In contrast, if there is a stakeholder board, Washington 
Commission urges that states be granted ``voting member status.'' In 
the case of a for-profit transco, it urges the Commission to require a 
formal advisory role for the states.
    Section 205 Filing Rights. Many IOUs and public systems oppose the 
NOPR's proposal to require that RTOs have ``exclusive and independent 
authority to file changes to its transmission tariff with the 
Commission under section 205 of the Federal Power Act.'' 283 
In contrast, those who support the proposal assert that it is a 
necessary and logical implication of the Commission's previously stated 
policy that the ``[a]uthority to act unilaterally * * * is a crucial 
element of a truly independent ISO.'' 284 SRP recommends 
that ``the need for an RTO to independently administer its own tariff 
must be balanced against the need for individual transmission owners to 
maintain control over their ability to recover their revenue 
requirements and meet their debt service obligations.'' 285
---------------------------------------------------------------------------

    \283\ See, e.g., AEP, Alliance Companies, CMUA, Duke, Florida 
Power Corp., LPPC, Metropolitan, Midwest Municipals, Montana-Dakota 
and Southern Company.
    \284\ Citing NEPOOL, 79 FERC para. 61,974 at 62,585 (1997). See, 
e.g., PJM, Cal ISO, Industrial Consumers, Montana Commission, NECPUC 
and NASUCA.
    \285\ SRP Reply Comments at 12.
---------------------------------------------------------------------------

    Those who oppose the proposal focus on the case of an RTO that is 
an ISO. Transmission ISO Participants argues that the proposal is bad 
law and bad policy. Citing the Supreme Court decision in United Gas 
Pipe Line Co. v. Mobile Gas Service Corp.,286 it asserts 
that the Commission does not have the legal authority to grant section 
205 filing rights to an ISO. It contends that the FPA grants this 
fundamental right to transmission owners that are public utilities. 
While a transmission owner may ``voluntarily cede'' this right to an 
ISO, the Commission cannot compel a transmission owner, either directly 
or indirectly, to give up this legal right. Puget Sound argues that the 
proposal would have the effect of reducing the transmission-owning 
utility to little more than a ``bystander'' and could constitute an 
illegal ``taking'' under the Fifth Amendment of the U.S. Constitution.
---------------------------------------------------------------------------

    \286\ 350 U.S. 332 (1956).
---------------------------------------------------------------------------

    Transmission ISO Participants also claims that the Commission's 
previous decisions in this area have not been consistent. It asserts 
that the Commission ``required transmission owners to cede their 
section 205 rights to the ISO in our order approving the PJM ISO.'' 
287 But it points to the fact in a 1997 California ISO order 
that the Commission seemed to establish a much smaller role for the ISO 
(``the ISO is responsible for only collecting the revenue 
requirement.'') 288 Furthermore, it notes that in this same 
order the Commission decided to set all rate design and rate 
methodology issues in the dockets established for the filings made by 
the transmission owners, and not in a docket for the transmission 
tariff filing made by the ISO.289
---------------------------------------------------------------------------

    \287\ Transmission ISO Participants at 20.
    \288\ Quoting 81 FERC para. 61,122 at 61,506 (1997).
    \289\ However, the California ISO asserts that it has 
``exclusive and independent'' authority ``to modify the design of 
rates for transmission and ancillary services.'' See Cal ISO at 18.
---------------------------------------------------------------------------

    Many commenters also address whether it would be practical to give 
RTOs FPA section 205 filing rights for transmission rate design and 
terms and conditions that directly affect access while transmission 
owners would retain section 205 rights for overall revenue 
requirements. A number of commenters say that this distinction is 
unworkable because the two are inextricably connected (i.e., changes in 
rate design can have major impacts on revenue 
collections).290
---------------------------------------------------------------------------

    \290\ See, e.g., EEI, Transmission ISO Participants and Southern 
Company.
---------------------------------------------------------------------------

    However, other commenters argue that the Commission cannot 
realistically expect an RTO to be a neutral and unbiased transmission 
provider unless the RTO has full legal authority to propose changes in 
its own transmission tariff.291 PJM states that ``its 
ability to function would be severely hindered'' unless it has the 
ability to unilaterally make tariff filings. It points to several 
recent instances of emergency filings with us as examples of why it 
must have its own independent filing authority without getting the 
prior approval of

[[Page 850]]

transmission owners or any other group. It argues that it will not be 
able to satisfy its responsibility to ``provide for safe and reliable 
operation of the transmission grid and operation of a robust, 
competitive, and non-discriminatory electricity market'' without such 
authority.292 However, PJM does state that transmission 
owners, rather than the RTO, should have the unilateral right to seek 
changes in the RTO's tariff to address changes in the transmission 
owners revenue requirements with respect to transmission 
facilities.293
---------------------------------------------------------------------------

    \291\ See, e.g., Cal ISO, PJM ISO, Industrial Customers, Montana 
Commission, NECPUC and NASUCA.
    \292\ PJM at 53.
    \293\ PJM at 54. The California, New York and New England ISOs 
agree with PJM on this point.
---------------------------------------------------------------------------

    Oneok, a power marketer, states that an RTO needs its own section 
205 filing authority because it would not be able to reach a consensus 
and act quickly if it must get the prior approval of all stakeholders. 
However, Oneok suggests an alternative to what was proposed in the 
NOPR. It recommends a two-tier approach to transmission tariff filings. 
Under this proposal, ``transmission-owning utilities would be free to 
file changes to their rates (or rate structures) at any time'' to their 
single customer, the RTO.294 The RTO would then be free to 
``repackage'' the transmission capacity and services that it purchased 
under these separate transmission owner tariffs in its own RTO 
transmission tariff filed under section 205. Oneok states that there 
are precedents for this approach in prior Commission practices.
---------------------------------------------------------------------------

    \294\ Oneok at 8.
---------------------------------------------------------------------------

    Commission Conclusion. The Basic Independence Principle. In the 
NOPR, we repeated our earlier statement that ``the principle of 
independence is the bedrock upon which the ISO must be built ``and 
emphasized that this principle must apply to all RTOs, whether they are 
ISOs, transcos or variants of the two. We also stated that ``[a]n RTO 
needs to be independent in both reality and perception.'' We reaffirm 
both principles in the Final Rule.
    In applying these principles in the context of ISOs, we have 
stressed the importance of a decisionmaking process that is independent 
of control by any market participant or class of participants. This, in 
turn, required that we pay considerable attention to governance (e.g., 
voting shares and voting rules). Because ISOs are typically non-profit 
and non-share corporations, we generally did not have to consider the 
effect of ownership interests on the independence of the ISO. This will 
change with the emergence of for-profit RTOs, such as transcos, that 
have ownership interests. For these types of RTOs, we will have to 
examine how ownership of the RTO by market participants could affect 
the independence of its decisionmaking process.
    Who Is a Market Participant? The overall purpose of the 
independence standard in the Final Rule is to ensure that an RTO will 
provide transmission service and operate the grid in a non-
discriminatory manner. Equal access requires RTOs to be independent. 
Implementation of this standard then requires answering the question: 
independence from whom? Our logic in the NOPR, which we have adopted in 
the Final Rule, is to define a group of entities, referred to as market 
participants, whose economic or commercial interests are likely to be 
affected by an RTO's decisions and actions.
    Commenters provided many helpful comments on the definition of 
market participant that was proposed in the NOPR. As noted in the 
summary, the commenters generally fall into two broad categories: those 
who argue that the NOPR definition is too broad and those that argue 
that it is too narrow. We find that these views were not always 
inconsistent since the commenters were often discussing different 
aspects of the definition. After a careful review of the comments, we 
conclude that it is necessary to change the definition of a market 
participant that was proposed in the NOPR. The revised definition at 
section 35.34(b) is:

    (2) Market participant means:
    (i) Any entity that, either directly or through an affiliate, 
sells or brokers electric energy, or provides transmission or 
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)).

    Before discussing how this definition is different from the NOPR 
definition, it is useful to consider why a definition of market 
participant is needed in the first place. It is the Commission's view 
that an RTO must be independent of any entity whose economic or 
commercial interests could be significantly affected by the RTO's 
actions or decisions. Without such independence, it will be difficult 
for an RTO to act in a non-discriminatory manner. Therefore, the 
definition focuses on those entities whose economic and commercial 
interests can be significantly affected by the RTO's behavior. However, 
it should be emphasized that the definition of a market participant is 
simply a starting point for implementing the independence standard. The 
definition is used 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. As discussed below, the fact that a 
particular participant is defined as a market participant does not 
preclude it from having any active or passive ownership interest in an 
RTO.
    We agree with many commenters that the NOPR definition was too 
broad in defining a market participant to be ``any entity that buys or 
sells electric energy in the RTO's region or in any neighboring region 
that might also be affected by the RTO's actions.'' As several 
commenters pointed out, a literal reading of this definition would make 
market participants of every residential, commercial, industrial and 
wholesale electric customer in the RTO region and some neighboring 
regions. This is clearly too encompassing and was not our intent. We 
therefore are narrowing the definition of a market participant in the 
Final Rule to include those who sell or broker electric energy but not 
those who buy electric energy.
    We recognize, however, that there may be circumstances where buyers 
of electric energy could buy a controlling interest in a for-profit RTO 
and manipulate its access and curtailment decisions to their advantage. 
Such an outcome would clearly be inconsistent with the independence 
standard. Therefore, as a backstop, we are adding paragraph (b) to the 
definition (``any other entity that the Commission finds has economic 
or commercial interests that would be significantly affected by the 
RTO's actions or decisions''). The addition of this paragraph allows 
us, on a case-by-case basis, to consider whether particular buyers of 
electric energy (or any other entity) could manipulate an RTO's 
decisions to the disadvantage of other RTO customers.
    We are also dropping the phrase ``in the RTO's region or in any 
neighboring region that might also be affected by the RTO's actions.'' 
Given the high degree of integration within the Eastern and Western 
Interconnections, the growth of transactions involving buyers and 
sellers separated by hundreds of miles and the participation of energy 
concerns

[[Page 851]]

in multiple markets, we conclude that it would be virtually impossible 
to apply a geographically delineated standard. However, we will 
consider requests for waivers from entities in other Interconnections 
who can demonstrate that their economic or commercial interests would 
not be significantly affected by the RTO's actions or decisions.
    We are also making one other change to the NOPR definition to 
expand its scope. Paragraph (a) expands the NOPR definition by 
including entities that provide transmission or ancillary services to 
an RTO. We believe that it would compromise an RTO's independence if 
one or more transmission owners could influence the RTO's decisions to 
the detriment of other market participants. Therefore, it is 
appropriate to include providers of transmission service as market 
participants.295 With regard to the creation of RTOs that 
are transcos, we have developed policies on the level of ownership that 
market participants may possess, as discussed below, in order to ensure 
that the operating decisions of the RTO are truly independent and non-
discriminatory.
---------------------------------------------------------------------------

    \295\ It is conceivable that RTO A might provide transmission 
service to a neighboring RTO B. In such a situation, RTO A would be 
considered a market participant. RTO A might also acquire ownership 
interests in RTO B as a first step towards consolidation of the two 
RTOs. We would anticipate granting a waiver to RTO A from a market 
participant definition and any associated ownership restrictions if 
we had reason to believe that the waiver could lead to a larger and 
more effective RTO.
---------------------------------------------------------------------------

    We believe that it is necessary to include ancillary service 
providers as market participants since the RTO is the supplier of last 
resort for ancillary services. As a consequence, the RTO is likely to 
have considerable discretion in defining the types and quantities of 
ancillary services needed and how they will be procured (e.g., market 
design). An RTO's decisions in any of these dimensions can have major 
economic effect on one or more providers of such services. Therefore, 
we define these entities as market participants to ensure that they are 
not in a position to influence the RTO's decisions to their own 
advantage.
    Several other commenters urged us to include distribution entities 
as market participants. At present, most distribution entities provide 
a bundled service. The bundled service includes the sale of electric 
energy as well as the delivery of this electric energy over local 
distribution facilities. Since these traditional distribution entities 
are selling electric energy, they would be considered market 
participants under the definition.
    However, several commenters pointed out that a new type of 
distribution entity is likely to emerge with the spread of retail 
competition. This type of distribution entity would simply transmit 
electric energy over distribution facilities for others and would not 
sell electricity.
    The issue is whether this type of pure distribution entity should 
be considered a market participant. Several commenters pointed to the 
danger of allowing one or two distribution entities to control an RTO. 
Their concern is that these distribution entities could use their 
control over the RTO to favor their distribution facilities over the 
facilities of non-affiliated distribution entities when the RTO has to 
choose among competing requests for transmission service or alternative 
curtailment actions. Other commenters minimize this risk and argue that 
distribution entities should be allowed to own RTOs because there are 
economies in having a single entity provide total delivery service 
(i.e., transmit electric energy at high and low voltages). The 
Commission does not wish to create impediments to the efficient 
integration of transmission and distribution facilities. Therefore, we 
will not include pure distribution entities in paragraph (a) of the 
market participant definition. However, if we are presented with 
evidence that a distribution entity is able to influence an RTO's 
actions or decisions to the disadvantage of other users, we may find 
such a distribution entity to be a market participant under paragraph 
(b) of the definition. Paragraph (a) of the revised definition defines 
all sellers of electric energy, whether retail or wholesale, as market 
participants. Several commenters urge us to exclude retail providers of 
last resort from the definition. These are entities that are required 
by state commissions or state law to be backup suppliers to retail 
customers who choose not to switch suppliers in a state-mandated retail 
competition program. We have decided to include such entities in the 
market participant definition because they are sellers of electric 
energy. However, the obligations and responsibilities of such entities 
are still being developed on a state-by-state basis. As a consequence, 
even though such entities may be generically referred to as ``suppliers 
of last resort,'' their responsibilities and incentives may vary 
widely. The Commission believes that certain factors, (e.g., an 
entity's sole electric sales are made to satisfy a state requirement 
and it does not compete for retail load) would support a finding that 
the entity is not a market participant.
    NEPCO et al. point to the problem of incumbent utilities that have 
tried to divest themselves of generating assets but have not yet 
succeeded. They say that this is likely to be a particular problem for 
utilities that own minority interests in nuclear plants since it is 
currently difficult to sell such interests. NEPCO et al. request that 
they not be automatically deemed a market participant because of these 
ownership interests. Once again, we will entertain requests for 
exemption. For example, we would be willing to give an exemption if the 
current owner could clearly demonstrate that it has transferred to non-
affiliated entities both the marketing rights and any profits resulting 
from the sale of electric energy associated with its ownership 
interest. Any compensation that the market participant receives from 
the non-affiliated entity should not be tied to profits on specific 
sales made by this entity.
    RTO Economic Interests in Market Participants and Energy Markets. 
We reaffirm the NOPR proposal that the RTO, its employees and any non-
stakeholder directors must not have any financial interests in market 
participants. As noted in the NOPR, our focus will be on current 
financial interests. Since this principle raises a number of specific 
issues, especially with respect to pension rights and benefits, we will 
continue our current policy of implementing this principle on a case-
by-case basis.
    Several commenters argued that the NOPR's treatment of financial 
independence was too narrowly drawn. For example, Dynegy, pointing to 
the example of ISOs, argues that while ISOs ``may ostensibly be 
independent of market participants--they are not independent of the 
market itself.'' 296 The participation of RTOs in the market 
stems from certain obligations that we require of any RTO: it is the 
supplier of last resort for required ancillary services and it must 
attempt to procure such services efficiently in competitive markets. 
These two requirements mean that most RTOs will be operators of 
bilateral and spot markets in ancillary services as well as buyers in 
these same markets. In addition, they will be resellers of any 
ancillary services that they purchase.
---------------------------------------------------------------------------

    \296\ Dynegy at 35.
---------------------------------------------------------------------------

    It is our intention that RTOs perform functions that make the 
transmission infrastructure operate efficiently, not that they take 
actions in ways that skew competitive outcomes in the market.

[[Page 852]]

Nevertheless we acknowledge that RTO operations may have that effect. 
Moreover, the two requirements may lead to an outcome that an RTO is 
not indifferent to whether the prices are high or low. Given this 
possible conflict, we will require that all RTOs must propose an 
objective monitoring plan to assess whether the RTOs involvement in 
these markets favors its own economic interests over those of its 
customers or members.297
---------------------------------------------------------------------------

    297 This is discussed more fully under Market Monitoring. 
See infra section III.E.6.
---------------------------------------------------------------------------

    Passive Ownership Interests in the RTO. As we have emphasized, the 
Commission wishes to give industry participants every reasonable 
opportunity to create RTOs through their own voluntary actions. 
However, we also recognize that mere exhortations that the industry 
participants should volunteer to create independent transmission 
entities will not ensure a truly open and reliable grid in the 
reasonably foreseeable future. The Commission must take actions to 
ensure that the stand-alone transmission business is financially 
attractive and viable. We must also provide a high degree of regulatory 
certainty and not foreclose viable options for creating and developing 
RTOs. To provide more certainty, the Final Rule provides guidance on 
our future policies for establishing revenues, incentives and 
performance-based regulation for proposed RTOs.298
---------------------------------------------------------------------------

    \298\ See infra section 111.G.
---------------------------------------------------------------------------

    We also recognize that the voluntary creation of RTOs requires that 
current owners of transmission assets must be willing to transfer 
operational control of these assets to RTOs or to divest their 
interests in their entirety. Therefore, it is important that we provide 
current transmission owners with flexibility in deciding how they will 
relinquish ownership or control of their transmission facilities to an 
RTO. Numerous commenters, ranging from IOUs to state commissions to 
marketers, urge the Commission not to make RTO policy in a vacuum. In 
particular, they stress that the Commission needs to understand that 
there are many existing legal and tax disincentives to the outright 
sale of such assets to an RTO.299
---------------------------------------------------------------------------

    \299\ See EEI, Southern Company, United Illuminating, Enron/APX/
Coral Power, ISO-NE, NECPUC, Salomon Smith Barney and Konoglie/Ford/
Fleishman.
---------------------------------------------------------------------------

    Among these potential impediments, commenters identify the federal 
capital gains tax most frequently. There was agreement among many 
commenters that it would be unrealistic for the Commission to expect 
current transmission owners to sell their transmission facilities to an 
RTO if the sale becomes a taxable event that triggers a large capital 
gains tax. Therefore, they urge the Commission to accommodate financing 
and ownership arrangements that facilitate the creation of for-profit 
RTOs while minimizing the tax burden on current transmission owners who 
are willing to take actions that would promote the Commission's RTO 
policies. Many commenters argue that the Commission could significantly 
accelerate RTO development if we were to allow current transmission 
owners to retain a passive ownership interest in new RTOs. Several 
commenters contend that if the Commission fails to accommodate such 
arrangements, this initiative will be unproductive because our policies 
would be effectively biased against the creation of for-profit 
transmission companies that seek RTO status. They assert that such an 
outcome would be inconsistent with the statement in the NOPR that the 
Commission wishes to encourage all types of RTOs, whether they are 
transcos, ISOs or combinations of the two.300
---------------------------------------------------------------------------

    \300\ FERC Stats. and Regs. para. 32,541 at 33,726.
---------------------------------------------------------------------------

    In response to these comments, we reaffirm that it is the 
Commission's policy to encourage all types of RTOs. In light of our 
evolving experience with the workability of certain RTO models, it 
would be inappropriate for us to mandate a single RTO model of 
ownership and operation. While the dominant approach to date has been 
ISOs, we are receptive to alternative approaches that can provide 
evidence of the legitimacy of various models of ownership and 
operation. Because the institutions which we propose to sanction 
pursuant to this Final Rule will be so influential in operating the 
Nation's nfrastructure over a period of time, the Commission resolves 
to implement its independence criteria with an open mind and, to the 
extent practicable, with flexibility. At this juncture, we therefore 
propose to remove unnecessary impediments to the creation of 
transmission companies by allowing market participants to maintain 
passive ownership interests in RTOs.
    We reaffirm our belief that ``[a]n RTO must be independent in both 
reality and perception.'' 301 This same conclusion was also 
reached by the DOE Reliability Task Force and the NERC Reliability 
Panel, two widely respected industry groups comprised of 
representatives from all sectors of the industry. The DOE Reliability 
Task Force concluded that regional reliability entities must be ``truly 
independent of commercial interests so that their reliability actions 
are--and are seen to be--unbiased and untainted.'' The Electric 
Reliability Panel concluded that ``[t]o dispel suspicions that the 
system operator favors one participant over another * * * the operator 
must be independent of market participants.'' 302
---------------------------------------------------------------------------

    \301\ As discussed below, this overriding consideration is also 
relevant to active voting interests.
    \302\ See U.S. Department of Energy, Maintaining Reliability in 
a Competitive U.S. Electricity Industry: Final Report of the Task 
Force on Electric System Reliability, at xv (September 29, 1998); 
North American Reliability Council, Electric Reliability Panel, 
Reliable Power: Renewing the North American Electric Reliability 
Oversight System at 17 (Dec. 22, 1997)
---------------------------------------------------------------------------

    The Commission concludes that an RTO will not be successful unless 
all market participants believe that the RTO will operate the grid and 
provide transmission service to all grid users on a non-discriminatory 
basis. It is clear that the perception of a broad cross-section of 
commenters is that passive ownership may interfere with the independent 
operation of RTOs.303 In the view of many commenters, 
passive ownership is only a subtle mechanism to allow existing 
transmission owners to continue to control use of transmission assets 
and ultimately deny equal access to competitors. Therefore, we must 
provide assurances to all market participants that any passive 
ownership interest is truly passive and will in no way interfere with 
the independent operation and decisionmaking of the RTO. It is 
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.304
---------------------------------------------------------------------------

    \303\ See, e.g., Consumer Groups, South Carolina Authority, TDU 
Systems, Industrial Customers, APPA, Los Angeles, NASUCA, Arkansas 
Cities and Wolverine Cooperative.
    \304\ The auditing requirements of this Rule represent one 
approach to addressing our concern that it may otherwise be 
difficult to assess the ongoing independence of passive ownership 
arrangements. We expect that parties will include in any rehearing 
requests their views on this approach, in general, and the 
particular auditing requirements that we have adopted.
---------------------------------------------------------------------------

    Those who support the policy of allowing market participants to 
have passive ownership in RTOs point to the fact that the Commission 
has accepted many instances of passive ownership in the past. 
Typically, these arrangements have involved the sale and leaseback of 
generating units in which a jurisdictional public utility will sell a 
generating unit to a bank, insurance company or other financial 
institution. The financial institution will then lease

[[Page 853]]

back the generating unit to the jurisdictional utility. Even though the 
financial institution is the owner of record, we have generally 
concluded that it is a passive owner without any real operational 
control and, therefore, is not a jurisdictional public utility under 
the FPA.305
---------------------------------------------------------------------------

    \305\ See Pacific Power and Light Co., 3 FERC para. 61,119 
(1978); Baltimore Refuse Energy Systems Co., Wheelabrator Millbury, 
Inc., 40 FERC para. 61,366 (1987).
---------------------------------------------------------------------------

    There are, however, several considerations that distinguish these 
earlier passive arrangements from the ones that are being contemplated 
for RTOs. First, the passive ownership arrangements for RTOs (e.g., 
two-tier LLCs, synthetic leases and leveraged partnerships) may be 
complicated and multi-layered. Even those commenters who urge that we 
accept passive ownership as a necessary transition mechanism admit that 
such arrangements ``will prove troublesome for both utilities and 
FERC'' because they create the ``need to constantly police supposedly 
passive ownership positions to make sure that they remain passive in 
all respects.'' 306
---------------------------------------------------------------------------

    \306\ Salomon Smith Barney Reply Comments at 15.
---------------------------------------------------------------------------

    Second, unlike financial institutions, the passive owners will 
typically own other assets (e.g., generating assets) that could reap 
major economic benefits if an RTO's decisions can be influenced to 
their advantage. Therefore, unlike financial institutions, the passive 
owners in RTOs may have a direct economic incentive to influence the 
RTO's operating and investment decisions to favor other economic 
interests.
    In response to a request for a declaratory order from Entergy 
Services, Inc., the Commission found that passive ownership of a 
transmission entity by a generating entity or other market participant 
could meet the Commission's ISO standards relating to governance and 
independence if it were properly designed. Because Entergy's proposal 
was incomplete, the Commission provided some limited guidance related 
to: board selection and removal, potential issues about the board's 
fiduciary duties, attraction of capital and issues about the 
transmission entity contracting with member companies. In this rule we 
provide further guidance which we believe will help RTO applicants who 
may be considering some form of passive ownership structure.
    Based on these considerations, the Commission's policy on proposals 
for passive ownership of RTOs by market participants will have three 
key elements:
    (1) Passive ownership proposals will be reviewed on a case-by-case 
basis. The Commission will approve a proposal only if we are satisfied 
that the passive owners have relinquished control over operational, 
investment and other decisions to ensure that the RTO will treat all 
users of the grid--passive owners and others--on an equal basis in all 
matters. The burden of proof is on the RTO to demonstrate that control 
of the RTO is ``truly independent'' and that the RTO has a 
decisionmaking process that is independent of control by the passive 
owners.
    (2) The Commission requires any RTO with passive ownership 
interests approved by the Commission to undertake an obligation and 
propose processes for an independent compliance audit to ensure the 
independence of its decisionmaking process from the passive owners. The 
first independence audit will be required two years after initial 
approval of the RTO and every three years thereafter. The independence 
compliance audit must be submitted to the Commission in a public 
document without any requirement for approval by the RTO 
board.307
---------------------------------------------------------------------------

    \307\ See supra note 304.
---------------------------------------------------------------------------

    (3) The Commission will take appropriate action if it finds 
evidence of abuses.
    We will now discuss implementation of these elements. The first 
element of our policy is that any RTO that wishes approval for passive 
ownership above the limits set for active ownership must demonstrate in 
its application that the passive owners will relinquish effective 
control over operational and investment decisions. Specifically, the 
RTO must demonstrate that the proposed arrangement has been designed to 
ensure that it can treat all users of the grid--passive owners and 
others--on an equal basis in the provision of non-discriminatory 
transmission service.
    It will be difficult for the Commission to make an assessment of 
whether a particular passive arrangement achieves true independence in 
decisionmaking for the RTO board and its management unless an RTO 
provides complete information about the rights that passive owners have 
reserved for themselves both as owners of the RTO and as providers of 
facilities and services to the RTO. In judging any proposal, our 
overriding concern is that the arrangements provide a high degree of 
assurance that those who are not passive owners will have equal access 
to the services provided by the RTO.
    To assure ourselves that this standard is satisfied, the Commission 
will need information on the following issues: fiduciary 
responsibilities of the RTO board and management to passive owners; 
ability of the RTO to raise capital independently of its passive 
owners; ability of the RTO to make investment and financing decisions 
independently of its passive owners; the extent of control by passive 
owners over board selection and removal; the extent of control by 
passive owners over transmission rates, terms and conditions; control 
of passive owners over issuance of new membership interests and/or 
equity; services that will be provided by the passive owners or their 
employees to the RTO; and the extent of access of passive owners to 
information not available to other market participants.308 
An RTO application seeking approval for passive ownership should 
provide any other relevant information that will allow the Commission 
to assess whether passive owners have reserved rights for themselves 
that are superior to those of other market participants and if such 
rights constitute control over the RTO.309
---------------------------------------------------------------------------

    308 For example, this could include information on the market 
behavior of one or more non-affiliate market participants acquired 
through a market monitoring program and information on the RTO's 
proposed investment and operational plans, except where the 
Commission has approved it as necessary to protect the passive 
owner's capital investment.
    \309\ We note that many of these same concerns also apply to 
RTOs that allow market participants to have ownership interests in 
voting securities.
---------------------------------------------------------------------------

    The second element requires a mechanism for assuring ourselves and 
market participants that any passive ownership arrangement remains 
passive over time. The Commission will require the RTO to notify us 
immediately of any changes in the underlying agreements or facts that 
occur after the initial filing. The Commission has relied on a similar 
system of self-monitoring in cases in which we have approved market-
based rates. Specifically, we have required that any public utility 
that receives market-based pricing must notify us of any factual 
changes that call into question whether it should be allowed to 
continue to charge market-based rates.310
---------------------------------------------------------------------------

    \310\ When there is a change in the factual circumstances that 
were the basis for the Commission's approval of market-based 
pricing, we require that a public utility notify us immediately of 
this change or at the next update of their market power analysis. 
This update occurs once every three years. With respect to passive 
ownership, we will require that the passive owner must notify us 
immediately of any change in governance in ownership or governance 
that takes place after our initial approval.
---------------------------------------------------------------------------

    We will also require a system of independent compliance auditing. 
The auditing must be performed by individuals or organizations that are 
not

[[Page 854]]

affiliated with the RTO or its owners. The purpose of the auditing 
would be to ensure that what is passive on paper is passive in reality 
throughout the transition period. In particular, auditors would assess 
whether the passive owners have retained rights or privileges in their 
role as owners or providers of services that would put non-owner 
participants at a competitive disadvantage. The audits would cover the 
RTO's actions and decisions with respect to operations and investments. 
In order for this to be a credible auditing system, the auditors should 
have clear authority to obtain any information or data necessary to 
perform their audits and they should have the right to report any 
findings and recommendations to the Commission without prior approval 
of the RTO or any of its owners/members. An initial audit must be 
performed two years after our approval of the passive ownership 
arrangements and every three years thereafter.311 If there 
is evidence of abuse or we are unable to determine if the ownership 
interests continue to be passive, the Commission will not hesitate to 
order appropriate remedial action, including possible termination of 
passive ownership interests.
---------------------------------------------------------------------------

    \311\ See supra note 304.
---------------------------------------------------------------------------

    We understand that passive ownership arrangements are likely to 
take many forms and that the Commission has not had much experience in 
examining these types of arrangements in the context of RTOs. We 
encourage market participants to investigate the options available for 
passive ownership to identify those types of arrangements that will 
provide the greatest assurance of independence. For example, we note 
that the SEC's Rule 250.7(d) establishes criteria under which entities 
may have ownership interests that do not trigger SEC jurisdiction under 
PUHCA. The criteria under Rule 250.7(d) are that: (1) The entity owns 
the facility as a company, a trustee or holder of a beneficial interest 
under a trust; (2) the facility is leased under a net lease directly to 
a public utility company and such facility is to be employed by the 
lessee in its operations; (3) the company is otherwise primarily 
engaged in business other than that of a public utility; (4) the terms 
of the lease have been approved by the regulatory authority having 
jurisdiction over the lessee; (5) the lease extends for an initial term 
of not less than 15 years; and (6) the rent reserved under the lease 
shall not include any amount based, directly or indirectly, on revenues 
or income of the lessee public utility. While it is unclear whether 
these exact criteria can be applied to the passive ownership 
arrangements that may be involved in the formation of an RTO or whether 
they would address the particular independence issues raised in this 
Rule, we believe that it would be acceptable for market participants to 
develop passive ownership arrangements that are purely financial. A 
passive ownership arrangement that is demonstrated to be purely 
financial could be relieved of the auditing requirement in this Rule.
    Active Ownership Interests in the RTO. We now turn to a discussion 
of active as opposed to passive ownership. Most commenters used the 
term ``active'' ownership interests to refer to ownership of voting 
securities that give the owner the ability to influence or control an 
RTO's operating and investment decisions. We adopt this definition for 
purposes of our discussion and will use the terms ``active'' and 
``voting'' interchangeably.
    Several commenters who were strong proponents of allowing high or 
unlimited voting interests by market participants argue that in the 
NOPR the Commission was wrong to focus on any particular ownership 
percentage. Instead, they contend that what really matters is ``actual 
control over the day to day affairs of the system, not some arbitrary 
ownership percent ownership test.'' 312 We agree that the 
independence of an RTO ultimately depends on who makes the 
decisions.313 But control of decisionmaking ultimately 
depends on who votes and how many votes each party has.
---------------------------------------------------------------------------

    \312\ CTA at 4.
    \313\ However, independence does not automatically guarantee 
that an RTO will be effective in providing non-discriminatory access 
to the grid. Independence must also be combined with adequate 
operational and legal authority in order for the RTO to provide non-
discriminatory access.
---------------------------------------------------------------------------

    Consequently, we do not think that the Commission can ignore market 
participants' ownership of voting interests in the RTO.314 
To do so would require us to presume that even though a market 
participant has the legal right to vote for its own commercial 
interests, it will choose to vote for the public interest (or the 
general interests of all market participants). Therefore, we conclude 
that ownership of voting interests does matter and we cannot remain 
agnostic about the ownership of voting interests in an RTO by 
individual market participants, their affiliates or classes of market 
participants.315
---------------------------------------------------------------------------

    \314\ In response to EEI's request for a clarification, we 
clarify that we are referring only to corporate or shareholder 
ownership in the RTO itself and not to ownership of transmission 
facilities under the RTO's operational control. The fact that such 
facilities are owned by market participants would not be a concern 
unless the owners retain legal rights and operational 
responsibilities that make it difficult for an RTO to provide non-
discriminatory transmission service to other market participants.
    \315\ This is not the first time that we have emphasized the 
importance of voting rights. In various cases dealing with voting 
shares and voting rules for ISOs, we required that proposed 
arrangements be reformed to assure that no individual market 
participant or class of market participants could dominate the 
decisions of stakeholder committees that advised the ISO's board. 
See New England Power Pool, 88 FERC para. 61,079 (1999); Central 
Hudson Gas and Electric Corp., et al., 88 FERC para. 61,229 (1999).
---------------------------------------------------------------------------

    a. Active Ownership by Individual Market Participants and 
Affiliates. A number of transmission customers argue that the cleanest 
solution would be an ``absolute prohibition'' on ownership of voting 
interests by any market participant 316 We agree that this 
would produce a high level of certainty that an RTO is truly 
independent and anything less than an absolute prohibition introduces 
some risk. However, if our goal is to encourage the voluntary creation 
of RTOs, we have to accept that current owners may not relinquish 
ownership or control of their transmission assets unless it is in their 
economic interests to do so. In order to create a viable, for-profit, 
regional transco, at least some current transmission owners must be 
willing to sell their transmission assets to a new transmission 
company. Many commenters point out that this voluntary action is not 
likely to happen if the current owners anticipate large capital gains 
taxes as a consequence of the sale. The solution, according to many 
commenters, is to allow current owners to retain some voting interests, 
some non-voting (i.e., passive) interests or both.
---------------------------------------------------------------------------

    \316\ See, e.g., APPA, Consumer Groups and South Carolina 
Authority.
---------------------------------------------------------------------------

    As with passive ownership, the Commission must balance two 
conflicting goals: the need to assure that any RTO will be truly 
independent; and of not creating disincentives for transmission owners 
to voluntarily relinquish ownership or control of their transmission 
assets. Against the backdrop of these two goals, the specific question 
that confronts us is how much ownership of active voting interests in 
RTOs should be allowed for market participants.
    Several investor-owned utilities urged us to allow current 
transmission owners to retain as much as 100 percent voting interest in 
new for-profit transcos. They argue that we allow 100 percent ownership 
combined with codes of conduct in the natural gas industry and there is 
no reason why this model should not also apply to a restructured 
electricity industry. We disagree with

[[Page 855]]

this recommendation. The two industries, while similar in some 
respects, also differ significantly in the degree of vertical 
integration. The electricity industry is starting with a much higher 
level of vertical integration. As we noted in our NOPR discussion of 
the complaints filed since the issuance of Order No. 888, it is 
difficult to monitor compliance with codes of conduct when there is 
substantial vertical integration (i.e., those who own generation and 
also own transmission). 317
---------------------------------------------------------------------------

    \317\ FERC Stats. and Regs. para. 32,541 at 33,704-14.
---------------------------------------------------------------------------

    Moreover, it is a very intrusive form of regulation and ultimately 
requires us to be ``chasing after conduct.'' If such regulation is to 
be effective, we have to be concerned with internal corporate 
organization and ``who spoke to whom in the company cafeteria.'' 
318 This is not light-handed regulation. Therefore, we see 
little value in replicating this model in the new world of RTOs.
---------------------------------------------------------------------------

    \318\ Id. at 33,714.
---------------------------------------------------------------------------

    It would be equally unworkable to adopt the recommendations of some 
transmission customers that we should allow no ownership of RTOs by 
market participants from the outset. While this is a clean solution and 
greatly reduces the need to monitor for discriminatory behavior, it 
also reduces the likelihood that many current transmission owners will 
voluntarily relinquish ownership or control of their transmission 
facilities. As a consequence, it is likely to produce significant 
delays in the creation of RTOs that can support more competitive 
markets that would benefit consumers. Therefore, the Commission has 
concluded that it is in the public interest to permit some ownership of 
RTOs by market participants for a transition period. Within five years 
of RTO approval, however, active ownership by market participants must 
end unless the RTO seeks, and the Commission approves, an extension. 
Any request for extension, including a request occasioned by changed 
circumstances, must demonstrate that the extension is consistent with 
the independence standard of this rule and is otherwise in the public 
interest.
    For the transition period, the Commission will establish a safe 
harbor of five percent for active ownership interests by market 
participants. We will allow any market participant to own up to five 
percent of an RTO's outstanding voting securities without the need for 
case-by-case review by the Commission. An active ownership interest at 
five percent or lower will be construed as not providing the owner with 
control.
    The Commission will carefully evaluate, on a case-by-case basis, 
proposals that involve an ownership percentage higher than five 
percent. In deciding whether to allow active ownership interests that 
exceed five percent, we will look at various factors including the 
voting interests held by other class members (i.e., other market 
participants with similar economic interests), the amount of passive 
ownership held by market participants, the degree of dispersion of 
voting interests among other market participants and the general 
public, and the rights retained by the owners as suppliers of 
facilities and services to the RTO. While there is no prohibition on 
RTO proposals that involve higher ownership percentages, it would 
heighten the concerns identified above and would require justification 
by the applicants to overcome these concerns.
    We note that other Federal regulatory agencies have chosen to use a 
five percent value in similar situations. The SEC employs a five 
percent value in deciding when one entity is an affiliate of another 
under PUHCA.319 The SEC also requires that any person who 
becomes a direct or indirect owner of more than five percent of any 
class of stock of a company must file a public statement with the SEC. 
In commenting on this latter requirement, the FCC observed that its 
purpose is ``to ensure that investors are alerted to potential changes 
in control * * * which confer on their holders the potential for 
influence or control.'' 320 Less than two months ago, the 
FCC established a five-percent ``voting share benchmark'' for assessing 
ownership interests in companies that are cable TV operators. In 
justifying its decision to stay with a five-percent value, the FCC 
noted that ``[t]here is a body of more recent academic evidence that 
tends to confirm our earlier conclusions, demonstrating that interest 
holders of [five percent] can likely exert considerable influence on a 
company's management and operational decisions.'' 321 The 
FCC concluded that ``ownership percentages starting at [five] percent 
can influence management polices.'' 322
---------------------------------------------------------------------------

    \319\ See 15 U.S.C. 79b(a)(11).
    \320\ Federal Communications Commission, In the Matter of 
Implementation of the Cable Television Consumer Protection and 
Competition Act 1999; Implementation of Cable Act Reform Provisions 
of the Telecommunications Act of 1996; Review of the Commission's 
Cable Attribution Rules, FCC LEXIS 5243, *53 (October 20, 1999) 
citing Securities and Exchange Commission v. Savoy Industries, Inc., 
587 F.2d 1149 (D.C. Cir. 1978), cert. denied, 440 U.S. 913 (1979).
    \321\ Id.
    \322\ Id.
---------------------------------------------------------------------------

    We recognize that this Commission has used higher percentages in 
other contexts. For example, in determining whether a company is an 
affiliate of a natural gas pipeline or an electric utility, we have 
applied a rebuttable presumption of control only when a utility or 
pipeline owns ten percent or more of the company's voting stock. As a 
general matter, since the success of RTOs will depend on both the 
perception and reality of independence, the Commission believes that 
caution requires us to allow only very limited voting interests by 
market participants. The Commission believes that a lower percentage is 
necessary in this instance because we allow other market participants 
with similar economic interests (i.e., members of the same class) to 
have voting interests. Therefore, we believe that it is appropriate to 
impose a lower cap to reduce the risk that owners with similar outside 
economic interests may create a voting bloc. If, after our initial 
approval, we find evidence that control over the RTO is being exercised 
by an individual market participant or a class of market participants, 
we will not hesitate to take appropriate action, including ordering one 
or more entities to divest their ownership interests in the RTO.
    The Commission recognizes that there are risks associated with 
allowing market participants to have any active ownership interests in 
an RTO. Even with a five percent active ownership interest, there is a 
risk that one or more market participants will be able to influence the 
RTO's decisionmaking process to the disadvantage of other market 
participants. Consequently, the RTO may fail to be an entity in which 
``the control of transmission operation is cleanly separated from power 
market participants.'' 323 Accordingly, we will require that 
all market participants divest themselves of any active ownership 
interests no later than five years after our approval of the RTO. We 
will consider requests for extensions to this ``sunsetting'' 
requirement on a case-by-case basis. Any request for extension, 
including a request occasioned by changed circumstances, will be 
granted if the requester demonstrates that the extension is consistent 
with the independence standard of this Rule and is otherwise in the 
public interest. We will also require that any RTO that proposes active 
ownership by a market participant must adopt a system of independent 
compliance auditing to ensure that the active voting interests held by 
an individual market participant or classes of market

[[Page 856]]

participants do not convey decisionmaking control.
---------------------------------------------------------------------------

    \323\ FERC Stats. & Regs. para. 32,541 at 33,718.
---------------------------------------------------------------------------

    b. Active Ownership by Classes of Market Participants. In the NOPR, 
we stated that ``[a]n RTO must have a decisionmaking process that is 
independent of control of any market participant or class of 
participants.'' 324 While we suggested a safe harbor of one 
percent ownership in voting securities by an individual market 
participant and its affiliates, we did not propose any specific cap on 
ownership of voting securities by a class of participants. Based on a 
review of the comments received, we have concluded that a policy on 
ownership by classes of market participants is necessary to ensure the 
independence of the RTO. Thus, we will review RTO proposals with 
respect to class ownership, considering potentially relevant factors 
such as voting interests held by other market participants or classes 
of market participants, the degree of passive ownership by market 
participants, the degree of dispersion of voting interests, and the 
rights retained by the owners as suppliers of facilities and services 
to the RTO. We recognize that this is a fact-specific determination 
that will require the Commission to evaluate, on a case-by-case basis, 
proposals that involve ownership by more than one market participant. 
We will adopt a benchmark of 15 percent class ownership. Our 
willingness to allow ownership by a class of participants that exceeds 
fifteen percent will depend on the particular circumstances of the 
filing (e.g., the presence of offsetting voting interests by another 
class of market participants with competing economic or commercial 
interests or proposals to sunset active ownership).325 
Moreover, intervenors may also advance arguments that a 15 percent 
class ownership is inappropriate under certain factual circumstances.
---------------------------------------------------------------------------

    \324\ Id. at 33,727.
    \325\ See Alliance Companies, supra note 48.
---------------------------------------------------------------------------

    Comments on this issue reflect widely divergent views. SRP 
criticizes the NOPR for failing to recognize that ``[a]n interest may 
be considered de minimis when viewed in isolation, could still result 
in effective control when aggregated for a group with common 
interests.'' SRP contends that while the Commission explicitly 
recognized the importance of classes in the NOPR, we failed to do 
anything about it. In contrast, FP&L and others argue that there is no 
need for any ownership caps for a group of market participants since 
they will often have conflicting interests. EEI echoes this point by 
observing that any ``coalitions'' are likely to be ``fragile, short-
lived and unlikely to result in a serious threat to the independence of 
the RTO.'' 326 It also contends that it will be difficult to 
keep track of ownership interests and to categorize market participants 
into specific groups with ``alleged common interests.'' Therefore, 
while EEI proposes a ten-percent cap on ownership interests in voting 
securities by individual market participants, it recommends that there 
be no cap on the ownership interests of any group of participants.
---------------------------------------------------------------------------

    \326\ EEI Reply Comments at 21.
---------------------------------------------------------------------------

    In several ISO orders, we rejected proposed governance arrangements 
because we concluded that the voting weights and rules given to classes 
or sectors of participants would allow transmission owners to dominate 
the decisionmaking process.327 We believe that the concerns 
that motivated these orders also hold true with respect to ownership of 
RTOs. It would make little sense to establish a policy on ownership by 
individual market participants and their affiliates while allowing five 
or six generators or marketers to group together to force an RTO to 
adopt a policy that favors their interests.
---------------------------------------------------------------------------

    \327\ See New England Power Pool, 88 FERC para. 61,079 (1999); 
Central Hudson Gas and Electric Corp., et al., 88 FERC para. 61,229 
(1999).
---------------------------------------------------------------------------

    The Commission is unpersuaded by the assertions that similarly 
situated market participants will not have a ``nexus of interests.'' 
While we recognize, for example, that individual generators may 
actively compete against each other for specific sales, this does not 
imply that there is a total absence of common economic interests among 
generators relative to marketers or distributors. If we were to accept 
this argument, it would require us to ignore the fact that the 
Commission routinely receives joint pleadings from non-affiliated 
parties with similar economic interests. Similarly, over the last two 
years, we have frequently observed various non-affiliated entities 
within ISOs voting as a bloc on issues where they have similar economic 
interests (e.g., existing generators voting against new generators who 
seek lower interconnection charges when they connect to the grid).
    There is a second reason why we believe it is necessary to review 
class or sector ownership of voting securities in RTOs. With ISOs, we 
have allowed sector or class representation on the advisory and 
technical committees that are charged with giving advice or making 
recommendations to non-stakeholder governing boards. We have accepted 
these arrangements even though the votes of some classes exceed 20 
percent because all other classes are represented and have roughly 
equal voting power. Thus, independence is achieved through a diffusion 
of voting power among all the affected classes. While this arrangement 
may work for ISOs that are typically non-profit and non-share 
corporations, we do not think it is viable option for RTOs that have 
ownership shares that must be purchased. In particular, we cannot 
assume that all affected classes of market participants will have the 
financial resources to purchase ownership interests that would 
guarantee them a vote at the table. Therefore, we cannot presume that 
there will be a balance of voting power as was the case for the ISOs. 
In the absence of such countervailing voting blocs, we believe that it 
is necessary to establish lower limits on the amount of voting shares 
that can be owned by members of any one class of market participants.
    Based on our experience to date, we do not think it is impractical 
to define classes of market participants with similar economic 
interests. This has been routinely done as part of the governance 
design in every one of the ISOs that we have approved. The Commission 
will not establish categories of classes in this Final Rule. Instead, 
we will allow each RTO to propose the classes that it believes are 
relevant to its region. However, we are inclined to define such classes 
broadly to avoid bypassing the class cap through narrowly defined 
classes.
    In addition, we will require independent compliance auditing to 
ensure that market participants that have ownership interests will not 
use these ownership interests to put other non-owner market 
participants at a competitive disadvantage.328
---------------------------------------------------------------------------

    \328\ See supra note 304.
---------------------------------------------------------------------------

    The auditing should be performed by individuals or organizations 
that are not affiliated with the owners or RTO. The auditors would have 
clear authority to obtain any information or data necessary to perform 
their audits, and they would have the right to report any findings and 
recommendations to the Commission without prior approval of the RTO or 
any of its owners/members. An initial audit should be performed two 
years after our approval of the RTO. This will be the only audit 
required for active ownership unless the RTO or the active owners 
request and receive approval for an extension of active ownership 
interests beyond five years. If such an extension is granted, then 
follow-up compliance audits must be performed at three year intervals,

[[Page 857]]

beginning with a three-year audit filed along with any request for 
extension.
    As we discussed above with respect to passive ownership, applicants 
will have a continuing obligation to inform the Commission of any 
changed circumstances regarding active ownership. Moreover, the 
Commission would expect auditing for compliance with the individual and 
class caps established at the time of RTO approval. Where feasible, the 
auditors would rely on publicly available information on ownership 
interests (e.g., SEC data sources). Where such information is not 
publicly available (e.g., individual ownership interests of less than 
five percent), the auditors should have the authority to obtain this 
information from market participants and their affiliates. Any market 
participant that wishes to have an ownership interest in an RTO must 
agree to provide this information to the auditor or the Commission upon 
request. We would expect that market participants will comply with both 
the individual and class caps at all times. If the auditor finds that 
either cap has been violated, it must notify the Commission and the 
affected owners immediately and also recommend a remedy.
    Since the caps do not guarantee a lack of control, the Commission 
expects that the auditors will also look for evidence of control over 
RTO decisionmaking at lower levels of ownership. These audit reports 
would be closely reviewed by the Commission and if there is evidence of 
abuse or unwillingness to cooperate with the auditors, the Commission 
will not hesitate to order owners to divest themselves of their active 
ownership interests.
    RTO Governing Boards. Many commenters urge us to impose specific, 
detailed requirements on RTO governance. Commenters make 
recommendations on many different aspects of governance: the 
desirability of stakeholder, non-stakeholder or hybrid boards, the size 
of boards, the relationship between non-stakeholder boards and 
stakeholder advisory groups, the number of classes for stakeholder 
boards, the appropriate voting entitlements for individual classes on a 
stakeholder board; and optimal voting rules. Most of the 
recommendations seemed to be targeted for RTOs that are ISOs. In the 
Final Rule, we have decided not to impose any specific requirements on 
RTO governing boards other than the general requirement that they must 
satisfy the overall principle that their decisionmaking process should 
be independent of any market participant or class of participants. We 
have opted not to impose more detailed governance requirements for 
three reasons.
    First, we anticipate that RTOs will take many different forms that 
reflect the needs and different starting points of each region. We 
expect to see proposals from ISOs, transcos and hybrids. It is unlikely 
that a single approach to governance will work for the different types 
of RTOs that are likely to emerge. At this early stage, it would be 
counterproductive to impose a ``one size fits all'' approach to 
governance when RTOs may differ significantly in structure and patterns 
of ownership.
    Second, our experience to date has been largely limited to 
reviewing governance proposals of ISOs that operate but do not own 
transmission facilities. A governance model that works for an ISO may 
not be appropriate for transcos or other types of for-profit 
transmission enterprises.
    Third, even among the ISOs, there are different models of 
governance. As we noted in the NOPR, the dominant governance model 
(PJM, New England, New York and the Midwest) for ISOs is a two-tier 
form of governance. The top tier consists of a non-stakeholder board, 
while the lower tier consists of advisory committees of stakeholders 
that may recommend options to the non-stakeholder board. Generally, the 
top tier has the final decisionmaking authority.329 In 
contrast, California, employs a decisionmaking board for its ISO that 
consists of both stakeholders and non-stakeholders representatives. And 
we note that the recently passed Texas restructuring law would require 
a pure stakeholder governing board for the ERCOT ISO. Given the variety 
of governance forms that exist or are proposed for ISOs and the limited 
experience with these different approaches, the Commission believes 
that it is premature to conclude that one form of governance is clearly 
superior to all other forms in every situation.
---------------------------------------------------------------------------

    \329\ One exception is the New York ISO where decisionmaking is 
explicitly shared by a non-stakeholder Board of Directors and 
stakeholder Management Committee. Modification of the ISO tariffs 
under the FPA requires approval of the ISO Board and the Management 
Committee. If they fail to agree on a modification, either the Board 
or the Management Committee may make a filing under FPA section 206. 
See Central Hudson Gas & Electric Corp., et al., 88 FERC para. 
61,138 (1999).
---------------------------------------------------------------------------

    Therefore, we will not mandate detailed governance requirements for 
RTO boards. Instead, the approach that we adopt in the Final Rule is 
that any RTO governance proposals, whether from an ISO, transco or a 
hybrid arrangement, will be judged on a case-by-case basis against the 
overarching standard that its decisionmaking process must be 
independent of individual market participants and classes of market 
participants.330
---------------------------------------------------------------------------

    \330\ We will require every ISO to submit an audit of the 
independence of its governance process two years after its approval 
as an RTO.
---------------------------------------------------------------------------

    While we are not imposing any other specific requirements, the 
Commission believes that it is appropriate to give some general 
guidance based on the governance arrangements that we have reviewed to 
date. Where there is a governing board with classes of market 
participants, we would expect that no one class would be allowed to 
veto a decision reached by the rest of the board and that no two 
classes could force through a decision that is opposed by the rest of 
the board. Where there is a non-stakeholder board, we believe that it 
is important that this board not become isolated. Both formal and 
informal mechanisms must exist to ensure that stakeholders can convey 
their concerns to the non-stakeholder board. Where there are 
stakeholder committees that advise or share authority with a non-
stakeholder board, it is important that there be balanced 
representation on the stakeholder committees so no one class dominates 
its recommendations or its decisions.
    We note that this general guidance is based on our experience with 
governance proposals of ISOs. The Commission recognizes that these 
observations may not be completely relevant for an RTO that intends to 
operate as a for-profit transmission company. Nevertheless, we 
emphasize that the common element for all types of RTOs must be that 
they satisfy the threshold principle that their decisionmaking should 
be independent of market participants.
    Role of State Agencies. We do not impose any specific requirements 
on the role of state agencies in RTOs. Such specificity would be 
counterproductive in light of the variation in the legal 
responsibilities of state commissions and RTO design across regions. 
However, we agree with NARUC that state commissions ``should fully 
participate in RTO formation and development.'' When we undertake our 
collaborative efforts with the industry after issuance of the Final 
Rule, we encourage state commissions and other state agencies to play a 
key role in this effort. State involvement is important for several 
reasons, especially where RTOs are a critical element of the retail 
choice programs of many states. State commissions are in a unique 
position to assess whether a particular RTO design will help or hinder 
their efforts to promote retail competition.

[[Page 858]]

    Once an RTO becomes operational, it appears that most states 
believe that it would be inappropriate for a state official, whether a 
state commission representative or some other state employee, to serve 
as a voting member of an RTO board. We note that NECPUC, representing 
the six New England state commissions, was joined by most other state 
commissions and commenters from other sectors of the industry in 
recommending that state officials should not be voting members of any 
RTO governing body. ISO-NE presents three reasons why it would be 
problematic for a state official to serve as a voting member of an RTO 
governing board. First, it would create a conflict between the state 
official's duties as an RTO board member and his or her regulatory or 
legal responsibilities at the state level. Second, in the case of a 
multi-state RTO, it would be difficult for an official of one state to 
represent the interests of others states if the state interests are in 
conflict. Third, the solution of allowing each state to have its own 
voting member on the RTO board could lead to large and unwieldy boards 
for multi-state RTOs.
    While most commenters agreed that state officials should not serve 
as voting members of RTO boards, most of these same commenters were 
comfortable with allowing state officials to serve as ex officio 
members. It was thought that state officials would be better informed 
in making their own decisions if they could closely observe the 
considerations and constraints that were weighed by the RTO in making 
its decisions. It was thought that the ability of state officials to 
observe the RTO's decisionmaking process would be especially useful if 
the RTO had to recommend one or more expansions to the existing grid.
    While we see considerable merit in the arguments that state 
officials should not be voting members of an RTO governing board (and 
note that most state commissions share this view), the Commission is 
not imposing such a prohibition. Since RTOs do not yet exist, it would 
be premature to conclude that state officials should not participate as 
voting members of RTO boards. There may be special circumstances in 
some regions that would make it in the public interest to give voting 
rights to one or more state government representatives. Therefore, we 
will be willing to entertain such proposals and perhaps revisit the 
issue after we gain more experience.
    Section 205 Filing Rights. In the NOPR, we proposed that the RTO 
must have exclusive and independent authority to file changes in its 
transmission tariff under section 205 of the Federal Power Act. This 
proposal triggered hundreds of pages of comments. Upon consideration of 
the comments received, as discussed below, we will modify our proposal, 
in part, to make clear that transmission owners who do not also operate 
their transmission facilities retain certain section 205 rights.
    Most commenters on this issue fall into two categories. Those who 
oppose the proposal in the NOPR argue that it is bad law and bad 
policy. They contend that the Commission does not have the legal 
authority to grant section 205 rights over their transmission 
facilities to some other entity. While a transmission owner may 
voluntarily cede this right to an RTO, they argue that the Commission 
cannot compel a transmission owner, either directly or indirectly, to 
give up this legal right. Many transmission owners, representing IOUs, 
public and cooperative systems, argue that the transfer of this right 
to an RTO would increase their risk of recovering revenues to which 
they are lawfully entitled. On the other hand, those who support the 
proposal argue that it is a necessary and logical implication of our 
previously stated policy that the ``[a]uthority to act unilaterally * * 
* is a crucial element of a truly independent transmission provider.'' 
331 They contend that an RTO will not be able to function as 
an independent and neutral transmission provider if it has to seek the 
approval of transmission owners or other market participants every time 
it wishes to modify its tariff. They point to numerous tariff changes 
that the various ISOs have had to make as real world evidence of their 
need to move quickly and make filings at the Commission when they 
encounter a tariff problem that needs to be corrected.
---------------------------------------------------------------------------

    \331\ New England Power Pool, 70 FERC para. 61,374 at 62,585 
(1997).
---------------------------------------------------------------------------

    Based on the comments received, we reaffirm our determination 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. This determination, 
however, is subject to several important clarifications discussed 
below.
    We recognize that for some RTOs (in particular, ISOs), both the 
transmission owners and the RTO will be public utilities with respect 
to the same transmission facilities,332 i.e., one or more 
entities will own the facilities and a different entity will operate 
the facilities and actually sell the transmission provided by the 
facilities, and that this presents a somewhat unusual situation insofar 
as sections 205 and 206 of the FPA are concerned. The FPA does not 
explicitly address who has filing authority or responsibility in this 
circumstance. We conclude that while the RTO must have independent and 
exclusive authority to propose changes in the rates, terms and 
conditions of transmission service provided over the facilities it 
operates, it also is reasonable for the transmission owners to retain 
certain independent section 205 filing rights with respect to the level 
of the revenue requirement that the transmission owners receive from 
the RTO and that the RTO, in turn, will collect from the transmission 
customers through its rates. We therefore clarify that a transmission 
owner must have independent authority to set the level of its portion 
of the revenue requirement to be collected by the RTO.333
---------------------------------------------------------------------------

    \332\ Under FPA section 201(e), a public utility is any person 
who owns or operates jurisdictional facilities.
    \333\ Of course, a transmission owner may voluntarily agree to 
relinquish this right during the RTO negotiation process or 
subsequently.
---------------------------------------------------------------------------

    Importantly, we further clarify that we expect the authorities of 
the transmission owners and the RTO to be exercised as follows. The 
transmission owners may make section 205 filings to establish the 
payments that the RTO will make to the transmission owners for the use 
of the transmission facilities that are under the control of the RTO; 
the RTO, in turn, will make section 205 filings to recover from 
transmission customers the cost of the payments it makes to 
transmission owners as well as its own costs, and propose any other 
changes in the rates, terms and conditions of service to transmission 
customers. Thus, the transmission owners may have on file a tariff that 
assures their recovery of transmission revenues from the RTO and, while 
they may be affecting the level of the RTO's revenue requirement, they 
will not be permitted to make section 205 filings for RTO services to 
transmission customers and will not interfere with the independence of 
the RTO to file proposed changes to the open access 
tariff.334
---------------------------------------------------------------------------

    \334\ We note that some existing ISOs have adopted an approach 
where the transmission owners' revenue requirement is filed with the 
Commission in a separate transmission rate filing (e.g., California 
ISO), while others incorporate the revenue requirement of the 
transmission owners, as changed from time to time, in the ISO's 
tariff. In either case, only the ISO is authorized to make filings 
that change the tariff sheets in the ISO's tariff.

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

[[Page 859]]

    We believe this division of filing rights reflects a reasonable 
interpretation of the FPA as applied to these circumstances, and that 
it appropriately balances the need to ensure the independence of the 
RTO with the need to provide transmission owners the opportunity to 
recover revenues. To avoid unnecessary disputes and coordinate the 
interaction of these independent section 205 filings, we will require 
the RTO and the transmission owners to give prior notice to each other 
of any planned section 205 filings. Further, we strongly encourage 
transmission owners and RTOs to resolve rate issues prior to the filing 
of proposed rate changes.
    We recognize that the division of filing rights described above may 
not be the only way to accommodate the concerns raised. Accordingly, 
the Commission will entertain other approaches 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. The Commission will require RTOs to 
provide a detailed description of the process to allow us to assess its 
fairness and workability.
2. Scope and Regional Configuration (Characteristic 2)
    The NOPR proposed as the second minimum characteristic of an RTO 
that the RTO must serve an appropriate region--a region of sufficient 
scope and configuration to permit the RTO to effectively perform its 
required functions and to support efficient and nondiscriminatory power 
markets.353 The NOPR noted that there is likely no one 
``right'' configuration of regions and proposed to establish a set of 
factors that encourage appropriate regional configuration without 
prescribing boundaries. The NOPR suggested that a region that is large 
in scope would facilitate the effective performance of many of the 
RTO's functions, but also recognized that there may be factors that 
might limit how large an RTO should be.336 The NOPR also 
proposed a set of factors that may affect the location of regional 
boundaries. These factors indicate that boundaries should facilitate 
essential RTO functions and goals, recognize trading patterns, mitigate 
the exercise of market power, do not unnecessarily split existing 
control areas or existing regional transmission entities, encompass 
contiguous geographic areas and highly interconnected portions of the 
grid, and take into account useful existing regional boundaries (such 
as NERC regions) and international boundaries. The NOPR put forth for 
discussion the appropriateness of existing configurations, such as the 
three electric interconnections within the continental United States, 
the ten NERC reliability councils, and the 23 NERC security coordinator 
areas.
---------------------------------------------------------------------------

    \335\ FERC Stats. and Regs. at 33,729.
    \336\ Id. at 33,730.
---------------------------------------------------------------------------

    The NOPR also requested comments on what portion of the 
transmission facilities within an appropriate region the RTO must 
control in order to be approved as an RTO. The Commission recognized 
that it might be difficult to obtain 100 percent participation of all 
transmission owners within a region, but that, on the other hand, it 
would not be appropriate to approve an RTO proposal that included only 
a small portion of the facilities of the region. The Commission also 
requested comments on how much deference the Commission should give to 
regions proposed to us, and to what extent state commission approval or 
disapproval should be taken into account.
    a. How Should Initial Boundaries be Established? Comments. Most 
commenters agree with the Commission's proposal not to initially 
prescribe the boundaries for appropriate regions.337 Among 
the rationales asserted by these commenters is that this is a matter 
best left in the first instance to the stakeholders in the various 
regions,338 there should be deference to proposals by 
transmission owners and market participants,339 FERC should 
give deference to state commissions on scope and 
configuration,340 boundaries should be determined naturally 
in a way that facilitates market transactions,341 and size 
and configuration must be determined on a case-by-case 
basis.342
---------------------------------------------------------------------------

    \337\ See, e.g., South Carolina Authority, Cleco, SRP, LG&E, 
Detroit Edison, Wyoming Commission, Entergy, UtiliCorp, NECPUC, 
MidAmerican, Enron/APX/Coral Power, Duke, NASUCA, Industrial 
Consumers, Connectiv, Massachusetts Division, Iowa Board.
    \338\See, e.g., South Carolina Authority, NASUCA, Florida Power 
Corp.
    \339\ See, e.g., Entergy, MidAmerican.
    \340\ See, e.g., Southern Company, NECPUC, Nine Commissions, 
Florida Commission.
    \341\ See, e.g., Duke, FirstEnergy, Allegheny, Iowa Board.
    \342\ See, e.g., NYPP.
---------------------------------------------------------------------------

    However, some commenters argue that the Commission should prescribe 
regional boundaries. APPA, East Texas Cooperatives, TDU Systems and the 
Michigan Commission urge that the Commission use section 202(a) 
authority to establish initial boundaries. APPA asserts that the 
Commission should establish a rebuttable presumption in favor of 
specific regional district boundaries based on the topology of the 
transmission network to enhance system security. East Texas 
Cooperatives argues that after the Commission established regional 
districts, the burden would be on those proposing different regions to 
show that they provide at least the benefits of the prescribed 
districts. Michigan Commission states that the electricity market is 
currently too immature to determine by itself the size of the markets, 
and that firm guidance is needed rather than allowing the RTO 
boundaries to be set by participants.
    Several other commenters do not go as far in asserting that the 
Commission should initially set boundaries, but argue that the 
Commission should take a strong role in assuring proper boundaries. For 
example, Cinergy urges that the Commission be aggressive in 
establishing boundaries consistent with the proposed criteria, noting 
that the willingness of the Commission to exercise its authority over 
boundaries will determine the success of the Commission's restructuring 
efforts. Coalition of Alliance Users maintains that the Commission 
should take a direct and active role in formulating RTO boundaries. 
WEPCO believes that the role of the Commission should be to set 
criteria that encourage the establishment of sensible RTO boundaries. 
Project Groups assert that if the stakeholders in a region do not 
determine boundaries by the end of 2000, the Commission should make the 
determinations. LG&E states that while the Commission should show 
deference to voluntary RTOs, it should not hesitate to disapprove 
proposals with geographic shortcomings.
    Commenters express a variety of views regarding whether particular 
regional configurations would be appropriate. Some commenters support 
interconnection-wide RTOs as a desirable goal,343 while 
others regard either an Eastern or Western interconnection RTO as 
unworkably large. 344
---------------------------------------------------------------------------

    \343\ See, e.g., South Carolina Authority, Conlon, Industrial 
Consumers, First Rochdale, Los Angeles, PG&E, Sonat.
    \344\ See, e.g., South Carolina Authority, Desert STAR, 
MidAmerican, TDU Systems, CREDA, SNWA, CRC, Platte River, PSNM, SRP, 
Metropolitan.
---------------------------------------------------------------------------

    Commenters offer specific ideas about the number and placement of 
RTOs. PG&E states that the long-term goal should be four or five RTOs 
nationwide.

[[Page 860]]

Williams argues for 3 to 10 RTO nationwide, while Project Groups 
advocates 3 to 12 RTO nationwide. WEPCO proposes the formation of five 
RTOs: (1) three in the Eastern interconnection (one covering MAPP, 
MAIN, ECAR and portions of SPP; one covering SERC, Florida and the rest 
of SPP; and one covering NPCC and MAAC); (2) one for WSCC; and (3) one 
for ERCOT. APPA, supported by East Texas Cooperatives, suggests: (1) no 
more than three RTOs in the West; (2) the combination of PJM, NY ISO 
and ISO-NE into one RTO with the possible participation of Ontario; (3) 
the combination of the Alliance RTO, Midwest ISO, and MAPP into one 
RTO; (4) Kansas to the Carolinas under one RTO; and (5) separate RTOs 
for Florida, ERCOT and Hydro-Quebec.
    With respect to specific regions, ISO-NE contends that it already 
operates a region of appropriate size and configuration. Mass Companies 
agrees that ISO-NE is an appropriate region. NYC argues that the 
formation of a northeastern RTO with a broader geographic scope than 
the NY ISO would help remove existing institutional impediments to the 
construction of new transmission lines. American Forest argues that PJM 
is too small, while NASUCA and Mid-Atlantic Commissions believe that 
PJM satisfies the size criteria. Some commenters object to a split 
between the area represented by the proposed Alliance RTO and the 
Midwest ISO.\345\ Most of the Florida commenters assert that peninsular 
Florida represents an appropriate region.\346\ For example, Florida 
Commission claims that peninsular Florida is a large and efficient 
marketplace that does not share parallel flows with other electrical 
regions; however, it states that the Florida panhandle could be in a 
region with all of SERC or a subregion of SERC.
---------------------------------------------------------------------------

    \345\ See, e.g., Michigan Commission, South Carolina Authority, 
Midwest ISO, Midwest ISO Participants, NASUCA.
    \346\ See, e.g., Florida Commission, JEA, FP&L, Florida Power 
Corp., Tallahassee, Gainesville.
---------------------------------------------------------------------------

    Although some commenters encourage a Western interconnection-wide 
RTO, the majority of commenters support three or four RTOs for the 
Western interconnection, noting that the interests in the WSCC are too 
diverse and the area too large for control by a single entity.\347\ Cal 
ISO contends that California satisfies the minimum size criteria, but 
does not represent the maximum feasible area. Commenters from the 
Pacific Northwest generally agree that a region including Washington, 
Oregon, and all or portions of Idaho and Montana is distinct enough to 
warrant an RTO limited to that area.\348\ CREDA and Platte River 
envision one RTO for the Pacific Northwest, one for California and one 
for the Rocky Mountain/Desert Southwest area; CRC suggests a similar 
alignment, with the exception of the Rocky Mountain and Southwest areas 
as separate RTOs.
---------------------------------------------------------------------------

    \347\ See, e.g., SRP, Metropolitan.
    \348\ See, e.g., Seattle, PGE, Industrial Customers, BC Hydro, 
Powerex, Tacoma Power, PNGC.
---------------------------------------------------------------------------

    A number of commenters make the point that, regardless of where RTO 
boundaries are drawn, it is important that there be integration and 
coordination among RTOs.\349\ NERC believes that there are two seams 
issues: reliability practices across seams and market practices across 
seams. TDU Systems suggests that there be a set of regions for 
reliability/operations purposes within a larger region for rates and 
scheduling. Industrial Consumers state that, if multiple RTOs are 
formed within an interconnection, RTOs should be required to coordinate 
their operations to collectively ``simulate'' an interconnection-wide 
RTO. Cinergy suggests that, if there were more than one RTO in a large 
interconnection, a ``super'' RTO could be established to operate and 
coordinate inter-RTO activities. Montana Commission states that RTO 
boundaries are less important than ensuring that seams do not interfere 
with the market, and proposes, as do others such as Ontario Power and 
CMUA, that the Commission require adjacent RTOs to embody consistent 
methods of access, pricing, and congestion management to encourage 
seamless trading. PacifiCorp asserts that reciprocity agreements among 
RTOs may be easier to achieve than having all parties in a large region 
agree to one RTO. Allegheny suggests that appropriate transmission 
pricing could provide some of the same benefits as a large RTO.
---------------------------------------------------------------------------

    \349\ See, e.g., South Carolina Authority, SPP.
---------------------------------------------------------------------------

    Several commenters express concern that multiple RTO proposals for 
the same region will be submitted. Indiana Commission contends that the 
NOPR leaves the door open for more than one RTO proposal for 
approximately the same wholesale power market region and this could 
limit the operational efficiency and increase the cost of transmission 
in the region. It suggests that the Commission consider requiring 
formal mediation or play an assertive role in such circumstances. 
Snohomish suggests favoring the RTO proposal that is negotiated 
pursuant to the most open process that included consumers, transmission 
dependent utilities and others with a vital interest in the effective 
and efficient operation of the transmission grid. Midwest ISO 
Participants submit that the proponents of multiple RTOs meet a heavy 
burden and demonstrate the need for more than one RTO. In particular, 
it would require demonstration that the proposals: do not balkanize the 
market; allow for effective congestion relief; maintain reliability; 
facilitate construction of new transmission facilities; and allow for 
effective tariff administration and unbiased ATC determination 
throughout the region.
    Commission Conclusion. We adopt the NOPR proposal on this 
characteristic. All RTO proposals filed with us must identify a region 
of appropriate scope and configuration. The scope and configuration of 
the regions in which RTOs are to operate will significantly affect how 
well they will be able to achieve the necessary regulatory, 
reliability, operational, and competitive benefits.
    As proposed in the NOPR, we will not at this time prescribe initial 
boundaries for RTOs. Section 202(a) of the FPA does give us the 
authority, after consultation with state commissions, to fix and modify 
boundaries for regional districts for the voluntary interconnection and 
coordination of facilities. We acknowledge those commenters who believe 
that it may be more efficient for the Commission to establish at least 
a rebuttable presumption that particular boundaries are appropriate 
starting points. However, we conclude, as a matter of policy, that we 
should not attempt to draw boundaries at this time. We are convinced 
that the transmission owners, market participants, and regulators in a 
particular region have a better understanding of the dynamics of the 
transmission system in that region, and that they should, at least in 
the first instance, propose the appropriate scope and regional 
configuration of an RTO. There are many technical considerations 
involved in discerning the appropriate scope and regional configuration 
of an RTO, and we believe that those most familiar with such 
considerations in a region are in a better position to propose a 
workable solution.
    As noted above, some commenters advocate that the NERC regions be 
starting points; others advocate that the Interconnections be the goal; 
and still others propose specific configurations that would divide the 
Nation as many as three to 12 RTOs. Consistent with our decision to let 
the parties take the initiative to propose what is appropriate for 
their region, we will not specifically

[[Page 861]]

endorse any particular scheme for RTO configuration.
    This is not to say, however, that we will deem appropriate any 
regional configuration proposed. As stated in the regulatory text for 
this characteristic, an appropriate region is one of sufficient scope 
and configuration to permit the RTO to effectively perform its required 
functions and to support efficient and nondiscriminatory power markets. 
A proposed RTO could simply be too limited to satisfy several of the 
necessary functions. Further, we are aware that transmission owners 
could seek to gain strategic advantage by the way an RTO is formed. For 
example, an RTO could be placed to act as a toll collector on a 
critical corridor.\350\ An RTO could propose a configuration that 
interferes with the formation of a larger, more appropriately 
configured RTO.
---------------------------------------------------------------------------

    \350\ See Statement of Ohio Commission Chairman Craig Glazer, 
RTO Conference (St. Louis), transcript at 85-87.
---------------------------------------------------------------------------

    As we review a proposal by a regional transmission entity for its 
scope and regional configuration, if we determine that the scope is 
inappropriate, that entity will not be deemed to be an RTO, and its 
participants will not be deemed to be RTO participants.\351\ In 
response to the commenters questioning what the Commission would do if 
it received multiple RTO proposals for a region, we note that we hope 
the collaborative process we are encouraging in this Final Rule would 
foreclose that circumstance. However, if we are faced with multiple 
proposals, we would have to determine which RTO proposal best meets the 
objectives of this Rule.
---------------------------------------------------------------------------

    \351\ The proposal could be accepted, however, as something less 
than an RTO that represents an improvement over the status quo.
---------------------------------------------------------------------------

    As we stated in the NOPR, we are aware that there is likely no one 
``right'' configuration of regions. One particular boundary may satisfy 
one desirable RTO objective and conflict with another. We recognize 
here, and elsewhere in this Final Rule,\352\ that the industry will 
continue to evolve, and the appropriate regional configurations will 
likely change over time with technological and market developments. The 
Commission is also mindful of the interests of individual states 
regarding RTO boundaries. Given all these considerations, the 
Commission believes that the public interest will best be served if we 
provide guidance in this Final Rule, in the form of factors that affect 
appropriate regional configuration, without actually prescribing 
boundaries.
---------------------------------------------------------------------------

    \352\ See section F on Open Architecture.
---------------------------------------------------------------------------

    b. Scope and Configuration Factors. Comments. A large number of 
commenters agree that the factors listed in the NOPR for determining a 
proper scope and configuration for an RTO are generally 
appropriate.\353\ Industrial Consumers propose that the factors be 
codified as part of our regulations. Florida Commission, on the other 
hand, argues that the factors should not be mandated as part of the 
Commission's regulations.
---------------------------------------------------------------------------

    \353\ See, e.g., UtiliCorp, Desert STAR, Midwest ISO 
Participants, Metropolitan, NECPUC, LG&E, PJM/NEPOOL Customers, 
Midwest Municipals, Industrial Consumers, Dairyland, TDU Systems, 
ISO-NE, Midwest Energy, APX, APPA, Cal ISO.
---------------------------------------------------------------------------

    Many commenters argue that the RTO region should be as large as 
possible, i.e., bigger is better.\354\ Several commenters suggest the 
minimum size should be the NERC regions.\355\ Conlon suggests a minimum 
area should be one containing a load of 50,000 MW. PJM states that its 
organization demonstrates that a very large RTOs is feasible, in that 
it manages a grid serving more than 57,000 MW of generation and 
containing more than 8,000 miles of high voltage transmission lines. 
PJM states that even larger control areas are possible as technology 
advances. PJM/NEPOOL Customers, claiming that all potential factors 
that might limit size can be overcome, argue that the Commission should 
not conclude that there are factors that limit size. As discussed below 
with respect to the congestion management function, some commenters 
make a particular point of emphasizing the importance of large scope to 
effective congestion management.\356\
---------------------------------------------------------------------------

    \354\ See, e.g., Cinergy, American Forest, EPSA, UtiliCorp, 
PG&E, NSP, Pennsylvania Commission, NJBUS, LG&E, Enron/APX/Coral 
Power, NASUCA, PJM/NEPOOL Customers, Cal ISO, Texas Commission, 
Conlon, Dynegy, Nine Commissions, Michigan Commission, Lincoln, 
WPSC, First Rochdale, East Texas Cooperatives, Los Angeles, Ohio 
Commission, EME, Ontario Power, H.Q. Energy Services, Ogelthorpe, 
UMPA, PG&E, Indiana Commission.
    \355\ See, e.g., Cinergy, WPSC, Lincoln, Ohio Commission, PG&E.
    \356\ See, e.g., LG&E, ComEd, Midwest ISO Participants, Midwest 
ISO.
---------------------------------------------------------------------------

    Other commenters argue that bigger is not necessarily better and 
that there are factors that limit size.\357\ CMUA argues that the role 
of security coordinator and operational characteristics of a region may 
limit geographic scope. STDUG claims that size breeds inefficiency. 
Several commenters claim that requiring maximum scope upon creation may 
discourage RTO formation or make it more costly and take longer to 
achieve.\358\ NYPP expresses concern that, if an RTO is too large, it 
may not be able to handle local reliability issues. Other commenters 
believe that the ability to plan new transmission facilities may limit 
scope.\359\ AEPCO expresses concern that the voice of smaller 
participants could be lost in a larger RTO. Florida Power Corp. claims 
that there may be a security risk associated with concentrating control 
of too large an area into a single facility, and that large areas of 
non-pancaked rates may eliminate incentives for proper generator siting 
decisions. A number of commenters believe that either the Eastern 
interconnection or the Western interconnection is too large an area to 
be controlled by one RTO.\360\ New York Commission argues that the 
Commission should recognize that experience must be gained in stages 
before an RTO encompassing an entire interconnection can be 
implemented. Several commenters in the Pacific Northwest cite the 
failed attempt to create IndeGo as evidence that trying to create too 
large an RTO is unworkable, and at some point ``bigger'' creates more 
problems than it solves.\361\
---------------------------------------------------------------------------

    \357\ See, e.g., AEPCO, Tallahassee.
    \358\ See, e.g., Enron/APX/Coral Power, FirstEnergy, Tri-State.
    \359\ See, e.g., Dairyland, Minnesota Power.
    \360\ See, e.g., South Carolina Authority, Desert STAR, 
MidAmerican, TDU Systems, CREDA, SNWA, CRC, Platte River, PSNM, SRP, 
Metropolitan.
    \361\ See, e.g., Industrial Customers, Powerex, Tacoma Power.
---------------------------------------------------------------------------

    Some commenters offer subjective parameters for the scope of an 
RTO. For example, SNWA proposes that the RTO be large enough to 
accommodate as many market participants as possible, but not so large 
as to be overly burdensome to manage. SRP argues that a balance must be 
struck between an RTO that is too small to cover a meaningful wholesale 
power market and one that is too large to form and operate effectively. 
TDU Systems argue that RTOs should comprise the largest regions that 
could operate in a coordinated fashion within a short period of time 
with reasonable investments of funds.
    A number of commenters emphasize particular factors that they 
consider important in determining scope and configuration. Some 
commenters assert that reliability and system security should be the 
primary determinant of scope and configuration.\362\ Others place prime 
importance on trading patterns and facilitating market 
transactions.\363\ EEI states that the most efficient size and 
configuration of an RTO should be left to the market to determine. 
Other commenters propose electrical

[[Page 862]]

configuration and physical power flows as important factors.\364\ CREDA 
and Desert STAR argue that the preservation of a Federal Power 
Marketing Administration project marketing area is an important 
consideration. Chelan argues that cost shifts need to be considered in 
determining scope. Platte River contends that established security 
coordinators should be a factor. Southern Company argues that joint 
ownership agreements should be a factor. Tacoma Power claims that 
traditional business relationships and social and political commonality 
are factors that affect scope.
---------------------------------------------------------------------------

    \362\ See, e.g., CMUA, APPA, Florida Commission, Minnesota 
Commission.
    \363\ See, e.g., UtiliCorp, Reliant, Duke, South Carolina 
Commission, NU, Florida Power Corp., Detroit Edison.
    \364\ See, e.g., South Carolina Authority, Williams, NSP, 
Dynegy.
---------------------------------------------------------------------------

    Commenters are divided on whether points where transmission 
facilities are constrained should be used as an RTO boundary or 
internalized within an RTO. Some commenters claim that constraints 
should be internalized to the extent possible and not constitute 
boundaries between regions.365 NERC states that boundaries 
should not be placed at weak interconnections because a single entity 
is better able to strengthen them. On the other hand, other commenters 
believe that constrained facilities should constitute the boundaries, 
either because they may form a natural boundary between robust systems 
or because it makes more sense to internalize markets than to 
internalize constraints.366 APPA states that, because it is 
not possible to internalize all constraints, the goal should be to 
alleviate or mitigate the effects of interregional constraints through 
additional construction and RTO operating rules and pricing policies. 
NECPUC argues that it does not matter where constraints are if 
compatible methods of locational pricing are adopted by contiguous 
RTOs. MidAmerican and Duke assert that constraints are not natural 
boundaries between regions because the location of points of constraint 
change over time as market conditions change. Several commenters, such 
as Dairyland and Desert STAR, take the position that the issue whether 
to design RTO boundaries at constrained interfaces cannot be stated 
generically, and must be decided on a case-by-case basis.
---------------------------------------------------------------------------

    \365\ See, e.g., Industrial Consumers, First Rochdale, Minnesota 
Power, STDUG, NARUC.
    \366\ See, e.g., Ohio Commission, EAL, Florida Power Corp.
---------------------------------------------------------------------------

    Commission Conclusion. The factors we believe should be used to 
develop appropriate regions are set out here and called regional 
configuration factors. These cover such considerations as how large a 
region should be and how boundaries should be evaluated. We do not see 
a benefit to placing them in regulatory text, as suggested by one 
commenter, and we will not do so. The factors are intended as guidance 
and, as such, must necessarily be applied flexibly.
    Regional Configuration Factors. As stated above, the principal 
consideration in evaluating the appropriate scope of an RTO is that 
such scope must permit the RTO to perform its functions effectively. As 
we stated in the NOPR, many of the characteristics and functions for an 
RTO proposed in this section suggest that the regional configuration of 
a proposed RTO should be large in scope.367 For example:
---------------------------------------------------------------------------

    \367\ This reiterates the conclusion we reached in the eleven 
ISO principles in Order No. 888, where we stated that ``[t]he 
portion of the transmission grid operated by a single ISO should be 
as large as possible.'' Order No. 888, FERC Stats. & Regs. para. 
31,036 at 31,731.
---------------------------------------------------------------------------

     Making accurate and reliable ATC determinations: An RTO of 
sufficient regional scope can make more accurate determinations of ATC 
across a larger portion of the grid using consistent assumptions and 
criteria.
     Resolving loop flow issues: An RTO of sufficient regional 
scope would internalize loop flow and address loop flow problems over a 
larger region.
     Managing transmission congestion: A single transmission 
operator over a large area can more effectively prevent and manage 
transmission congestion.
     Offering transmission service at non-pancaked rates: 
Competitive benefits result from eliminating pancaked transmission 
rates within the broadest possible energy trading area.
     Improving Operations: A single OASIS operator over an area 
of sufficient regional scope will better allocate scarcity as regional 
transmission demand is assessed; promote simplicity and ``one-stop 
shopping'' by reserving and scheduling transmission use over a larger 
area; and lower costs by reducing the number of OASIS sites.
     Planning and coordinating transmission expansion: 
Necessary transmission expansion would be more efficient if planned and 
coordinated over a larger region.
    We note that the comments on this issue express a range of views. 
Many commenters assert that the bigger the RTO is the better, and that 
there really are no serious limitations to RTOs representing loads as 
large as several hundred thousand megawatts. Other commenters suggest a 
number of considerations that may militate against RTOs that are too 
large, including the role of security coordinator, operational 
characteristics, costs of formation, local reliability issues, and the 
effect on smaller participants. In the NOPR, we recognized that there 
may be a limitation on how many facilities or transactions can be 
overseen reliably by a single operator, imposed either by hardware 
design or costs, or imposed by human limitations to process the 
required amount of information. We further recognized that the 
difficulty and cost of transferring operational control over many 
transmission systems to one RTO may affect regional configuration. We 
also noted that, as regions get larger and involve more existing owners 
of transmission, reaching consensus on an appropriate transmission rate 
design for the region may prove challenging.
    We note that a number of commenters make the point that, at least 
for some purposes and functions, the scope of an individual RTO is less 
important if it is part of a group of RTOs that have adequately 
eliminated the negative effects of ``seams'' between itself and the 
other RTOs. NERC identifies two seams issues: reliability practices 
across seams and market practices across seams. We further note that 
other commenters suggest that large RTOs could be ``simulated'' through 
coordinated operations and consistent methods of access, pricing, and 
congestion management, and that there may be different acceptable 
scopes for reliability and operations purposes on one hand, and rates 
and scheduling on the other.368 We also detect a common 
theme that runs through a number of comments: large geographic size is 
most important for trading areas. Thus, the concept of large ``seamless 
trading areas'' for power emerges as a ``scope'' issue that is distinct 
from the scope of the region for organizing the transmission functions 
of an RTO.
---------------------------------------------------------------------------

    \368\ In a recent conference to address interregional ISO 
coordination in the northeast, the three northeast ISOs (ISO New 
England, New York ISO, and PJM ISO) and other market participants 
discussed current and future coordination efforts among the ISOs 
intended to simplify market transactions and enhance reliability in 
the northeast. See http//www.dps.state.ny.us/isoconf.htm.
---------------------------------------------------------------------------

    We conclude that a large scope is important for an RTO to 
effectively perform its required functions and to support efficient and 
nondiscriminatory power markets. Adequate scope is not necessarily 
determined by geographic distance alone; other factors include the 
numbers of buyers and sellers covered by the RTO, the amount of load 
served, and the number of miles of transmission lines under operational 
control. The scope must be large enough to achieve

[[Page 863]]

the regulatory, reliability, operational and competitive objectives of 
this Rule.
    We are receptive to flexible and innovative ways for an RTO to 
achieve sufficient scope. Where a proposed regional transmission entity 
may be of sufficient scope for some RTO purposes, but not others, an 
RTO may be able to achieve sufficient ``effective scope'' by 
coordination and agreements with neighboring entities, or by 
participating in a group of RTOs with either hierarchical control or a 
system of very close coordination. We do not foreclose the possibility 
that an RTO may satisfy some of the minimum characteristics and 
functions by itself, while satisfying others through a strong 
cooperative agreement with neighboring RTOs to create a ``seamless 
trading area.'' The functions of a large RTO may be met by eliminating 
the effect of seams separating smaller RTOs through a contract or other 
coordination arrangement. One of our concerns about an RTO's scope is 
that the existing impediments to trade, reliability, and operational 
efficiency be eliminated to the greatest extent possible. However, an 
RTO application that proposes to rely on ``effective scope'' to satisfy 
Characteristic 2 must demonstrate that the arrangement it proposes to 
eliminate the effect of seams is the practical equivalent of 
eliminating the seams by forming a larger RTO.
    Factors for Evaluating Boundaries. In addition to the factors 
affecting the size of a region, other factors may affect the 
delineation of regional boundaries. As stated in the NOPR, the 
Commission proposed that RTO boundaries be drawn so as to facilitate 
and optimize the competitive, reliability, efficiency and other 
benefits that RTOs are intended to achieve, as well as to avoid 
unnecessary disruption to existing institutions. The Commission 
proposed in the NOPR a list of factors it would consider in evaluating 
the configuration for a proposed RTO. Nearly all of the comments agree 
that these factors are generally appropriate.
    We recognize that different factors may suggest different 
configurations and that assessing the appropriateness of a region's 
configuration will require balancing factors and a flexible approach. 
Given this qualification, the Commission, in evaluating an RTO's 
boundaries, will consider the extent to which the proposed boundaries:
    Facilitate performing essential RTO functions and achieving RTO 
goals: The regions should be configured so that an RTO operating 
therein can ensure non-discrimination and enhance efficiency in the 
provision of transmission and ancillary services, maintain and enhance 
reliability, encourage competitive energy markets, promote overall 
operating efficiency, and facilitate efficient expansion of the 
transmission grid. For example, we understand that there have been 
instances where transmission system reliability was jeopardized due to 
the lack of adequate real-time communication between separate 
transmission operators in times of system emergencies. To the extent 
possible, RTO boundaries should encompass areas for which real-time 
communication is critical, and unified operation is preferred.
    Encompass one contiguous geographic area: The competitive, 
efficiency, reliability, and other benefits of RTOs can be best 
achieved if there is one transmission operator in a region. To be most 
effective, that operator should have control over all transmission 
facilities within a large geographic area, including the transmission 
facilities of non-public utility entities. This consideration could 
preclude a noncontiguous region, or a region with ``holes.'' However, 
as we discuss below, we will not automatically deny RTO status where 
the RTO is not able to obtain full participation in its region.
    Encompass a highly interconnected portion of the grid: To promote 
reliability and efficiency, portions of the transmission grid that are 
highly integrated and interdependent should not be divided into 
separate RTOs. One RTO operating the integrated facilities can better 
manage the grid. This is not to say, however, that every weak 
interconnection belongs on a regional boundary. Where a weak interface 
is frequently constrained and acts as a barrier to trade, it may be 
appropriate to place that interface within an RTO region. It may be 
more difficult to expand a weak interface on the boundary between two 
regions; this may act as a barrier to trade between the two 
regions.369
---------------------------------------------------------------------------

    \369\ Commenters are also divided on whether weak interfaces 
should be encompassed within an RTO or act as a natural boundary. 
After consideration, we conclude that there is not a universal 
answer applicable to all situations. Consequently, we will address 
this issue as it arises in RTO proposals on a case-by-case basis.
---------------------------------------------------------------------------

    Deter the exercise of market power: While the industry should work 
toward a goal of virtually seamless trade between RTOs, it may be that 
initially a significant amount of trade may be contained within an RTO, 
especially if the RTO or the market establishes a power exchange that 
covers the same area as the RTO. Thus, to have a competitive market, it 
is important to create an RTO region that is not dominated by a few 
buyers or sellers of energy. Also, the RTO configuration should not be 
one where the RTO participants can exercise transmission market power 
by collecting congestion fees on a critical corridor.
    Recognize trading patterns: Given that a goal of this initiative is 
to promote competition in electricity markets, regions should be 
configured so as to recognize trading patterns, and be capable of 
supporting trade over a large area, and not perpetuate unnecessary 
barriers between energy buyers and sellers. There may exist today some 
infrastructure or institutional barriers unnecessarily inhibiting trade 
between regions that could be economically reduced. RTO boundaries 
should not perpetuate these unnecessary and uneconomic barriers.
    Take into account existing regional boundaries (e.g., NERC regions) 
to the extent consistent with the Commission's goals for RTOs: An RTO's 
configuration should, to the extent possible, not disrupt existing 
useful institutions. The Commission recognizes that utilities have been 
working together regionally in different contexts for some time, and 
that there is value in preserving historical institutions and 
relationships; but we also recognize that in the evolving market, 
efficiencies may call for new configurations.
    Encompass existing regional transmission entities: Because existing 
ISOs, and any other regional transmission entities we may hereafter 
approve, already integrate transmission systems, it may not be 
efficient to divide them into different regions. This is not to say, 
however, that RTO boundaries must coincide with existing regional 
transmission entities. An appropriate region may well be larger, and 
there may be circumstances that support combining or reconfiguring 
existing entities.
    Encompass existing control areas: Many existing control areas are 
relatively small. It may be advisable not to divide them further. 
However, parties would not be precluded from proposing to divide a 
control area if they show this to be beneficial.
    Take into account international boundaries: The Commission 
recognizes that natural transmission boundaries do not necessarily 
coincide with international boundaries. Indeed, a large part of 
Canada's transmission system, and a small part of Mexico's transmission 
grid, is interconnected on a synchronous basis with that of the U.S. 
Accordingly, an appropriate region need not stop at the international 
boundary. However, this Commission

[[Page 864]]

does not have, and is not intending by this rule to seek, jurisdiction 
over the facilities in a foreign country. We will ask our international 
neighbors to participate in discussion of these issues. Perhaps what 
may be thought of as a ``dotted line'' boundary at the international 
border could be used to indicate that a natural transmission region 
does not necessarily stop at the border, while this Commission's 
jurisdiction does.
    Although most commenters generally support these factors, other 
considerations are proposed as factors. For example, some commenters 
claim that we should make reliability and system security the dominant 
factor, while other commenters propose that we make trading patterns 
and market transactions the dominant factor. After consideration, we do 
not think it appropriate to identify one factor as the most important. 
Although it is essential that reliability not be jeopardized by RTO 
formation, and it is important to promote competition, we do not 
believe that one goal needs to be sacrificed to achieve the other.
    Other commenters suggest additional factors that they deemed 
important to RTO boundaries, including, for example, established 
security coordinators, joint ownership arrangements, and Federal power 
marketing administration project marketing areas. We do not intend the 
factors we have listed to be exclusive: other factors may have merit 
for a particular region. We encourage parties to identify additional 
factors they believe relevant as we consider specific RTO proposals.
    c. Control of Facilities Within a Region. We proposed in the NOPR 
to accept as RTOs only those proposals for which a region of 
appropriate scope and configuration is identified and the proponents 
represent a large majority of the transmission facilities within the 
identified region. We solicited comments on how best to balance our 
goal of having RTOs in place that operate all transmission facilities 
within an appropriately sized and configured region against the reality 
that there may be difficulties in obtaining 100-percent participation 
in all regions in the near term. We asked if we should deny RTO status 
for any proposal that does not include all transmission facilities 
within an appropriate region, or if we should require that the RTO at 
least negotiate certain agreements with any non-participants within its 
region to ensure maximum coordination.
    Comments. Almost all commenters argue that RTO status should not be 
withheld if the RTO participants are unable to obtain participation by 
all transmission owners in the region.370 Several 
commenters, such as Desert STAR and Minnesota Power, note that, if the 
Commission does not mandate 100 percent participation, it does not make 
sense to make it a condition of RTO approval. Other commenters propose 
standards to consider in determining when a proposed RTO represents 
sufficient facilities in the region. For example, Desert STAR suggests 
that the RTO have more than a majority of transmission owners and has 
not restricted membership. Southern Company proposes a standard that 
sufficient facilities include most of the major transmission facilities 
and the RTO can show benefits. MidAmerican proposes that the RTO be 
able to demonstrate that it would improve the wholesale market of any 
subregion of the country without hindering the wholesale market of any 
other region of the country. Enron/APX/Coral Power argues that an RTO 
should be approved if it provides an improvement even with ``gaps.'' 
Midwest Municipals believe that an RTO should be accepted if the 
Commission can make the judgment that the proposal with ``gaps'' is 
likely to encourage others to join through the strength of its 
operations and the facilities support the development of a competitive 
generation market. CRC suggests a standard that the proponents make a 
showing that they have diligently tried to accommodate the concerns and 
needs of the nonparticipating transmission owners.
---------------------------------------------------------------------------

    \370\ See, e.g., Desert STAR, Southern Company, Metropolitan, 
MidAmerican, Nevada Commission, Avista, Enron/APX/Coral Power, Duke, 
PJM/NEPOOL Customers, Cal ISO, Midwest Municipals, CRC, NPRB, 
Minnesota Power, Tri-State, TVA.
---------------------------------------------------------------------------

    Some commenters, such as NJBUS and Cal ISO, believe that an RTO 
should include the participation of all jurisdictional transmission 
owners in the region. Duke, however, opposes any attempt by the 
Commission to determine the appropriate level of participation, stating 
that the market should determine the participation level. Some 
commenters, such as Metropolitan, support having the RTO develop 
coordinated operations agreements with non-participants, while other 
commenters, such as Avista and Duke, caution that requiring such 
agreements would be contrary to market principles and would give the 
non-participating party too much bargaining power.
    Seattle contends that the Commission should guard against utilities 
that would add to the RTO some facilities that are not necessary for 
RTO operations merely to obtain incentives. It argues that small 
municipal control areas should have some latitude to determine which of 
their facilities are regional for RTO purposes. Seattle also questions 
what ``participation'' entails for a utility that has limited 
transmission facilities.
    Commission Conclusion. To satisfy the scope and configuration 
characteristic of this Final Rule, all or most of the transmission 
facilities in a region must be included in the RTO. Any RTO proposal 
filed with us should intend to operate all transmission facilities 
within its proposed region.
    We recognize, however, that the proponents of an RTO may not be 
able to obtain agreement by all transmission owners in a region of 
appropriate scope and configuration to transfer operating control of 
their facilities to the RTO. This may occur, for example, because 
certain facilities may be owned by governmental entities that have 
restrictions on transfer of control that may require time to resolve. 
We do not believe that it would be desirable to deny RTO status or 
delay RTO start-up where the transmission owners representing a large 
majority of the facilities within a region are ready to move forward, 
while a few others are not. On the other hand, we do not believe it 
would be desirable to approve an RTO proposal for a region if the 
proponents represent only a small portion of the facilities in an 
otherwise satisfactory region.
    Not knowing the full extent of difficulties that may be involved to 
achieve participation by all transmission facilities, we will not 
decide generically to automatically deny RTO status for lack of full 
participation. If an RTO proposal does not cover all the transmission 
facilities within its proposed region, it should identify the reasons 
for this, any continuing efforts to include all facilities, and any 
interim arrangements with the non-represented facility owners to 
coordinate transmission functions within the region. The Commission may 
at a future time determine whether the use of its authorities under FPA 
sections 202(a) and 206 is appropriate to rationalize proposed regions 
in order to accomplish the objectives of those sections, as discussed 
elsewhere in this Final Rule.
3. Operational Authority (Characteristic 3)
    In the NOPR, the Commission proposed that the RTO have operational 
authority for all transmission facilities under its 
control.371 We stated that this

[[Page 865]]

requirement raised two questions: Which functions must an RTO perform? 
How should an RTO perform the functions that it has reserved for 
itself? With respect to the question of which functions an RTO should 
perform, the Commission proposed that, at a minimum, the RTO must have 
operational authority over all transmission facilities transferred to 
the RTO and must be the security coordinator for its 
region.372 As security coordinator, the RTO would be 
responsible for real-time monitoring of system conditions (including 
voltage, frequency, transmission and generation availability, and power 
flows) in order to anticipate potential reliability problems, and for 
directing and coordinating relief procedures to respond to transmission 
loading problems (such as assisting the control area in alleviating the 
loading, halting additional interchange transactions, reallocating the 
use of the transmission system, selecting the transmission loading 
relief procedure, and implementing emergency procedures, including 
directing that the control area immediately redispatch generation, 
reconfigure transmission or reduce load). Those proposing an RTO may 
also decide to have their RTO perform other traditional control area 
functions (such as maintaining the energy balance, interchange 
schedules and system frequency). The Commission proposed, however, that 
an RTO would not be required to be a single control area because of 
concerns over potentially high costs and technical limitations. Instead 
those proposing an RTO would be given flexibility in determining the 
best division of functions between the RTO and any providers of other 
control area functions if there are no other grid operators in its 
region. However, the Commission insisted that an RTO must be ultimately 
responsible for providing reliable and non-discriminatory transmission 
service.373
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    \371\ FERC Stats. & Regs. para. 32,541 at 33,734 and proposed 
Sec. 35.34(i)(3). In the NOPR, we used the terms ``operational 
authority'' and ``operational responsibility'' interchangeably. For 
purposes of clarity and consistency, we will use only the term 
``operational authority'' to describe this function and have revised 
the proposed regulatory text accordingly.
    \372\ FERC Stats. & Regs. para. 32,541 at 33,734 and proposed 
Sec. 35.34(i)(3)(ii).
    \373\ Id.
---------------------------------------------------------------------------

    With respect to the second question of how an RTO will perform its 
functions, the Commission proposed that an RTO be given considerable 
flexibility in determining whether it will control facilities directly, 
delegate functions, or use a combination of these 
methods.374 For example, we stated that an RTO proposal 
could have the RTO operate a single control area, or establish a 
master-satellite hierarchical control structure with one central and 
multiple distributed control centers (in either case it could propose 
to lease equipment and convert employees from existing control 
centers).375 The Commission also proposed that the RTO must 
submit a public report assessing its operational arrangements no later 
than two years after it begins operations.376
---------------------------------------------------------------------------

    \374\ Id. and proposed Sec. 35.34(i)(3)(i).
    \375\ Id.
    \376\ Id. at 33,735.
---------------------------------------------------------------------------

    Comments. Comments on the Functions an RTO Must Perform. Most 
commenters agree that the RTO must have operational authority 
377 for the transmission facilities under its 
control.378 Some commenters claim that this authority is 
necessary to prevent anticompetitive behavior by transmission 
owners.379 Some commenters further contend that this 
authority must extend to all facilities involved in wholesale 
transactions so that the transmission owner does not retain control of 
``access ramps'' that happen to be at low (34kV or 69kV) voltage 
levels.380 In contrast, some utilities express concern that 
RTO authority over low voltage facilities will unnecessarily complicate 
operations.381
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    \377\ Operational authority refers to the authority to control 
transmission facilities, either directly or through contractual 
agreements with the entities that do have direct control. In 
contrast, security coordination refers to real-time monitoring of 
system conditions in order to anticipate potential reliability 
problems, and directing and coordinating relief procedures to 
respond to transmission loading problems.
    \378\ See, e.g., APPA, Cal ISO, Duke, East Texas Cooperatives, 
Entergy, EPSA, First Rochdale, Georgia Transmission, Illinois 
Commission, IMEA, ISO-NE, Michigan Commission, Minnesota Power, 
Montana-Dakota, NASUCA, NECPUC, Nevada Commission, Mid-Atlantic 
Commissions, PacifiCorp, PJM, PJM/NEPOOL Customers, SNWA, Southern 
Company, SRP, SPRA, Tri-State, UtiliCorp, WPSC.
    \379\ See, e.g., Illinois Commission, IMEA, NASUCA, PJM/NEPOOL 
Customers.
    \380\ See, e.g., First Rochdale, IMEA, UMPA.
    \381\ See, e.g., Montana-Dakota, Tacoma Power.
---------------------------------------------------------------------------

    Several commenters oppose operational authority over the 
transmission system by the RTO. Some commenters claim that the 
Commission does not have the legal authority to require transmission 
owners to transfer control to any other entity.382 Midwest 
Energy and SPP believe a transfer of authority would be too costly to 
implement. Other commenters maintain that the owner and operator of the 
transmission system must be the same entity in order to avoid liability 
disputes.383 Mass Companies suggests that transmission 
owners retain authority to ensure the safe and prudent management of 
their facilities. ComEd suggests that transmission owners retain 
operational authority with the RTO having oversight responsibility.
---------------------------------------------------------------------------

    \382\ See, e.g., Florida Commission, Puget. It appears that the 
Florida Commission interprets a transfer of operational control as a 
transfer of retail dispatch authority. Although other commenters 
such as WPSC support the RTO having operational authority, they 
believe that the Commission may need legislative action to obtain 
the authority to require such a transfer.
    \383\ See, e.g., Florida Power Corp., Georgia Transmission, JEA, 
MidAmerican, Southern Company, Enron/APX/Coral Power.
---------------------------------------------------------------------------

    Commenters are divided whether the RTO should be required to be a 
control area operator. The existing ISOs in California, New England and 
PJM, which are all control area operators, report that this structure 
is working in their regions. Some commenters express concern over 
potential harm to competitive markets if control area authority is not 
transferred to an independent entity.384 ICUA recommends 
that the RTO be the sole control area operator. Many other commenters 
support a single control area as the ultimate goal, but suggest that 
the RTO be allowed to evolve to this structure and not be required to 
consolidate control areas immediately.385 Other commenters 
express concern about potential costs associated with control area 
consolidation, but agree that such action would be acceptable if and 
when the RTO decides it is necessary for reliability or other 
reasons.386
---------------------------------------------------------------------------

    \384\ See, e.g., APPA, APS, Arkansas Consumers, NASUCA, NJBUS, 
TDU Systems.
    \385\ See, e.g., Conlon, Illinois Commission, Los Angeles, First 
Energy, Minnesota Power, SRP, TDU Systems.
    \386\ See, e.g., CP&L, ECAR, EEI, Entergy, EPSA, Southern 
Company.
---------------------------------------------------------------------------

    Commenters that oppose requiring control area consolidation provide 
a variety of reasons.387 Enron/APX/Coral Power state that 
only an RTO that is a transco should perform control area functions. 
The Florida Commission is concerned that control area consolidation may 
result in a security risk. Tri-State and WEPCO believe that there are 
higher priorities in RTO development (such as eliminating pancaking, 
and promoting regional system planning) and that emphasizing control 
area consolidation may inhibit RTO formation.
---------------------------------------------------------------------------

    \387\ It appears that the Florida Commission and JEA believe 
that such a transfer would involve RTO control of retail dispatch. 
It also appears that Dynegy believes that the basic control area 
function of frequency control is identical to dynamic scheduling, 
which they believe should not be centralized or consolidated.
---------------------------------------------------------------------------

    With respect to specific control area functions, numerous 
commenters discuss the need for an RTO to have some control of 
generation in order to ensure system reliability, especially

[[Page 866]]

during emergency situations.388 Minnesota Power suggests 
that the Commission include ``control generation as required to ensure 
reliability'' as an additional minimum function in the final rule. It 
also recommends that responsibility for area control error (ACE) and 
automatic generation control (AGC) be transferred to the RTO as control 
area functions because separating these functions from transmission 
operations can lead to reliability problems. Other commenters request 
that the balancing function be transferred to the RTO to prevent 
discriminatory behavior by transmission owners.389
---------------------------------------------------------------------------

    \388\ See, e.g., NASUCA, First Energy, Otter Tail, PJM, PJM/
NEPOOL Customers, Professor Hogan, Project Groups, SPRA, UtiliCorp, 
Williams, WPPI. We also discuss below in more detail the issue of 
congestion management as an RTO minimum function.
    \389\ See, e.g., East Texas Cooperatives, WPPI, Project Groups.
---------------------------------------------------------------------------

    There is widespread agreement among commenters that the RTO must be 
the security coordinator. Marketers, utilities, existing ISOs and 
customers all agree that coordination and reliability will be enhanced 
if a regional organization is responsible for maintaining grid 
security.390 Some commenters state that the authority of a 
security coordinator to receive commercially sensitive information to 
order the curtailment of transactions and the shedding of firm load 
also grants it the ability to favor its own merchant functions. 
Confidence in comparable and non-discriminatory transmission service, 
therefore, will be improved if these functions are performed by an 
entity that is independent of all market participants.391 
Though essentially in support of our proposal, NERC and MidAmerican 
assert that is not necessary to link each RTO to a single security 
center, but rather it is possible to allow a single security 
coordinator to assume responsibility for more than one RTO. NERC points 
out that if an RTO performs all the characteristics and functions 
specified in the NOPR, it will necessarily be a security coordinator.
---------------------------------------------------------------------------

    \390\ See, e.g., Allegheny, APPA, APX, Cal ISO, ComEd, Dynegy, 
East Texas Cooperatives, Enron/APX/Coral Power, Entergy, EPSA, LG&E, 
Mass Companies, MidAmerican, Midwest Energy, Montana-Dakota, NASUCA, 
NECPUC, NERC, NJBUS, PJM/NEPOOL Customers, PPC, Professor Hogan, 
Seattle, South Carolina Authority, SPP, SRP, Tri-State, UtiliCorp, 
Williams.
    \391\ See, e.g., LG&E, PJM/NEPOOL Customers, SPP, UtiliCorp. See 
also supra section III.D.1 for a more detailed discussion of 
independence as an RTO minimum characteristic.
---------------------------------------------------------------------------

    A number of parties state that the RTO must have access to real-
time system information in order to perform its functions as security 
coordinator.392 Montana-Dakota explains further that 
security centers, by definition, will be equipped with the hardware and 
software required to assume basic operational control of the system, 
which are beyond that required strictly for security functions.
---------------------------------------------------------------------------

    \392\ See, e.g., Montana-Dakota, PJM/NEPOOL Customers, South 
Carolina Authority, Williams.
---------------------------------------------------------------------------

    Only two commenters express concern over the need for the RTO to be 
the security coordinator. ComEd, though supporting some security 
functions for the RTO, asserts that the RTO's role can be limited 
simply to one of oversight. ComEd does not believe that the RTO needs 
access to real-time data, and instead would allow the individual 
control areas to perform the bulk of the security functions. The only 
commenter that argues against making the RTO a security coordinator is 
Avista, which states that the security coordinator in the Pacific 
Northwest is already an independent body and has the authority 
necessary for ensuring reliability; therefore, no changes are required.
    Comments on How an RTO Should Perform Its Functions. Overall, 
commenters strongly agree with the Commission's proposal to permit 
those proposing an RTO the authority to decide the type of control they 
require: direct, functional or a combination. Some commenters believe 
direct control is the best approach to prevent abuse of sensitive 
information and better ensure reliability.393 However, 
Manitoba Board and Canada DNR express concern that continued 
coordination between U.S. and Canadian utilities might be undermined if 
highly centralized systems are developed and controlled by U.S. 
entities. A few commenters contend that it is best for the RTO to 
delegate control authority.394 The majority of commenters 
support some form of hierarchical control structure, where the RTO 
would establish a master control center and direct the operations in 
the existing geographically distributed control centers, which would 
become satellite centers.395 PJM and ISO-NE indicate that 
they both currently operate with a hierarchical control structure, 
where the ISO control center is the master control room that directs 
the actions of the satellite control centers.
---------------------------------------------------------------------------

    \393\ See, e.g., East Texas Cooperatives, First Rochdale, 
Illinois Commission, PJM/NEPOOL Customers.
    \394\ See, e.g., MidAmerican, Seattle, South Carolina Authority.
    \395\ See, e.g., ECAR, Enron/APX/Coral Power, EPSA, East Texas 
Cooperatives, First Rochdale, Industrial Consumers, ISO-NE, LG&E, 
Los Angeles, Lincoln, MidAmerican, Montana-Dakota, NECPUC, NASUCA, 
Otter Tail, PJM, PJM/NEPOOL Customers, Project Groups, Seattle, 
South Carolina Authority, Tri-State. Many of these commenters 
support eventual consolidation when any cost and technical barriers 
are overcome and if the RTO decides it is necessary.
---------------------------------------------------------------------------

    A number of supporters of the hierarchical structure specifically 
request that the Commission ensure that the RTO has the authority to 
direct all actions at the satellite control centers and that the 
satellite centers will be independent in order to prevent 
discriminatory transmission service and the transfer of commercially 
valuable information to market participants.396 Montana-
Dakota and Otter Tail believe a major benefit of the hierarchical 
structure is improved emergency response and system security in a large 
region if the RTO is coordinating and directing the actions of all 
operators in the region. Finally, Enron/APX/Coral Power believe the 
standardization of balancing practices for a large region is an 
important benefit of a hierarchical system.
---------------------------------------------------------------------------

    \396\ See, e.g., EAL, East Texas Cooperatives, ISO-NE, 
Industrial Consumers, LG&E, NASUCA, PJM, PJM/NEPOOL Customers, 
Powerex, Project Groups, Tri-State.
---------------------------------------------------------------------------

    Commission Conclusion. Which Functions Must an RTO Perform? We 
reaffirm the determination proposed in the NOPR that an RTO must have 
operational authority for all transmission facilities under its control 
and also must be the security coordinator for its region. We recognize 
that it is difficult to draw a precise line between transmission 
control and generation control,397 and we also recognize 
that given the changing nature of the industry, terminology such as 
``control area operator'' is undergoing definitional 
changes.398 Accordingly, it is difficult to state precisely 
what functions an RTO must have in order to have full operational 
authority for transmission facilities. Moreover, our desire to allow 
RTOs flexibility dissuades us from trying to be too precise. However, 
certain concepts are basic and generally understood in the industry.
---------------------------------------------------------------------------

    \397\ See NERC Operating Manual Policy 2 which can be found at 
www.nerc.com. As we have stated before, the dividing line ``between 
transmission control and generation control is not always clear 
because both sets of functions are ultimately required for reliable 
operation of the overall system.'' Midwest ISO, 84 FERC at 62,151. 
The idea that the entity that controls the transmission system must 
have some degree of control over some generation seems to be 
generally recognized. See Docket No. ER98-1438-000 Applicants' 
Response at 3.
    \398\ We note that the definition of a control area, and 
consequently the functions that must be performed by a control area, 
is currently being reexamined by the NERC Control Area Criteria Task 
Force in an open forum. See NERC web page at www.nerc.com.

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

[[Page 867]]

    One necessary aspect of operational authority as used here refers 
to the authority to control transmission facilities. This includes, but 
is not limited to, switching transmission elements into and out of 
operation in the transmission system (e.g., transmission lines and 
transformers), monitoring and controlling real and reactive power 
flows, monitoring and controlling voltage levels, and scheduling and 
operating reactive resources. Functions such as these must be included 
within the operational authority of an RTO.
    We conclude, as proposed in the NOPR, that the RTO is also required 
to be the NERC security coordinator for its region. The role of a 
security coordinator is to ensure reliability in real-time operations 
of the power system. As security coordinator, the RTO will assume 
responsibility for: (1) performing load-flow and stability studies to 
anticipate, identify and address security problems; (2) exchanging 
security information with local and regional entities; (3) monitoring 
real-time operating characteristics such as the availability of 
reserves, actual power flows, interchange schedules, system frequency 
and generation adequacy; and (4) directing actions to maintain 
reliability, including firm load shedding.
    We believe that the RTO must be security coordinator for several 
reasons. The functions of the security coordinator are enhanced when 
they are performed over large regions. In addition, the independence of 
the security coordinator is important for ensuring non-discriminatory 
transmission service, and the RTO will have that independence. As we 
stated in Midwest ISO:

    This role [the role of a security coordinator] is central to 
maintaining grid reliability and non-discriminatory access. Under 
proposed NERC policies, security coordinators would be required to 
anticipate problems that could jeopardize the reliability of the 
interconnected grid. In the course of performing these reliability 
functions, the Security Coordinator would receive considerable 
information which is commercially sensitive. Therefore, it is 
important that the proposed Midwest ISO Security Coordinator be 
performed by an entity that is independent of market 
participants.\399\

    \399\ 84 FERC at 62,158.
---------------------------------------------------------------------------

    However, we will allow flexibility in how the RTO performs its 
security coordinator functions. For example, an RTO may contract these 
responsibilities out to an independent security coordinator if this is 
justified. Also, this requirement does not prevent more than one RTO 
from sharing a single security coordinator as suggested by NERC.
    As proposed in the NOPR, we will not at this time require the RTO 
to operate what traditionally has been thought of as a single control 
area for its region. However, the RTO must perform the control 
functions required to satisfy the minimum characteristics and functions 
in this Final Rule, including the transmission control and security 
coordinator functions discussed above,\400\ in a non-discriminatory 
manner for all market participants.\401\ We will permit those 
developing an RTO proposal flexibility in deciding on the particular 
division of operational responsibilities with existing control areas.
---------------------------------------------------------------------------

    \400\ For example, several commenters state that an RTO must 
have some authority over generation to ensure system reliability. 
The RTO is required to have some authority as a minimum 
characteristic, as discussed with respect to short-term reliability.
    \401\ In our order approving the Midwest ISO, we stated that our 
approval of the ISO was based on the applicants' commitment that the 
ISO would be able to ``take all actions necessary to provide 
nondiscriminatory transmission service, promote and maintain 
reliability.'' Midwest ISO, 84 FERC at 62,159.
---------------------------------------------------------------------------

    We recognize that the feasibility of consolidating existing control 
areas into a single such area may be limited by cost and technical 
considerations. However, we note that physical consolidation may be 
unnecessary when a hierarchical control structure is used to define a 
single control area by making existing control areas subject to RTO 
direction (and so avoiding the high costs and technical uncertainty 
associated with centralization of physical control for a very large RTO 
region). Hierarchical control is a form of power system control that 
relies on a master-satellite control structure, which establishes a 
single controlling authority without requiring the construction of a 
single, consolidated control room. Existing control centers are not 
replaced, but continue to operate, independent from market 
participants, as satellite control centers reporting to the RTO master 
control center. The RTO security center assumes the dual role of the 
master control center and security center, with clear authority to 
direct all actions at the satellite centers.\402\
---------------------------------------------------------------------------

    \402\ See, e.g., Marija Ilic and Shell Liu, Hierarchical Power 
System Control: Its Value in a Changing Industry, Springer-Verlag, 
1996.
---------------------------------------------------------------------------

    We conclude that each region should be free to decide if and when 
the region will transition to a hierarchical control structure, 
consolidate the control areas in its region, or adopt a different 
control structure that best meets the region's needs.
    How Should the RTO Perform Its Functions? We conclude that those 
designing the RTO should have flexibility to decide how it would 
exercise its operational control authority. The RTO operate the 
transmission system through direct physical operation by RTO employees, 
contractual agreements with other entities (e.g., transmission owners 
and control area operators) or implement a hierarchical control 
structure involving a combination of direct and functional control. 
Under these arrangements, the personnel of existing control centers 
might become employees of the RTO or remain as employees of the control 
center owner, while being supervised by RTO personnel. We will leave it 
to the discretion of the region to decide on the combination of direct 
and functional control that works best for its circumstances.\403\
---------------------------------------------------------------------------

    \403\ This issue is also addressed in greater detail in our 
discussion of the RTO's role as a provider of ancillary services as 
an RTO minimum function.
---------------------------------------------------------------------------

    However, regardless of the method of control chosen, the RTO must 
have clear authority to direct all actions that affect the facilities 
under its control, including the decisions and actions taken at any 
satellite control centers. The system of operational control chosen 
must ensure reliable operation of the grid and non-discriminatory 
access to the grid by all market participants. In addition, to ensure 
that the RTO does not become locked into an operational system that is 
unsatisfactory, the Commission will require the RTO to prepare a public 
report that assesses the efficacy of its operational arrangements no 
later than two years after it begins operations.
4. Short-Term Reliability (Characteristic 4)
    The fourth proposed characteristic of an RTO is that it must have 
exclusive authority for maintaining the short-term reliability of the 
transmission grid under its control. In the NOPR we identified four 
basic short-term reliability responsibilities of an RTO: (1) the RTO 
must have exclusive authority for receiving, confirming and 
implementing all interchange schedules; (2) the RTO 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; (3) when the RTO operates transmission facilities owned by 
other entities, the RTO must have authority to approve and disapprove 
all requests for scheduled outages of transmission facilities to ensure 
that the outages can be accommodated within established reliability 
standards; and (4)

[[Page 868]]

if the RTO operates under reliability standards established by another 
entity (e.g., a regional reliability council), the RTO must report to 
the Commission if these standards hinder its ability to provide 
reliable, non-discriminatory and efficiently priced transmission 
service.\404\
---------------------------------------------------------------------------

    \404\ FERC Stats. and Regs. para. 32,541 at 33,735.
---------------------------------------------------------------------------

    Comments. General Comments. Commenters address both general 
concerns about reliability as well as the four basic proposed short-
term reliability responsibilities of an RTO. Most commenters generally 
agree that the RTO should have the responsibility for short term-
reliability.\405\ Several commenters raise questions regarding 
definition and scope of ``short-term'' reliability. TEP requests that 
the Commission further define the time period involved. It suggests 
that designating a specific time period (whether one month, six months 
or a year) would be beneficial to evaluating this characteristic. 
Enron/APX/Coral Power requests that the Commission make clear that 
``short-term'' is intended to mean ``real-time.''
---------------------------------------------------------------------------

    \405\ See, e.g., American Forest, Cal ISO, California Board, 
Cinergy, CMUA, CSU, EAL, Enron/APX/Coral Power, Entergy, EPSA, 
Industrial Customers, NASUCA, NECPUC, PJM, PNGC, SMUD, UtiliCorp, 
H.Q. Energy Services, Mass Companies, Mid-Atlantic Commissions, 
MidWest Energy, Minnesota Commission, NY ISO, PacifiCorp, PG&E, 
Williams, WPSC.
---------------------------------------------------------------------------

    While agreeing that the RTO should be given ultimate control over 
facilities necessary to preserve reliability, SMUD expresses concern 
that the RTO should not be encumbered with responsibility for 
facilities that do not serve a regional transmission function. TANC 
requests that the RTO's responsibility over reliability not infringe on 
the management responsibilities of local regulatory authorities or 
interfere with the management and operation of the local system 
facilities of a utility distribution company.
    PG&E requests that the Commission require that the RTO rely 
primarily on market mechanisms to maintain reliability. However, PJM/
NEPOOL Customers urge the Commission to ensure that the RTO's actions 
in maintaining the short-term reliability of the grid do not 
unreasonably impinge on the freedom of business decisions inherent in a 
competitive supply market. Several commenters, such as San Francisco 
and Minnesota Commission, state that because the primary function of a 
RTO is ensuring short-term reliability, it should be more clearly 
defined and should not be compromised by any other RTO market 
functions.
    PJM suggests that the Commission grant additional authorities to 
the RTO to ensure reliability, including the authority to (1) collect 
information, (2) direct operations in the control area, (3) assure that 
those it directs will respond in a predictable manner (which the RTO 
can achieve through training and drills) and (4) declare an emergency, 
direct emergency operations, and determine when emergency conditions 
have ended.
    Southern Company notes that the industry has little, if any, 
experience in granting a new entity control over the operations of a 
transmission system that encompasses a broad, multi-state region.\406\ 
It claims that transmission owners and State commissions must be 
assured that the RTO is capable of operating a regional transmission 
system reliably before an RTO is formed. New York Commission indicates 
that the authority of States to require the maintenance of electric 
system reliability should be recognized in establishing 
responsibilities. Iowa Board believes that there is a need for greater 
regional development of reliability standards to reflect regional needs 
and conditions. It requests that State commissions be involved in the 
decisionmaking process of an RTO to ensure that electric facilities are 
properly sized and located and that additions are not detrimental to 
the reliability of the grid.
---------------------------------------------------------------------------

    \406\ Southern Company notes that the California and ERCOT ISOs 
operate within the boundaries of a single state. In PJM, New York 
and New England, the control of the grid remains remarkably 
unchanged because the ISOs in those regions were already operating 
the system on behalf of the transmission owners and adopted the 
institutions and infrastructures of an ISO.
---------------------------------------------------------------------------

    Comments on Interchange Scheduling. The Commission proposed that, 
in the context of the RTO's role as the recipient and evaluator of all 
requests for transmission service under its own FERC-approved tariff, 
an RTO that is a control area operator must also receive, confirm, and 
implement all interchange schedules between adjacent control 
areas.\407\ The Commission expressed concern that non-RTO control area 
operators would receive commercially sensitive information involving 
its competitors in implementing interchange schedules and questioned 
whether there is any Commission action, other than its current code of 
conduct standards, and short of requiring consolidation of all control 
areas within a region, which could address this concern.
---------------------------------------------------------------------------

    \407\ FERC Stats. & Regs. para. 32,541 at 33,735-36.
---------------------------------------------------------------------------

    Several commenters agree that the RTO should have authority over 
receiving, confirming and implementing all interchange schedules.\408\ 
PJM believes that an independent ISO is in the best position to 
exercise the scheduling authority of an RTO. It suggests that an RTO 
that is independent of commercial interests in the market does not face 
the commercial information problem because it does not compete with 
market participants and consequently would make scheduling decisions in 
an unbiased and fair manner.
---------------------------------------------------------------------------

    \408\ See, e.g., Cal ISO, CMUA, Entergy, Mass Companies, NECPUC, 
Nevada Commission, PJM/NEPOOL Customers, PJM, SMUD, Southern 
Company, WPSC, PG&E.
---------------------------------------------------------------------------

    PJM/NEPOOL Customers claims that interchange scheduling oversight 
must be performed by an independent entity because it would be neither 
possible nor desirable for a non-RTO control area operator to perform 
this function without access to commercially sensitive information. It 
suggests that the RTO maintain direct control over interchange 
scheduling either by using RTO employees or a master satellite 
arrangement where ultimate responsibility remains in the RTO master 
control area operating room. APX suggests that requiring a contractor 
(acceptable to the RTO and the control area operator) to operate the 
control area operator facility could help address this concern.
    Enron/APX/Coral Power believes that the risk is eliminated if 
transmission operations, including control-area operations, are 
operationally separated from the load and generation of vertically-
integrated utilities. Barring such complete separation, this risk could 
nevertheless be substantially obviated if the RTO provided control area 
operators with information only about scheduled net interchanges 
between control areas without disclosing the individual transactions 
making up the new schedules.\409\
---------------------------------------------------------------------------

    \409\ See also Southern Company.
---------------------------------------------------------------------------

    However, other commenters contend that control area operators will 
continue to need information on individual transactions in order to 
implement interchange schedules and to ensure real-time 
reliability.\410\ Desert STAR believes that work should be done in this 
area to determine what information is required by control area 
operators and when they must receive it in order to carry out their 
reliability responsibilities.
---------------------------------------------------------------------------

    \410\ See, e.g., Duke, Florida Power Corp.
---------------------------------------------------------------------------

    Florida Commission states that this issue has already been resolved 
within the Florida Reliability Coordinating Council (FRCC) by requiring 
all entities who operate control areas within the

[[Page 869]]

region that require access to commercially sensitive information to 
sign agreements that separate reliability personnel and the relevant 
information from their wholesale merchant personnel.
    Several commenters, such as Duke and Florida Power Corp., state 
that no additional Commission action is necessary. These commenters 
believe that the existing code of conduct standards are working and the 
reciprocity provisions of Order No. 888 provide for compliance with the 
code of conduct standards by all non-public utility control area 
operators. Florida Power Corp. also notes that within the FRCC, all 
entities operating control areas are required to sign agreements 
verifying functional separation.
    Comments on Generation Redispatch. In the NOPR, the Commission 
proposed that the RTO's reliability authority include the ability to 
order redispatch of any generator connected to the transmission grid 
when necessary for the reliability of the grid. However, the RTO would 
have no authority over initial unit commitment and normal dispatch 
decisions.\411\
---------------------------------------------------------------------------

    \411\ FERC Stats. and Regs. para. 32,541 at 33,736.
---------------------------------------------------------------------------

    Several commenters agree that the RTO have some authority to order 
redispatch when necessary to maintain the reliability of the grid.\412\ 
Sithe, however, believes that, in the evolving competitive marketplace, 
redispatch authority alone is insufficient. It argues that the RTO 
should also provide appropriate incentives to the owners of assets that 
are needed for reliability to maintain those assets and make them 
available for operation in constrained areas. Sithe urges the 
Commission to consider adopting a final rule that provides RTOs with 
sufficient commercial authority, ``including the necessary financial 
resources'' to enter into market-rate business arrangements, that 
assure availability of assets needed for reliability. Sithe states that 
without this authority, the RTO may not have sufficient tools to fully 
ensure reliability, because must-run generators would have little 
incentive to continue to operate in constrained areas.
---------------------------------------------------------------------------

    \412\ See, e.g., Cal ISO, Cinergy, CMUA, NECPUC, PJM, UtiliCorp, 
Entergy, Allegheny, LG&E, Lincoln, Metropolitan, Minnesota Power, 
Nevada Commission, Otter Tail, Southern Company, TDU Systems, 
NASUCA, Reliant, Mass Companies, TAPS.
---------------------------------------------------------------------------

    CMUA maintains that it is insufficient to vest authority in the RTO 
to maintain short-term reliability without also vesting enforcement 
powers to ensure compliance with RTO dispatch instructions. Allegheny 
and other commenters agree that RTOs should be able to direct 
redispatch, particularly if the redispatch is accomplished under a 
market-based compensation scheme as a part of transmission service 
pricing methodology that uses the redispatch costs to set marginal 
system use costs. However, they argue that in no case should the RTO be 
able to direct generation redispatch unless the generator is 
compensated at market value (unless market power issues are 
involved).413
---------------------------------------------------------------------------

    \413\ See, e.g., Cinergy, Chelan, Southern Company, LG&E, 
Reliant.
---------------------------------------------------------------------------

    Avista expresses serious concern with the breadth of a redispatch 
requirement. It believes that the right to order redispatch of 
generation should be negotiated among the parties in the region without 
a presumption that the RTO must have broad redispatch authority, except 
in emergency circumstances. Avista and others note that a negotiated 
approach is particularly important to operators of hydroelectric 
resources which are subject to numerous environmental and operating 
restrictions that limit their ability to redispatch.414 
Avista and SMUD request that the Commission clarify that the RTO's 
authority to redispatch is limited to emergency circumstances affecting 
reliability.
---------------------------------------------------------------------------

    \414\ See, e.g., CMUA.
---------------------------------------------------------------------------

    Chelan believes that RTOs should be required to enter into arm's-
length agreements with those generators that are willing to service 
redispatch requests, and compensate those generators for supplying this 
service. RTOs should not be allowed to unilaterally redispatch a 
generating unit without the generator's consent, and without 
compensation.
    Commenters, such as Cal ISO and Nevada Commission, suggest that the 
Commission require reliability-related services (i.e. redispatch) be 
provided to RTOs under a set of uniform rates, terms and conditions. 
Such a requirement would reduce the Commission's administrative burden 
of contracts governed by different sets of terms and conditions.
    EME believes that the RTO's control over dispatch of generation 
should be carefully circumscribed. It recommends that reliability 
functions be internalized into explicit procedures for congestion 
pricing. It states that in most cases proper pricing signals can 
provide sufficient incentives for generators to schedule operation of 
their facilities to ensure system reliability.
    Industrial Consumers states that the RTO's redispatch decisions 
regarding ``any generator'' must be qualified to excuse on-site 
generators that serve an industrial load, especially those that serve a 
critical steam host. For environmental, safety and economic reasons, 
these units should not be forced to redispatch except as a last resort 
option.
    Metropolitan supports an RTO having authority to order redispatch 
of any generating unit when necessary for the reliability of the grid. 
However, ``reliability'' must be carefully defined to avoid RTO 
interference with normal market operations by redispatching generation 
for its own convenience, or to alleviate adverse market 
conditions.415
---------------------------------------------------------------------------

    \415\ Metropolitan believes the Cal ISO's definition of system 
emergency appropriately describes the circumstances in which 
redispatch may be appropriate. A ``system emergency'' is described 
as ``any abnormal system condition which requires immediate manual 
or automatic action to prevent loss of load, equipment damage or 
tripping of system elements which might result in cascading outages 
or to restore system operation to meet the minimum operating 
reliability criteria.''
---------------------------------------------------------------------------

    Several commenters oppose the proposal to allow the RTO to 
redispatch generation.416 PG&E believes that the proposal 
would give too much latitude to RTOs and create an incentive to impose 
centrally determined fixes on market operations, rather than allowing 
market mechanisms to self-correct. Therefore, PG&E argues that RTOs 
should be allowed to redispatch generation facilities only when there 
is a true reliability emergency as specified in the RTO tariff. 
Moreover, RTOs should be able to redispatch only those units that have 
actually participated in the market.
---------------------------------------------------------------------------

    \416\ See, e.g., PG&E, Southern Company, Reliant, SMUD.
---------------------------------------------------------------------------

    PJM/NEPOOL Customers believes that the authority as proposed in the 
NOPR is too broad and must be further defined. It requests that the 
Commission ensure that this authority is exercised only during only the 
most serious circumstances when grid reliability is truly in danger. It 
suggests that the Commission promulgate or pre-approve reliability 
standards for determining when the RTO can order redispatch of 
generators, the amount of generation assets that the RTO will have 
authority over and standards for the redispatch order. Southern Company 
recommends that the Commission provide only general guidance concerning 
redispatch and allow the regions to develop more specific procedures.
    When considering allowing an RTO to redispatch a Federal 
hydroelectric generator, SPRA emphasizes that the Commission must 
recognize that individual Federal hydroelectric generators are under 
the control of either the Corps, the Bureau of

[[Page 870]]

Reclamation or the International Boundary Waters Commission, not the 
PMA. While a PMA may belong to an RTO, it is unlikely that other 
Federal agencies will. The Commission must give careful consideration 
to determine that RTO redispatch authority does not prohibit or limit a 
PMA's ability to fulfill its statutory obligations.
    Comments on Transmission Maintenance Scheduling. In the NOPR, the 
Commission proposed that an RTO which operates transmission facilities 
owned by other entities be authorized to approve or disapprove all 
requests for scheduled outages of transmission facilities in order to 
ensure that maintenance outage schedules meet applicable reliability 
standards.417
---------------------------------------------------------------------------

    \417\ FERC Stats. and Regs. para. 32,541 at 33,736-37.
---------------------------------------------------------------------------

    The Commission requested comments on a number of issues related to 
this proposed requirement: Does it cede too much or too little 
authority to the RTO? If the RTO requires a transmission owner to 
reschedule its planned maintenance, should the transmission owner be 
compensated for any costs created by the required rescheduling? Would 
it be feasible to create a market mechanism to induce transmission 
owners to plan their maintenance so as to minimize reliability effects? 
Should an RTO that is an ISO have any authority to require rescheduling 
of maintenance if it anticipates that the planned maintenance schedule 
will adversely affect power markets? If the RTO is a transco, can it 
manipulate its transmission maintenance schedules in a manner that 
harms competition?
    The Commission stated that the RTO's regional perspective will 
allow it to coordinate individual maintenance schedules with each other 
as well as with expected seasonal system demand variations. Because the 
RTO will have access to extensive information, it will see the ``big 
picture'' and be able to make more accurate assessments of the 
reliability effect of proposed maintenance schedules than individual, 
sub-regional transmission owners.
    Commenters address essentially three issues related to transmission 
maintenance scheduling: the RTO's authority; appropriate compensation; 
and use of market mechanisms.
    RTO Authority to Schedule Transmission Maintenance. Many commenters 
support giving an RTO authority over transmission maintenance 
scheduling.418 Duke, however, believes that an enforcement 
mechanism may also be needed. First Rochdale recommends that 
transmission owners be given the right to protest an RTO's actions to 
the Commission. Reliant, however, opposes RTO authority over 
maintenance scheduling, arguing that transmission maintenance decisions 
must reside with transmission facility owners.
---------------------------------------------------------------------------

    \418\ See, e.g., Cal ISO, NECPUC, PJM, Desert STAR, Entergy, 
PGE, Allegheny, Avista, LG&E, Lincoln, Tri-State, WPSC, CRC, Duke, 
EAL, First Rochdale, Industrial Consumers, ISO-NE, Metropolitan, 
Montana-Dakota, NASUCA, New Smyrna Beach, NYPP, Oneok, PG&E, 
Southern Company, SRP, Turlock, WPPI, Florida Power Corp., Nevada 
Commission.
---------------------------------------------------------------------------

    Seattle and NYPP suggest that the Commission define an RTO role 
only for scheduling facility outages that are clearly associated with 
the regional transmission network because internal subtransmission and 
radial transmission facilities do not have regional significance. 
Turlock supports restricting the RTO's authority to the grid it manages 
to prevent its outage scheduling authority extending beyond the grid 
for which it is responsible. On the other hand, TDU Systems claims that 
an RTO should also coordinate maintenance of interconnected 
distribution facilities that are not under its control, if maintenance 
on those facilities would adversely affect RTO operations.
    Duke suggests that with the creation of an RTO that is not a 
transco, a set of governing principles for outage coordination should 
be established. The parties should agree on the timing of requests for 
planned maintenance and the timing of responses to those requests. If 
for any reason, other than the gross negligence of the transmission 
owner, a scheduled maintenance outage was determined to be a problem 
after an agreement is reached, rescheduling the outage would require 
the mutual consent of the transmission owner and the RTO.
    EAL recommends that appropriate contracts with existing 
transmission facility owners that ensure the continued reliable 
operation of the grid are required. Principal elements of such 
contracts would include standards of service, provisions for 
information sharing and reporting, maintenance scheduling, transmission 
facility ratings, testing and performance expectations. Maintenance 
scheduling should include provisions for maintenance deferral under 
instructions from the RTO if required for system security reasons only.
    NYPP states that arrangements for outages should be made well in 
advance of the outage start date because RTO approval of proposed 
schedules could become the critical path. If approval is delayed, or 
subsequently revoked, the transmission owner will incur significant 
expenses that should be reimbursed.
    Montana-Dakota suggests that the effects of rescheduling can be 
decreased by having the RTO review and approve all transmission 
maintenance schedules on a weekly, monthly and quarterly basis. After 
reviewing the transfer capability and market effects of the proposed 
outage, the RTO should communicate the need to reschedule to the 
transmission owner far enough in advance of the planned outage to allow 
the owner to reschedule, possibly to avoid any cost impact. Montana-
Dakota notes, however, that the closer the date of the outage, the 
higher the probability of an economic impact.
    Southern Company requests that the Commission clarify that once an 
RTO approves a scheduled outage, it should be allowed to change that 
schedule only if implementing the plan would compromise system 
integrity or reliability.
    Seattle believes that the NOPR fails to provide adequate assurances 
to transmission owners that a timely maintenance schedule will be 
adopted by the RTO. The RTO must establish timely dates certain for 
maintenance outage requests from operating entities. To do this the RTO 
must adequately balance safety considerations, and the cost of 
deferring maintenance with commercial impact. For these reasons, an RTO 
should not be permitted to arbitrarily postpone required maintenance.
    Compensation. Nearly all of the commenters believe that 
transmission owners should be compensated in some form if they are 
required by an RTO to reschedule maintenance.419 Avista 
argues that the transmission owners' shareholders should not bear the 
burden of decisions made by an independent body that result in reduced 
revenues or increased costs for the transmission owner.
---------------------------------------------------------------------------

    \419\ See, e.g., PJM, TANC, WPSC, Avista, Lincoln, CRC, Duke, 
Metropolitan, Minnesota Power, Montana-Dakota, NASUCA, NPRB, NYPP, 
PJM/NEPOOL Customers, Reliant, TDU Systems, Turlock, Florida Power 
Corp., Reliant, Desert STAR, Southern Company.
---------------------------------------------------------------------------

    Metropolitan states that if an RTO requests a transmission owner to 
reschedule planned maintenance for reliability concerns, a transmission 
owner should be compensated only for its direct costs necessarily and 
reasonably incurred in complying with the RTO's request. Direct costs 
may include, for example, increased labor or equipment expenses arising 
from the rescheduled maintenance. However, Metropolitan does not 
believe a transmission owner should recover lost

[[Page 871]]

opportunity costs arising from the rescheduled maintenance because 
opportunity costs are uncertain and speculative.
    Southern Company argues that, if an RTO requires a transmission 
owner to reschedule a previously approved outage, the RTO should 
compensate the transmission owner for any additional costs caused by 
the rescheduling.
    NASUCA believes that the RTO should compensate transmission or 
generation owners only to the extent that incremental costs are 
incurred due to the rescheduling of outages. NASUCA argues that it is 
unlikely that owners would incur significant incremental costs, 
especially for transmission outages.
    Some commenters such as PGE and Minnesota Power state that if an 
RTO requires a transmission owner to reschedule its planned maintenance 
for reliability reasons in an emergency situation, the RTO should not 
be required to compensate the transmission owner. However, if an RTO 
requires a transmission owner to reschedule its planned maintenance for 
economic reasons, the RTO should be required to compensate the 
transmission owner for liquidated damages.
    Other commenters such as Tri-State and Cal ISO oppose transmission 
owners being compensated for the rescheduling of maintenance work. Cal 
ISO states that, where an RTO properly exercises such authority by 
requiring a transmission owner to reschedule a maintenance outage, that 
transmission owner is not entitled to compensation for the costs 
associated with rescheduling. Tri-State recommends factoring any 
additional expense into the revenue requirement that the transmission 
owner receives from the RTO.
    Market Mechanisms. PJM/NEPOOL Customers suggests that the RTO enact 
a compensation mechanism in transmission outage rescheduling situations 
or propose to use a market mechanism to encourage transmission owners 
to plan maintenance so as to minimize reliability effects. Minnesota 
Power, however, argues that maintenance rescheduling to benefit power 
markets is analogous to generation redispatch and should be paid for by 
the benefitting market participants.
    Montana-Dakota believes that an RTO should have the authority to 
reschedule maintenance for market effects if there is an incremental 
cost reimbursement mechanism in place that would provide an incentive 
to the transmission owner to change maintenance schedules to benefit 
the market.
    Metropolitan argues that an RTO with authority to unilaterally 
reschedule transmission maintenance for market considerations could 
have a destabilizing effect on the power market. Emerging markets 
require predictability to thrive, and therefore RTOs should interfere 
in market operations only when necessary to address reliability 
concerns.
    Florida Power Corp. suggests that, while it may be feasible to 
develop a market mechanism to induce transmission owners to plan their 
maintenance to minimize reliability effects, it would be far simpler to 
retain the existing structure in which a single entity both owns and 
operates the transmission system. When ownership and operation are 
combined, a single entity is responsible for both reliability and 
maintenance, and thus has a natural incentive to seek an optimal 
balance between these activities. Thus, Florida Power Corp. opposes 
RTOs having authority to reschedule maintenance to manage the 
performance of the market.
    Turlock also does not believe an RTO should have authority to make 
transmission outage decisions based on market considerations. Turlock, 
as well as Desert STAR and CRC, believe instead that consideration 
should be given to motivating transmission owners to appropriately 
schedule their maintenance outages, to minimize impacts on competitive 
markets.
    Comments Generation Maintenance Scheduling. The short-term 
reliability characteristic, as proposed in the NOPR, would not give an 
RTO authority over proposed generation maintenance outage schedules. 
However, the Commission noted that some generation control is necessary 
for reliable operation of a transmission system. The Commission asked 
whether an RTO should have some authority over generation maintenance 
schedules and, if so, how much.420
---------------------------------------------------------------------------

    \420\ FERC Stats. and Regs. para. 32,541 at 33,737.
---------------------------------------------------------------------------

    The majority of commenters support an RTO having at least some 
authority over generation maintenance schedules.\421\ However, most 
commenters suggest limiting the RTO's authority. Some commenters 
suggest that an RTO have authority only for generating units that are 
``must-run'' or that the RTO has under contract due to the requirement 
to maintain system reliability.\422\ Desert STAR believes that an RTO 
should not attempt to manipulate the commercial power market when 
reliability is not affected.
---------------------------------------------------------------------------

    \421\ See, e.g., Cinergy, NECPUC, PJM, Desert STAR, WPSC, Cal 
ISO, EAL, Industrial Consumers, ISO-NE, Turlock, Florida Power 
Corp., Metropolitan, Minnesota Power, Montana-Dakota, NASUCA, Nevada 
Commission, NYPP, PSNM, TDU Systems.
    \422\ See, e.g., Desert STAR, Metropolitan, Turlock, Florida 
Power Corp., PSNM, NYPP.
---------------------------------------------------------------------------

    Cinergy supports an RTO having the ability to request changes to a 
schedule to serve reliability needs, coordinate transmission outages, 
and maximize grid efficiency to increase ATC for transmission 
customers' use, so long as generators receive compensation at market-
based prices for missed market opportunities. Other commenters agree 
that an RTO should compensate the generation owner if a schedule change 
is necessary.\423\
---------------------------------------------------------------------------

    \423\ See, e.g., WPSC, LG&E, Montana-Dakota.
---------------------------------------------------------------------------

    A few commenters claim that the RTO should not have any authority 
over generation maintenance schedules.\424\ SPRA states that requiring 
such authority would discourage or prevent participation by PMAs 
because other Federal agencies own the hydroelectric plants that 
generate the power marketed by the PMAs.
---------------------------------------------------------------------------

    \424\ See, e.g., Duke, PJM/NEPOOL Customers, SPRA, Tri-State, 
Empire District.
---------------------------------------------------------------------------

    Tri-State does not believe that an RTO should have approval 
authority over generation maintenance outages because these outages are 
driven by the cost considerations associated with generation plant 
equipment replacement or rehabilitation. However, Tri-State agrees that 
an RTO must have advance knowledge of the scheduled generation outages 
in order to assure transmission system reliability and adequacy of 
reserves. Other commenters concur with a notification requirement.\425\ 
Cinergy notes, however, that while it believes a generator may be 
required to submit its maintenance schedule to an RTO, the RTO should 
be prohibited from sharing that information with any other market 
participants, or affiliates of market participants.
---------------------------------------------------------------------------

    \425\ See, e.g., Enron/APX/Coral Power, FirstEnergy, Mass 
Companies, Metropolitan.
---------------------------------------------------------------------------

    Comments on Performance Standards. In the NOPR, the Commission 
discussed the establishment of performance standards by an RTO for 
transmission facilities under its direct or contractual control.\426\ 
For example, an RTO could establish a standard that identifies specific 
performance targets for planned and unplanned outages of facilities. 
The Commission requested comments on whether a non-profit ISO could 
establish incentive schemes for the transmission owners whose 
facilities it operates.
---------------------------------------------------------------------------

    \426\ FERC Stats. and Regs. para. 32,541 at 33,737.
---------------------------------------------------------------------------

    PJM believes that an RTO will be capable of developing performance

[[Page 872]]

standards and incentives to encourage transmission owners and 
generators to operate and maintain reliable facilities. It states that 
market participants cooperatively can create market-oriented incentives 
to maintain their transmission and generation facilities 
effectively.\427\
---------------------------------------------------------------------------

    \427\ See also LG&E.
---------------------------------------------------------------------------

    Duke also believes that incentive schemes can be developed. It 
suggests that the revenues collected from users by the RTO could be 
returned to transmission owners according to a prearranged formula that 
incorporates quality standards for reliability. Thus, the revenue 
allocation would reflect transmission owner performance in providing a 
reliable system.
    PSE&G believes that RTOs will, and should, be able to offer 
incentives to participants to ensure that reliability standards are not 
only met but exceeded. It states that a mechanism of linking payment 
with performance, measured against accepted benchmarks, has worked well 
for many years in PJM.
    EAL states that appropriate contracts with existing transmission 
facility owners that ensure the continued reliable operation of the 
grid are required. It suggests that these contracts include standards 
of service, provisions for information sharing and reporting, 
maintenance scheduling, transmission facility ratings, testing and 
performance expectations.
    Industrial Consumers believes that an RTO could establish 
performance standards for transmission facilities that takes into 
account the ``reliability'' of each facility. It argues that a facility 
that has frequent unplanned outages should not receive the same 
compensation as a facility whose availability is more reliable. It 
suggests that a transmission owner be precluded from recovering fixed 
costs during periods of unplanned outages that exceed some minimum 
threshold based on superior performance.
    Cal ISO indicates that its tariff provides for the implementation 
of maintenance standards, and penalties under those standards, to 
ensure both adequate maintenance and system reliability. These 
provisions act in concert with the California ISO's authority to 
coordinate and approve maintenance outages.
    Southern Company believes that the establishment of performance 
standards for transmission facilities controlled by an RTO is 
misplaced. Transmission owners plan and operate their transmission 
systems according to NERC and regional reliability standards, as well 
as State legal and regulatory requirements. Thus, while Southern 
Company doesn't claim that performance-based incentives are 
inappropriate, it points out that there already are existing standards 
to ensure reliable system operations.
    Comments on Facility Ratings and Operating Ranges. Reliable 
operation of the transmission system in the short-term requires both 
continuous monitoring of equipment availability and loading, and 
actions to maintain loading levels within the established operating 
ranges and equipment ratings. The NOPR suggested that RTOs are best 
situated to establish ratings and operating ranges for two reasons. 
First, they will have the most complete information about expected and 
real-time operating conditions. Second, RTOs will be trusted because 
they will not have any economic interests in electricity market 
outcomes and they will not be owned or controlled by any market 
participants. The Commission proposed to let RTO established equipment 
ratings prevail in a dispute with a transmission owner pending the 
outcome of a dispute resolution process.\428\
---------------------------------------------------------------------------

    \428\ FERC Stats. and Regs. para. 32,541 at 33,737-38.
---------------------------------------------------------------------------

    Nearly all commenters that address this issue oppose the NOPR 
proposal. South Carolina Authority urges the Commission to proceed with 
caution to prevent avoidable damage to persons or property. SRP argues 
that ratings and operating ranges influence the useful life and 
maintenance cost of equipment, as well as the level of service to the 
end-use customer, and notes that each transmission owner has a 
legitimate interest in the ratings. SRP believes that the ideal 
situation would be to establish ratings by mutual consent of the 
transmission owner and RTO. If they cannot agree, the issue should go 
to dispute resolution.
    NYPP and Mass Companies oppose this proposal because transmission 
owners have the fiduciary responsibility to protect their assets. 
Furthermore, they state that the rating of equipment necessarily 
requires a particularized knowledge of the equipment and related 
facilities that is unlikely to be possessed by the RTO.
    Metropolitan believes that a well-established reliability 
organization is best suited for establishing maximum transmission line 
ratings that can be sustained over most of the hours in a year because 
it will include the cooperation of technical groups representing all 
systems, not just those under RTO control. It sees no benefit from 
moving this responsibility to RTOs when the reliability councils have 
historically performed this function with a minimum of controversy. EAL 
suggests that since the owner of the transmission facility assumes the 
equipment, personnel and public risks for the operation of its 
equipment, the RTO could fulfill an audit role to ensure that facility 
ratings by the owners follow industry norms.
    Seattle suggests that the Commission instruct RTOs to work 
cooperatively with facility owners, since ratings on most power 
transmission equipment are a function of age and past usage, and a new 
entity will not have such historical information.
    Southern Company states that transmission owners have 
responsibilities to their shareholders and State commissions to operate 
their equipment safely and reliably. SPRA believes that this proposal 
has the potential to create significant liability risks for the United 
States.
    Entergy believes that a transco has an advantage at performing this 
function because it will have the natural incentive to maintain the 
highest and safest ratings for the transmission facilities since it 
will be solely and directly responsible for the risks and rewards of 
equipment ratings.
    Comments on Liability for Actions. Given that an RTO has 
responsibility for system reliability, the NOPR requested comments on 
the appropriate extent of an RTO's liability for its actions, and 
whether RTO facility ownership changes this determination.\429\
---------------------------------------------------------------------------

    \429\ FERC Stats. and Regs. para. 32,541 at 33,738.
---------------------------------------------------------------------------

    Most commenters believe that liability must be linked to the entity 
operating and controlling the transmission assets. Several commenters 
recommend that all RTO governing documents and operating agreements 
clearly establish the RTO's liability for any facilities that it 
operates but does not own.\430\ SRP recommends that the Commission not 
set a hard and fast rule, but rather give deference to assignments of 
liability worked out between the RTO and the transmission owner in the 
course of negotiating an operating agreement.
---------------------------------------------------------------------------

    \430\ See, e.g., Seattle, PGE, Desert STAR, PSNM, South Carolina 
Authority.
---------------------------------------------------------------------------

    Salomon Smith Barney believes that an RTO should be paid to run the 
network, and should suffer the consequences if it is not run well. 
Given this reasoning, it believes that an RTO requires sufficient 
capital to bear the risk, and that it operates under a regulatory 
scheme that acknowledges that higher risk taking requires a higher 
return.
    Other commenters focus on how to apportion liability. Several 
commenters

[[Page 873]]

suggest that the governing standard for liability for a particular 
activity should be the same standard that the Commission has approved 
for comparable ISO conduct. Thus, for example, the RTO would be subject 
to liability only on account of its reliability activities when damage 
caused by its actions is found to be the result of gross negligence or 
intentional misconduct.\431\
---------------------------------------------------------------------------

    \431\ See, e.g., NY ISO, Cal ISO, Nevada Commission, New York 
Commission.
---------------------------------------------------------------------------

    Other commenters believe that, if the RTO assumes authority to 
ensure proper maintenance and reliability of the system, it should 
assume that role fully (i.e., assume liability for its decisions) and 
it should hold transmission owners harmless for any increased cost 
responsibility.\432\
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    \432\ See, e.g., Avista, Minnesota Power, SPRA, MidAmerican, 
Florida Power Corp.
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    Tri-State believes that an RTO should not be held liable for the 
inevitable errors and omissions that will occur during transmission 
system operations except in the instance of gross negligence. It 
believes that without some form of indemnification, the RTO could be 
the target of numerous lawsuits alleging financial harm as a result of 
RTO actions.
    TANC believes that the RTO should be held liable for the 
consequential damages resulting from the RTO's instructions, if damage 
is caused to the transmission owners facilities as a result of the RTO 
requiring a transmission owner to operate its facilities in a manner 
that is inconsistent with prudent utility practice.
    Comments on Reliability Standards. In the NOPR, the Commission 
expressed a potential concern regarding an RTO's implementation of 
reliability standards that are established by another entity. The 
Commission identified two specific concerns: (1) regional or sub-
regional reliability groups may not be as independent from market 
participants as RTOs; and (2) almost every reliability standard will 
have a commercial consequence. The NOPR proposed to require an RTO to 
notify the Commission immediately if implementation of externally 
established reliability standards will prevent it from meeting its 
obligation to provide reliable, non-discriminatory transmission 
service.\433\
---------------------------------------------------------------------------

    \433\ FERC Stats. and Regs. para. 32,541 at 33,738-39.
---------------------------------------------------------------------------

    Most commenters generally support the proposal in the NOPR, 
although a few commenters believe that the NOPR proposal does not go 
far enough. On the other hand, some commenters seek clarification or 
oppose the NOPR proposal; most commenters that oppose the NOPR proposal 
believe that RTOs must be subordinate to national or regional 
reliability groups.
    PJM/NEPOOL Customers and other commenters agree that the RTO is an 
appropriate institution to evaluate whether other rules and 
requirements are impacting its ability to perform its function and to 
inform the Commission of this fact.\434\
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    \434\ See, e.g., Entergy, NECPUC, NASUCA.
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    PSE&G requests that the Commission clarify in its Final Rule that 
RTOs, not reliability trade associations, will have primary 
responsibility for resolving reliability issues in the future. It 
suggests that reliability trade associations can continue to play a 
role in developing reliability standards to be incorporated into RTO 
tariffs; these standards would then be implemented by the RTOs and 
ultimately enforced by the FERC. The standards, however, must be 
developed through a fair and open consensus process, such as the 
American National Standards Institute (ANSI) process.
    EPSA believes that reliability standards should be uniform 
throughout the United States. Reliability standards should be 
established at the national level through an industrywide 
representative organization, subject to review and approval by the 
Commission. Reliability rules should deviate regionally only if 
necessary to reflect specific operating conditions that are unique to a 
particular region. EPSA requests that existing reliability rules be 
considered carefully by the RTO, and reviewed by the Commission, as to 
their function and importance. EPSA and other commenters suggest that 
RTOs replace existing regional reliability councils as the entity 
responsible for maintaining compliance with nationally established 
reliability standards.\435\
---------------------------------------------------------------------------

    \435\ See, e.g., Cal ISO, Duquesne, Nevada Commission, Statoil.
---------------------------------------------------------------------------

    Conlon claims that the RTO must have the ability to establish 
various reliability standards that every participant. He suggests that 
the RTO, or the Commission with delegated authority to the RTO, set 
mandatory standards and impose sanctions or fines for violations.
    Cal ISO believes that RTOs are the appropriate entities to 
establish reliability standards. Regional organizations (not a single 
national standard-setter) should have the flexibility to develop 
standards that reflect regional priorities as well as individual issues 
related to particular areas or configurations in the transmission grid. 
It recommends that RTOs have the authority and responsibility to 
develop regional reliability standards, subject to general oversight by 
an appropriate independent national reliability organization such as 
NAERO.
    Similarly, Entergy believes that the RTO should have the primary 
role, authority and responsibility to adopt, implement and enforce 
regional reliability standards. Entergy further argues that this 
authority must be subject to regional oversight, especially as to 
reliability issues between and among interconnected RTOs.
    Some commenters argue that the Commission should provide additional 
authority to RTOs. For example, PJM believes that an RTO should have 
exclusive authority for administering the regional reliability of the 
bulk power system. It argues that no entity external to an RTO's region 
should have authority to dictate reliability rules that adversely 
affect the reliability in a region served by an RTO. Thus, PJM believes 
the Commission should extend this proposal beyond the proposed 
reporting requirement. In its opinion, RTOs that are responsible for a 
particular area of the bulk power market system best can develop tools 
that are designed to meet the needs of their individual areas. PJM 
requests that the Commission insist in its rule that RTOs play a 
significant role in setting any national reliability standards. Sithe 
suggests that RTOs should also have independent authority to modify 
existing rules, and/or to place new rules before the Commission for its 
review and approval in order to promote rules that intrude less into 
the markets and that promote efficiency goals, as well as system 
reliability.
    Illinois Commission argues that the proposal is not adequate and 
that the Commission must more directly address the concern over lack of 
independence between reliability standards development, enforcement 
organizations and commercial market interests. Illinois Commission 
suggests some possibilities: (1) require NERC/regional reliability 
council reform so that the process of establishing and enforcing 
reliability guidelines, standards, and policies is independent of 
discriminatory generation/transmission owner influence; (2) require 
that all NERC/regional reliability council guidelines, standards, and 
policies be approved by FERC prior to their adoption; or (3) reform 
NERC so that it is independent of generation/transmission owners, then 
eliminate MAIN and ECAR and require the Midwest ISO to act as the 
regional standards setting entity and as the

[[Page 874]]

reliability enforcement entity for the Midwest Region.
    A few commenters seek clarification.\436\ British Columbia Ministry 
requests that the Commission clarify how the RTO roles and 
responsibilities overlap with duties outlined for the Self Regulating 
Reliability Organization in the North American Electric Reliability 
Council's draft legislation. New York Commission and Iowa Board request 
that the Commission recognize the authority of the states to require 
the maintenance of electric system reliability.
---------------------------------------------------------------------------

    \436\ See, e.g., Canada DNR, Manitoba Board, Cal DWR, Entergy, 
Minnesota Commission, PSE&G.
---------------------------------------------------------------------------

    NERC and several other commenters generally oppose the proposal. 
NERC urges the Commission to include an obligation that the RTO adhere 
to the reliability rules adopted by NERC and the relevant regional 
reliability council as a condition of becoming an RTO. NERC states that 
RTOs must be designed, implemented and operated consistent with NERC 
operating and planning policies. NERC notes it will revise its 
operating and planning policies to recognize and accommodate these 
emerging institutions, as necessary.
    Several commenters such as Duke and SERC supports the work of NERC 
to establish consistently applied reliability standards and supports 
NERC's authority to enforce these standards. Duke also supports NERC 
and the regional reliability councils continuing to play a vital role 
in setting reliability standards. NERC oversight of reliability should 
prevent different RTOs from applying different standards and will 
ensure that inter-RTO reliability matters will be dealt with 
effectively. CEA suggests that the reliability responsibilities 
authorized for RTO's be respectful of the carefully balanced design of 
the evolving NERC/NAERO.
    SRP requests that each RTO be required to join NERC, or NAERO when 
formed. In addition, other commenters such as SRP and Los Angeles 
propose that RTOs be required to use planning and design criteria that 
comply with the criteria established by the appropriate NERC (or NAERO 
when established) regional reliability council.
    NYPP believes that properly constituted local and regional 
reliability councils authorized by FERC should have the authority to 
establish criteria necessary to maintain the reliability of the 
transmission system including the reliability of discrete locations 
(e.g., the supply of reactive power to support voltage in load 
pockets).\437\
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    \437\ The Commission has authorized the establishment of the New 
York State Reliability Council and has accepted the relationship 
between it and the NY ISO.
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    FirstEnergy requests that the role of the regional reliability 
councils be clarified with respect to regional RTOs. Also it would have 
us identify the need boundaries so that each RTO reports only to one 
regional reliability council. In addition, the regional reliability 
councils may need to undergo a transformation similar to NERC/NAERO to 
expand the role of the various industry segments.
    Commission Conclusion. The Commission adopts the proposal in the 
NOPR that the RTO must have exclusive authority for maintaining the 
short-term reliability of the grid that it operates. Although many 
commenters support this requirement, some pose additional questions 
regarding how this function will be performed by the RTO. Some 
commenters request that the Commission define better the time period 
associated with ``short-term'' reliability. We clarify that the term 
``short-term'' is intended to cover transmission reliability 
responsibilities short of grid capacity enhancement. It includes all 
time periods, including but not limited to ``real-time,'' necessary for 
the RTO to satisfy its reliability responsibilities, up to the planning 
horizon. There is no time gap between what is included within short-
term reliability and the RTO's planning responsibilities.
    Commenters also request more specificity in describing the RTO's 
functions. The facilities that will be under RTO control, the specific 
functions that the RTO must perform, and how the RTO will execute its 
responsibilities and direct operations, are all defined above in the 
section on operational authority. PJM's additional request that the RTO 
have authority to collect information is discussed in both the 
operational authority and the market monitoring sections.
    PG&E requests that the RTO rely on market mechanisms to maintain 
short-term reliability. PJM/NEPOOL Customers requests that reliability 
and commercial activities be kept separate. We will not require the RTO 
to rely on market mechanisms in every instance to maintain short-term 
reliability. The Commission believes that some reliability functions 
may not be conducive to supply through competitive market mechanisms 
since a reliable power system provided to one customer cannot be 
withheld from other customers, viz., many reliability functions are, in 
economic terms, ``public goods.'' In Order No. 888, we identified some 
functions necessary to maintain grid reliability as ancillary services 
and required them to be provided as separate products. These services 
and their potential inclusion in emerging markets is discussed in the 
section on ancillary services below. We cannot conclude at this time 
that it is appropriate to rely solely on market mechanisms to supply 
the reliability functions that the transmission system operator must 
perform, but we expect that over time most of the generation services 
that perform these functions will be competitively procured.
    Interchange Scheduling. We conclude that the RTO must have 
exclusive authority for receiving, confirming and implementing all 
interchange schedules, which are often coincident with schedules for 
unbundled transmission service. This function will automatically be 
assumed by RTOs that operate a single control area. If the RTO 
structure includes control area operators who are market participants 
or affiliated with market participants, the RTO will have the authority 
to direct the implementation of all interchange schedules. As stated in 
the NOPR, a remaining concern is that non-RTO control area operators, 
who are also competitors in energy markets, have unequal access to 
commercially sensitive information and could use this knowledge of 
their competitors' schedules and transactions to gain an unfair 
competitive advantage in the energy markets. In the event that the RTO 
filing includes a structure in which non-RTO control area operators 
receive sensitive information, we will require the RTO to monitor for 
any unfair competitive advantage, and report to the Commission 
immediately if problems are detected. In addition, to address concerns 
about protecting commercially sensitive information, we will require 
the RTO or any entities who operate control areas within the RTO's 
region that require access to commercially sensitive information to 
sign agreements that separate reliability personnel and the relevant 
information they receive from their wholesale merchant personnel.
    Redispatch Authority. We conclude that the RTO must have the right 
to order the redispatch of any generator connected to the transmission 
facilities it operates, if necessary for the reliable operation of the 
transmission system.\438\

[[Page 875]]

We also require each RTO to develop procedures for generators to offer 
their services and to compensate generators that are redispatched for 
reliability. In order to maintain the reliability of the transmission 
system, the entity that controls transmission must also have some 
control over some generation. In general, we believe this control 
should be through a market where the generators offer their services 
and the RTO chooses the least cost options. This authority does not 
extend to initial unit commitment and dispatch decisions for 
generators. However, for reliability purposes, the RTO should have full 
authority to order the redispatch of any generator, subject to existing 
environmental and operating restrictions that may limit a generator's 
ability to change its dispatch.
---------------------------------------------------------------------------

    \438\ Redispatch for congestion management is addressed under 
different rules, as discussed in the section on congestion 
management.
---------------------------------------------------------------------------

    Some commenters request that we define what is meant by redispatch 
for reliability. We clarify that we intend the authority for generator 
redispatch to be used by the RTO to prevent or manage emergency 
situations, such as abnormal system conditions that require automatic 
or immediate manual action to prevent or limit equipment damage or the 
loss of facilities or supply that could adversely affect the 
reliability of the electric system, or to restore the system to a 
normal operating state.\439\
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    \439\ In general, a power system can be in one of three states: 
normal, emergency and restorative. When all constraints and loads 
are satisfied, the system is in its normal state; when one or more 
physical limits are violated, the system is in an emergency state; 
and when part of the system is operating in a normal state yet one 
or more of the loads is not met (partial or total blackout), the 
system is in a restorative state.
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    Transmission Maintenance Approval. We conclude that, when the RTO 
operates transmission facilities owned by other entities, the RTO must 
have authority to approve and disapprove all requests for scheduled 
outages of transmission facilities to ensure that the outages can be 
accommodated within established reliability standards. Control over 
transmission maintenance is a necessary RTO function because outages of 
transmission facilities affect the overall transfer capability of the 
grid. If a facility is removed from service for any reason, the power 
flows on all regional facilities are affected. These shifting power 
flows may cause other facilities to become overloaded and, 
consequently, adversely affect system reliability.
    The RTO is expected to base its approval on a determination of 
whether the proposed maintenance of transmission facilities can be 
accommodated within established state, regional and national 
reliability standards. The RTO's regional perspective will allow it to 
coordinate individual maintenance schedules with other RTOs as well as 
with expected seasonal system demand variations. Since the RTO will 
have access to extensive information, it will be able to make more 
accurate assessments of the reliability effect of proposed maintenance 
schedules than individual, sub-regional transmission owners.
    If the RTO is a transmission company that owns and operates 
transmission facilities, these assessments will be an internal company 
matter. However, if there are several transmission owners in the RTO 
region, the RTO will need to review transmission requests made by the 
various transmission owners.\440\ In this latter case, we expect the 
RTO to: receive requests for authorization of preferred maintenance 
outage schedules; review and test these schedules against reliability 
criteria; approve specific requests for scheduled outages; require 
changes to maintenance schedules when they fail to meet reliability 
standards; and update and publish maintenance schedules as needed.
---------------------------------------------------------------------------

    \440\ Since some of these transmission owners may also own 
generation, they may have an incentive to schedule transmission 
maintenance at times that would increase the prices received from 
their power sales. A transmission company, not affiliated with any 
generators, would not have these same incentives.
---------------------------------------------------------------------------

    We conclude that, if the RTO requires a transmission owner to 
reschedule planned maintenance, the transmission owners should be 
compensated for any costs created by the required rescheduling only if 
the previously scheduled outage had already been approved by the RTO.
    We encourage the RTO to establish performance standards for 
transmission facilities under its direct or contractual control. Such 
standards could take the form of targets for planned and unplanned 
outages. The rationale for this requirement is that two transmission 
owners should not receive equal compensation if one owner operates a 
reliable transmission facility while the other operates an unreliable 
facility. For RTOs that are transcos, we will require that such quality 
standards be made explicit in any rate proposal.
    Generation Maintenance Approval. We conclude that the RTO is not 
required to have authority over proposed generation maintenance 
schedules. However, we acknowledge that there are reliability 
advantages to the RTO having this authority, and we would accept RTO 
proposals where the participants choose to grant the RTO such 
authority. In our order approving the Midwest ISO, we observed that 
``the dividing line between transmission control and generation control 
is not always clear because both sets of functions are ultimately 
required for reliable operation of the overall system.'' 441 
Because of this close connection between generation and maintenance of 
system reliability, it is essential for generator owners and operators 
to provide the RTO with advance knowledge of planned generation outage 
schedules so that the RTO can incorporate this information into its 
reliability studies and operations plan. However, although a generator 
may be required to submit its maintenance schedule to an RTO, the RTO 
should be prohibited from sharing that information with any other 
market participants, or affiliates of market participants.
---------------------------------------------------------------------------

    \44\ Midwest ISO, 84 FERC at 62,180.
---------------------------------------------------------------------------

    Facility Ratings. After consideration of the comments, we conclude 
that it is inappropriate here to require RTOs to establish transmission 
facility ratings. We encourage, however, such ratings to be determined, 
to the extent practical, by mutual consent of the transmission owner 
and the RTO, taking into account local codes, age and past usage of the 
facilities.
    The Commission acknowledges the concern that changes in existing 
equipment ratings may lead to problems of equipment safety and possible 
damage. We further recognize that the RTO may initially need to rely 
upon existing values for equipment ratings and operating ranges so as 
not to disrupt reliable system operation. However, as an RTO gains 
experience operating or directing the operation of the transmission 
facilities in its region, we expect this responsibility to migrate to 
the RTO, as facility ratings have at least an indirect effect on the 
ability of the RTO to perform other RTO minimum functions (e.g., 
planning and expansion, ATC and TTC). If there is a dispute over 
equipment ratings, the parties should pursue resolution through an ADR 
process approved by the Commission.
    Liability. After consideration, we will determine the extent of RTO 
liability relating to its reliability activities on a case-by-case 
basis.
    Reliability Standards. We conclude that the RTO must perform its 
functions consistent with established NERC (or its successor) 
reliability standards, and notify the Commission immediately if 
implementation of these or any other externally established reliability 
standards will prevent it from meeting its obligation to provide 
reliable, non-discriminatory transmission service.

[[Page 876]]

E. Minimum Functions of an RTO

    In the NOPR, we proposed seven minimum functions that an RTO must 
perform. In general, we proposed that an RTO must:
    (1) administer its own tariff and employ a transmission pricing 
system that will promote efficient use and expansion of transmission 
and generation facilities;
    (2) create market mechanisms to manage transmission congestion;
    (3) develop and implement procedures to address parallel path flow 
issues;
    (4) serve as a supplier of last resort for all ancillary services 
required in Order No. 888 and subsequent orders;
    (5) operate a single OASIS site for all transmission facilities 
under its control with responsibility for independently calculating TTC 
and ATC;
    (6) monitor markets to identify design flaws and market power; and
    (7) plan and coordinate necessary transmission additions and 
upgrades.
    We basically affirm these seven functions with the clarifications 
and revisions as noted below. In addition, we have added interregional 
coordination as an eighth minimum function, as discussed below.
1. Tariff Administration and Design (Function 1) Sole Administrator of 
Tariff
    In order to ensure non-discriminatory service within the region, 
the NOPR proposed that the RTO be the sole administrator of its own 
transmission tariff.442 The RTO would thus be the sole 
authority making decisions on the provision of transmission service 
including decisions relating to new interconnections. The NOPR 
requested comments on several aspects of this standard, including how 
the authority over interconnections would work for ISOs that do not own 
transmission and would not be performing the construction. The NOPR 
also sought comment on whether authority over interconnection should 
apply to all new interconnections, including those for reliability and 
connections to other regions.
---------------------------------------------------------------------------

    \442\ FERC Stats. and Regs. para. 32,541 at 33,739-740. The 
authority to file changes in the RTO tariff is discussed above under 
the Independence Characteristic.
---------------------------------------------------------------------------

    Comments. The vast majority of commenters addressing these issues 
agree with the proposal that the RTO be the sole administrator of its 
own tariff.443 Commenters noted many of the benefits of an 
RTO being the sole tariff administrator: it will eliminate confusion; 
reduce transactions costs; assure that access decisions are 
independent; 444 reduce reliability concerns; 445 
and ensure consistent ratemaking across the RTO.446 Some 
commenters suggest that their respective organizations already meet 
this requirement, including ISO-NE and NY ISO, which ask whether 
sharing authority with transmission owners for non-discriminatory 
access meets the standard.
---------------------------------------------------------------------------

    \443\ See, e.g., Allegheny, APX, SMUD, NASUCA, NY ISO, East 
Kentucky, Utilicorp, JEA, LG&E, Enron/APX/Coral Power, EPSA, South 
Carolina Authority, First Energy, Cal DWR, California Board, 
PacifiCorp and NSP.
    \444\ PJM.
    \445\ PJM/NEPOOL Customers.
    \446\ UAMPS.
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    But some of the commenters that support the proposal had specific 
concerns and suggestions: the Commission should adopt specific pricing 
regulations and expressly permit expedited declaratory orders on 
pricing; 447 the Commission should take a more active 
approach in developing innovative rates; 448 there may be a 
problem for an RTO located in both the United States and Canada if 
there is disagreement over the tariff by the respective authorities; 
449 and quicker decisions are likely if a stakeholder board 
is not involved.450
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    \447\ Entergy.
    \448\ Illinois Commission.
    \449\ Canada DNR.
    \450\ New Smyrna Beach.
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    A number of commenters also supported the proposal with respect to 
the RTO's authority over interconnections.451 Some of these 
commenters expressed concerns and recommendations about the 
Commission's proposal, e.g., transmission owners should be a part of 
the decision process; 452 transcos will be better able to 
integrate interconnection decisions into a unified strategy covering 
investment, operations, maintenance and facility design; 453 
RTOs should not have the authority to deny a generator that is not 
optimally located on the grid; 454 interconnection policy 
should rely more heavily on market mechanisms; 455 the 
transmission owner should develop the actual interconnection agreement 
to insure adequate protections for its equipment; 456 
national fees and technical standards should be established for 
interconnections; 457 authority over interconnections should 
involve coordinated planning and construction, not ``autonomous, 
unilateral authority''; 458 RTOs need to develop procedures 
and guidelines so that there are no adverse impacts of interconnection 
on existing facilities; 459 RTOs should have authority to 
assess the impact of a new interconnection on regional facilities but 
should only have authority over interconnections involving RTO 
facilities, not all regional facilities; 460 and an RTO must 
be required to show harm to deny an interconnection 
request.461
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    \451\ See, e.g., Entergy, PJM, South Carolina Authority, 
Southern Company, Tri-State, Desert STAR, East Texas Cooperatives, 
Enron/APX/Coral Power, Sithe and PG&E.
    \452\ Cal ISO.
    \453\ Duke.
    \454\ Minnesota Power.
    \455\ PG&E.
    \456\ Southern Company.
    \457\ Distributed Power and EAL.
    \458\ SPRA.
    \459\ TANC.
    \460\ Metropolitan.
    \461\ Williams.
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    A few commenters opposed the Commission's proposal or suggested 
making significant modifications. With respect to tariff 
administration, Seattle opposes the Commission giving RTOs with small 
control areas blanket authority to approve new interconnections and 
also argues that the RTO should not be given authority over the 
interconnection of customer based backup and load shaving generators, 
QFs, or subtransmission and radial transmission facilities (used to 
reinforce municipal grids). TXU Electric argues that the Commission 
should be more flexible and allow RTOs to choose whether to administer 
the tariff of other entities. TXU Electric notes that in ERCOT, each 
owner has its own tariff with its own revenue requirement but with 
uniform terms and conditions of access and that this approach can 
protect the owner better than an RTO tariff. Florida Commission 
recommends that the question of tariff administration be determined on 
a regional basis with endorsement by state regulators.
    With respect to RTO authority over interconnections, Mass Companies 
argues that the RTO should not have the authority over interconnections 
because such authority is unlawful, impairs reliability, and because 
the transmission owner is in a better position to perform this 
function. SRP suggests that an RTO's exclusive right to administer its 
own tariff and the right to control interconnections may establish a 
property right that would jeopardize a public power's tax free status 
by being declared a private business use. This would be a potential 
problem if the RTO were not a governmental entity or a 501(c)(3) non-
profit organization. To prevent this, SRP says that the RTO would have 
to be structured carefully with these concerns in mind. DOE indicates 
that the authority over interconnection is a concern for PMAs

[[Page 877]]

because of the NEPA requirements which must be accommodated. Industrial 
Consumers would amend the proposed Regulatory Text on tariff 
administration to add ``throughout the interconnection within which the 
Regional Transmission Organization resides'' to the requirement to 
promote efficient use and expansion. Industrial Consumers also propose 
that the Regulatory Text on interconnection be amended to add the 
responsibility to coordinate transmission needs across the 
interconnection. Finally, Industrial Consumers would amend the 
provision that RTOs review and approve requests for new 
interconnections to add ``by new loads that take service at 
transmission voltages and by any new generation resource regardless of 
the nominal voltage at the generator's point of interconnection. Any 
proposal to increase the nameplate-rated capacity at an existing 
generating site shall be treated as a new request for interconnection'' 
to clarify that the RTO is to authorize such interconnections and 
minimize entry barriers to new sources of generation.
    Commission Conclusion. We note the strong support for this standard 
in the comments and we adopt the NOPR's requirement that the RTO be the 
sole provider of transmission service and sole administrator of its own 
open access tariff. Included in this 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.462
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    \462\ Of course, eligible applicants always have the right to 
seek interconnections from the Commission pursuant to sections 
202(b) and 210 of the FPA.
---------------------------------------------------------------------------

    With the RTO the sole provider of transmission service, 
transmission customers have a nondiscriminatory and uniform access to 
regional transmission facilities. This type of access cannot be assured 
if customers are required to deal with several transmission owners with 
differing tariff terms and conditions. As noted in the NOPR, the RTO 
must be the provider of transmission service in the strong sense of the 
term. Mere monitoring and dispute resolution are insufficient to meet 
the requirements of this standard.
    The requirement that the RTO administer its own tariff and not the 
tariff or tariffs of other entities received little objection in the 
comments, even from ISOs where this requirement is not currently being 
met.463 One commenter, SCE&G proposes that the RTO's tariff 
only cover its own costs and wheeling. The transmission owners would 
maintain standard open access tariffs which would be administered by 
the RTO. We reject this proposal. To provide truly independent and 
nondiscriminatory transmission service, the RTO must administer its own 
tariff and have the independent authority to file tariff changes.
---------------------------------------------------------------------------

    \463\ See, e.g., ISO-NE at 9.
---------------------------------------------------------------------------

    Mass Companies argues that the RTO is not in as good a position as 
transmission owners to judge requests for new interconnections. SPRA 
and Metropolitan suggest that an RTO's authority over new 
interconnections should be limited. Because the ability for customers 
to obtain nondiscriminatory access to the regional transmission system, 
whether over existing facilities or over new facilities, is integral to 
a competitive market for generation, we reject these proposals to 
modify our original position on new interconnections.
    Other commenters, as noted above, support this standard but have 
specific concerns they would like to see the Commission address. The 
concerns listed do not cause us to change our original proposal. These 
concerns, to the extent they apply, should be voiced at the time RTO 
proposals are filed and they will be considered on a case-by-case 
basis.
    Multiple Access Charges. The NOPR proposed that the RTO's tariff 
must not result in transmission customers paying multiple access 
charges. We affirm that proposal in this Final Rule. Because the issue 
of multiple access charges is a rate issue, we discuss in detail the 
comments we received on this issue, the reasons for our conclusion, and 
the concepts of pancaked rates, license plate rates, and uniform access 
charges in Section III.G of this Final Rule addressing transmission 
ratemaking policy for RTOs.
2. Congestion Management (Function 2)
    In the NOPR, we proposed to include congestion management as a 
minimum function that an RTO must perform.464 Specifically, 
we proposed to require the RTO to ensure the development and operation 
of market mechanisms to manage transmission congestion. We proposed 
that the RTO must either operate such markets itself or ensure that the 
task is performed by another entity that is not affiliated with any 
market participant. In carrying out this function, we stated that the 
RTO must satisfy certain standards or demonstrate that an alternative 
proposal is consistent with or superior to satisfying the standard. We 
further proposed that the market mechanisms must accommodate broad 
participation by all market participants, and must provide all 
transmission customers with efficient price signals regarding the 
consequences of their transmission usage decisions. We proposed to 
allow RTOs considerable flexibility in experimenting with different 
market approaches to managing congestion through pricing. However, we 
stated that proposals should ensure that (1) the generators that are 
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. We asked for comments as to what specific requirements, if any, 
may best suit these goals.465
---------------------------------------------------------------------------

    \464\ FERC Stats. & Regs. para. 32,541 at 33,741-43.
    \465\ Id. at 33,754-55.
---------------------------------------------------------------------------

    We stated in the NOPR that traditional approaches to congestion 
management such as those that rely exclusively on the use of 
administrative curtailment procedures may no longer be acceptable in a 
competitive, vertically de-integrated industry. We thus concluded that 
efficient congestion management requires a greater reliance on market 
mechanisms, and stated our belief that a large regional organization 
like an RTO will be able to create a workable and effective congestion 
management market. We stated that while it is our intent to give RTOs 
considerable flexibility in experimenting with different market 
approaches to managing congestion, we believe that a workable market 
approach should establish clear and tradeable rights for transmission 
usage, promote efficient regional dispatch, support the emergence of 
secondary markets for transmission rights, and provide market 
participants with the opportunity to hedge locational differences in 
energy prices.
    The Commission invited comments on the requirement that RTOs must 
be responsible for managing congestion with a market mechanism, and 
posed the following questions. Can decentralized markets for congestion 
management be made to work effectively and quickly? Can the RTO's role 
be limited to that of a facilitator that simply brings together market 
participants for the purpose of engaging in bilateral transactions to 
relieve congestion? If not, will these markets require centralized 
operation by the RTO or some other independent entity? How can an RTO 
ensure that enough generators will participate in the congestion 
management market to make possible a least-cost dispatch? Are there any 
special considerations in evaluating

[[Page 878]]

market power in a congestion market operated or facilitated by an RTO? 
In addition, we proposed to allow up to one year after start-up for 
this function to be implemented. We noted that market approaches to 
congestion management may take additional time to work out, and asked 
for comments on whether this additional implementation time period is 
warranted, and whether one year is an appropriate additional time 
period.
    Comments. Using Market Mechanisms to Manage Congestion. Although 
opinions vary as to the proper role of the RTO in managing congestion, 
many commenters believe that efficient congestion management requires 
greater reliance on market mechanisms.466 CSU believes that 
congestion management is uniquely amenable to a market solution. CSU 
states that there will be a continuing need for some type of market 
mechanism to address constraints and this mechanism is best established 
at the regional level and best placed with an entity independent of 
wholesale power market participants.
---------------------------------------------------------------------------

    \466\ See, e.g., United Illuminating, CSU, Duke, NASUCA, Los 
Angeles, NYPP, DOE, SMUD, Otter Tail, PG&E, FirstEnergy, Mass 
Companies, Enron/APX/Coral Power, Nevada Commission.
---------------------------------------------------------------------------

    Some commenters emphasize that it is better to use market 
mechanisms to manage congestion than to rely on the physical 
interruption of power flows.467 NERC contends that if the 
industry had in place more market-oriented mechanisms that dealt 
effectively with constraints, then the frequency of transmission 
loading relief (TLR) procedures would decrease. Professor Hogan claims 
that with efficient pricing, users have the incentive to respond to the 
requirements of reliable operation. He asserts that, absent such price 
incentives, market choices would need to be curtailed in order to give 
the system operator enough control to counteract the perverse 
incentives that would be created by prices that did not reflect the 
marginal costs of dispatch. PJM/NEPOOL Customers argues that, when 
faced with a transmission congestion circumstance, the RTO should 
redispatch generators to the extent possible.
---------------------------------------------------------------------------

    \467\ See, e.g., NERC, Sithe, NASUCA, Cinergy, Professor Hogan, 
PJM, Dr. Ilic.
---------------------------------------------------------------------------

    Also, Statoil claims that the use of TLR procedures is inherently 
discriminatory. Statoil claims that most transmission owners serving 
retail load do not engage in interchange transactions or use the pro 
forma tariff at the same level as new competitive market entrants 
attempting to enter historically captive markets. Statoil thus argues 
that, even if TLR is applied in a comparable manner, it will still 
disproportionately and adversely affect new competitive market 
entrants.
    Role of the RTO in Congestion Management. Commenters offer a 
variety of views concerning the proper role of the RTO in congestion 
management. Some advocate an active role for the RTO in operating an 
energy market that is highly centralized.468 Others envision 
the RTO's role as being much smaller, perhaps limited to that of a 
facilitator that brings together market participants for the purpose of 
engaging in voluntary transactions to relieve congestion.469 
Still others, such as Southern Company and EEI, believe that RTOs are 
not necessary to make congestion management work. EEI argues that while 
congestion management does require a coordinated regional or 
interconnection-wide solution, it does not require the extensive 
infrastructure and responsibilities associated with what the Commission 
has proposed to define as RTOs. EEI notes that NERC's Congestion 
Management Working Group is exploring available options for congestion 
management, independently of whether RTOs exist.
---------------------------------------------------------------------------

    \468\ See, e.g., PJM, Professor Hogan, CSU, Sithe, NERA, Duke, 
PJM/NEPOOL Customers, H.Q. Energy Services, Minnesota Power, FTC.
    \469\ See, e.g., APX, SPP, South Carolina Authority, Alliant 
Energy, WPSC, NSP, TANC, Williams.
---------------------------------------------------------------------------

    PJM/NEPOOL Customers believes that an independent entity must 
operate any congestion management market. It believes also that that 
entity must have sufficient power and centralization to address 
congestion problems effectively and quickly. Consequently, it urges the 
Commission not to consider proposals that include a decentralized 
market for congestion management or that limit the RTO role to that of 
a facilitator of bilateral transactions to relieve congestion. In 
addition, it contends that the RTO must retain sufficient authority 
over generators that choose to make themselves available to ensure that 
those generators will participate in the congestion management market. 
Duke states that, eventually, decentralized markets may organize in a 
manner to accomplish effective congestion management, but at this time, 
the congestion management function should be centrally managed.
    PJM claims that RTOs can facilitate efficient, broad-scale 
congestion management. PJM states that by combining multiple 
transmission systems over a large geographic region, an RTO can have an 
effective pricing system to price efficiently actual transmission flows 
in a region. PJM argues that not only should the Commission require 
that RTOs be responsible for managing congestion with market 
mechanisms, the Commission also should prohibit any other entity from 
acting in a manner that detracts from the RTO's ability to employ its 
market mechanisms.
    Cleveland believes that an effective way to manage congestion may 
be to combine a market-based mechanism with a power exchange. It states 
that the RTO's redispatch function and the bidding process available 
through a power exchange should jointly operate to minimize the 
congestion.
    H.Q. Energy Services contends that control over the management of 
congestion goes hand-in-hand with control over reliability. It believes 
that, ideally, an RTO should establish a congestion pricing system that 
manages congestion with minimal operator intervention. However, H.Q. 
Energy Services argues that, without control over reliability, an RTO 
will not be in the position to accurately and fairly allocate available 
transmission capacity because it cannot send the correct congestion 
pricing signals.
    Sithe contends that the Commission should not allow overly 
decentralized systems whereby individual utilities in a region continue 
to manage congestion relief, especially if those utilities continue to 
own generation. Arkansas Consumers believe that the RTO's congestion 
management function helps provide a remedy for any anti-competitive 
activity on the part of generators or transmission owners. First 
Rochdale contends that only fully independent operation of an RTO is 
likely to lead to open markets in which all entities can compete 
freely. Duke asserts that there are no special considerations in 
evaluating market power in a congestion market operated or facilitated 
by an RTO.
    Other commenters stress that the RTO's role in managing congestion 
using market mechanisms should be strictly limited. Indeed, the South 
Carolina Authority opposes a centralized arrangement for managing 
congestion as being unduly restrictive and perhaps anti-competitive. 
WPSC argues that the role of the RTO should be limited to acting as a 
clearinghouse so that market participants are aware of the range of 
alternatives available for dealing with congestion. WPSC contends that 
the market will then dictate which mechanisms are used in any 
particular instance. SPP suggests that the RTO can be a facilitator of 
congestion relief and that there is no need for the Commission to 
require that the RTO adopt a centralized approach,

[[Page 879]]

such as locational marginal pricing, for managing congestion. SPP 
states that it is a facilitator of congestion relief and intends to 
continue in that role under its new proposal. SPP states that it will 
identify which generators can relieve a constraint and the relative 
impact of redispatching those generators. It will then be the 
customer's responsibility to contract with the owner of these 
generators for redispatch services. SPP notes that this method relies 
on the market and bilateral contracts for the redispatch solutions. SPP 
claims that the market can also provide for price assurance and for 
long-term redispatch obligations. PG&E claims that with the proper 
information, bilateral market-based redispatch could be used within an 
hour of the occurrence of congestion on any part of the controlled 
system.
    APX argues that the RTO should not conduct the trading process 
because it will impede the adaptation of trading to market conditions, 
which is essential for market development. APX claims that all 
competitive industries use decentralized trading through forward 
contracts, and no competitive industry uses a central bidding agent to 
create its market. Consequently, APX believes that the Commission 
should limit the RTO's role in congestion management to that of a 
provider of last resort. PG&E argues that although the RTO may 
administer certain market mechanisms such as congestion management, it 
is important that the RTO not view itself as responsible for energy 
pricing and other aspects of supply and demand interactions, all of 
which, PG&E contends, can be most effectively managed by the market 
unless material and lasting market flaws are present.
    Similarly, Cinergy argues that the mechanism for price transparency 
in the commodity market should be developed and implemented by the 
market, not the RTO. Cinergy recognizes, however, that an economic 
congestion management system depends on a power market mechanism that 
provides price transparency for determining economic dispatch of 
generation. Consequently, Cinergy notes, RTOs will be confronted with 
issues of applying an economic dispatch valuation mechanism. Cinergy 
argues that such mechanism should evolve from the marketplace, not 
directly from the RTO. Cinergy proposes that the RTO would administer 
the congestion management system, but would not be involved in the 
commodity market infrastructure unless its involvement was mutually 
agreeable among all stakeholders.
    Williams claims that decentralized markets for congestion 
management, operating under the auspices of RTOs, can work effectively 
and quickly in an environment in which market participants have the 
correct incentives. Williams states that depending upon the geographic 
size of RTOs and the extent of congestion within each, zones for 
congestion management may have to be developed. Williams provides a 
detailed description of how a zonal approach to congestion management 
can be implemented.
    Both CP&L and Enron/APX/Coral Power believe that the role of the 
RTO in congestion management should depend on the time frame in which 
the decisions are being made. These commenters prescribe different 
roles for the RTO in each of three different time frames.
    The Direct Dispatch Authority of the RTO. While supporting the use 
of pricing and other market mechanisms to manage congestion, a number 
of commenters state that an RTO must have authority to direct 
redispatch if necessary to ensure grid reliability.\470\ For example, 
Otter Tail contends that the RTO should have direct authority to order 
redispatch of generation for purposes of relieving congestion and 
during system emergencies. Otter Tail states that this dispatch should 
be directed for the generating units that can most economically reduce 
the congestion. Otter Tail states that because there is a need for 
immediate, real-time response to system contingencies and to relieve 
transmission congestion, the RTO should have control of generating 
units. East Kentucky contends that to effectively manage congestion, 
the RTO must have absolute authority to order redispatch of all 
generators on the RTO transmission system. However, for this to work, 
East Kentucky states that the RTO will have to compensate the generator 
with firm transmission service for the additional out-of-pocket costs 
incurred due to the redispatch, plus an amount for lost margins on lost 
revenue. It suggests that generators with non-firm transmission service 
would have to redispatch as directed by the RTO but would have to bear 
their own costs.
---------------------------------------------------------------------------

    \470\ See, e.g., Otter Tail, NERC, Allegheny, EME, NASUCA, East 
Kentucky, Williams, Minnesota Power, CSU. See also supra section 
III.D.3, which addresses the appropriate scope of the RTO's 
operational authority.
---------------------------------------------------------------------------

    NERC notes that market mechanisms may offer better ways of dealing 
with congestion management than does physical interruption of power 
flows, but asserts that it will always be necessary to have a non-
market mechanism such as transmission loading relief in place to ensure 
that the stability of the grid is always maintained. However, EME 
believes that the extent of RTO control over dispatch of generation 
should be carefully circumscribed to ensure maximum development of 
competitive markets in wholesale power and ancillary services. Seattle 
contends that where transparent power supply markets exist, price 
differences are widely known to the market and congestion can be 
resolved bilaterally with no intervention by an RTO. PJM notes that 
since implementing LMP, it rarely has needed to take emergency actions 
to alleviate transmission congestion.
    Minnesota Power believes that RTOs must have the authority to 
require that all generators, existing and new, agree to redispatch as a 
condition of grid connection. Minnesota Power also believes that the 
RTO must have the authority to penalize generators who subsequently 
refuse a redispatch order, or claim a false unplanned outage. CSU 
asserts that generation redispatch is essential in Front Range 
Colorado, which can be expected to have an increasing population of 
gas-fired generation within the boundaries of the constraints. It 
contends that the inability to redispatch these units for any reason 
other than reliability would severely hinder the ability of an RTO to 
address capacity constraints.
    MidAmerican states that, although congestion must be managed using 
pricing signals from the market, circumstances may occur where 
immediate actions are required and time does not permit normal bidding 
to allow the marketplace to respond. It contends that during such 
events, the RTO must be required to follow previously established 
procedures.
    However, Seattle argues that the RTO should not have authority to 
redispatch generation to accomplish congestion management without 
unanimous consent of the stakeholders. Seattle notes that many 
Northwest generating plant operators are subject to fishery-related 
hydroelectric dispatch constraints. Seattle states that because these 
constraints are particular to the owners of the generating facilities, 
these resources are not well suited to third party dispatch.
    Managing Congestion by Eliminating It. Some commenters contend that 
the ultimate goal of RTOs should be the elimination of congestion 
within their respective areas of control.\471\ Powerex believes that it 
is better to eliminate congestion at its source through facilities 
upgrades, if economically and environmentally feasible, rather than

[[Page 880]]

attempting to manage congestion on a long-term basis through congestion 
pricing schemes. Salomon Smith Barney believes that the Commission has 
overemphasized congestion pricing as a vehicle to price the existing 
network rather than as a vehicle to induce investment when such 
investment is an economical alternative.
---------------------------------------------------------------------------

    \471\ See, e.g., Williams, Powerex, Manitoba Board, Salomon 
Smith Barney.
---------------------------------------------------------------------------

    TDU Systems state that they do not want management of significant 
transmission congestion to become a long-term function of RTOs. They 
claim that minor congestion (i.e., congestion that is economically 
dealt with through redispatch of generators) will always be a feature 
of wholesale transmission markets, and an RTO should properly manage 
it. However, they argue that an RTO should deal with significant 
persistent transmission congestion by constructing (or having 
constructed) the appropriate transmission or generation facilities.
    Desirable Attributes of Market Mechanisms. Many commenters offer 
their views on the desirable attributes of any market mechanisms that 
are used to manage congestion.\472\ For example, PJM/NEPOOL Customers 
urges the Commission to employ three general criteria to evaluate any 
proposal: simplicity, visibility and predictability. They state that 
the proposed approach to relieve the congestion should be simple to 
administer, both for customers and for the RTO. They believe that 
market participants should be able to examine the operation of the 
congestion management mechanism on a real-time basis and verify that 
transmission access is being appropriately accorded to entities that 
most desire transmission service. They state that such visibility will 
engender confidence by market participants in the congestion management 
mechanism. In addition, they believe that the congestion management 
mechanism must be predictable to all transmission users to determine 
the anticipated price that will be necessary to ensure the continuation 
of transmission service if congestion occurs.
---------------------------------------------------------------------------

    \472\ See, e.g., NASUCA, CMUA, NSP, PG&E, Statoil, SMUD, 
UtiliCorp, PacificCorp, PJM/NEPOOL Customers, Metropolitan, Cal DWR.
---------------------------------------------------------------------------

    Cinergy states that an economically efficient congestion management 
system must begin with properly defining information posting 
requirements. Accordingly, Cinergy argues that the Final Rule should 
ensure that requisite information on congestion is posted on the OASIS. 
Similarly, Williams and Industrial Consumers believe that RTO access to 
region-wide information on network conditions and power transactions, 
coupled with efficient congestion management and well specified 
transmission rights, could help RTOs in taking preemptive actions 
against potential curtailment incidents. Statoil and EPSA believe that, 
ideally, economic rationing schemes should be uniform across RTOs and 
should be implemented as an ancillary service under a regional 
transmission tariff. Montana Commission asserts that congestion 
management must be efficient. CMUA believes that congestion management 
mechanisms must do their job, but not unreasonably interfere with 
choices by market participants.
    Some commenters believe that efficient congestion management 
requires a transparent commodity market. Cinergy states that market 
mechanisms that include locational pricing and financial rights for 
firm transmission have been successfully implemented where they are 
supported by a power exchange or pool pricing mechanism that provides 
market-clearing prices and price transparency. CalPX emphasizes the 
value of a separate power exchange and argues that the bifurcation of 
the exchange and transmission operator functions does not add to the 
market cost of congestion management, as some have suggested. Also, 
Otter Tail believes that the development of an hour-ahead power 
exchange within the RTO would improve grid reliability.
    Many commenters support the NOPR's requirement that market 
mechanisms be used to manage congestion and note the particular value 
of using price as a tool to manage congestion.\473\ Some commenters 
specifically endorsed the proposed requirement that congestion pricing 
proposals must meet the two efficiency objectives set forth in the 
NOPR.\474\ PJM/NEPOOL Customers state that these two objectives are 
fundamental to the operation of a market and to the ultimate goals of 
electricity supply competition.\475\ SMUD believes that a well-designed 
congestion management policy, that provides proper locational price 
signals without creating opportunities for gaming or cost shifting, 
will attract market participation. SMUD agrees that market participants 
must be given efficient price signals concerning their use of the 
transmission system, but claims that this is difficult because the 
existing transmission grid was not designed with the capability to 
operate as a common carrier or to serve customers in an open access 
manner. Also, a few commenters expressed doubts about the overall value 
of using pricing mechanisms to manage congestion,\476\ and others cited 
reasons to move cautiously.\477\ Tri-State is skeptical that market 
mechanisms for managing congestion will lead to a least-cost dispatch. 
Tri-State states that entities with firm transmission rights on the 
congested path may be reluctant to participate voluntarily in 
generation redispatch that will jeopardize the economics of long-term 
power supply contracts or firm resources, even if the result would 
lower costs.
---------------------------------------------------------------------------

    \473\ See, e.g., PJM/NEPOOL Customers, United Illuminating, 
Allegheny, EPSA, SMUD, Los Angeles, NASUCA, Duke, NERC, Professor 
Hogan, EME, PJM, DOE, CSU.
    \474\ See, e.g., PJM/NEPOOL Customers.
    \475\ However, Montana Commission asks the Commission to specify 
more precisely the nature of the pricing and congestion management 
methods that will satisfy the NOPR's efficiency objectives.
    \476\ See, e.g., LIPA, Transmission ISO Participants.
    \477\ See, e.g., EPSA, Tri-State.
---------------------------------------------------------------------------

    Several commenters suggest principles to guide the design of 
congestion pricing mechanisms.\478\ NASUCA states that any mechanism 
for using congestion prices for managing transmission system flows 
should be easy to implement; designed to minimize cost shifts; designed 
to support an economically efficient dispatch; and coordinated with the 
underlying transmission rate design. PacifiCorp states that key 
components of a good market-based congestion clearing methodology are: 
(1) Tradable transmission capacity reservations; (2) a system in which 
all parties who can clear congestion can bid to do so; (3) the 
establishment of congestion costs far enough in advance to facilitate 
reasoned decision-making; and (4) the avoidance of any RTO rules that 
substantially reduce liquidity in power markets. UtiliCorp believes 
that a congestion management system should establish tradeable rights 
for transmission usage, promote efficient regional dispatch, support 
the emergence of secondary market for transmission rights, and give 
market participants the opportunity to hedge locational differences in 
energy prices. However, Enron/APX/Coral Power disagrees on the latter 
feature. It contends that the monopoly wires business should not be 
allowed to encroach on what they see as the highly competitive and 
innovative business of providing hedges against locational price 
differences of energy or capacity or against price volatility of these 
or any other competitive products.
---------------------------------------------------------------------------

    \478\ See, e.g., NASUCA, NJBUS, PJM/NEPOOL Customers, EPSA, 
Enron/APX/Coral Power.
---------------------------------------------------------------------------

    Cal DWR and Metropolitan urge the Commission to adopt RTO 
ratemaking principles that include off-peak rates.

[[Page 881]]

Cal DWR believes that customers should face accurate transmission price 
signals and, therefore, transmission prices should be lower in periods 
of off-peak demand for transmission. Cal DWR believes that off-peak 
pricing provides an accurate price signal over the longer term, 
promoting investment necessary to shift transmission usage to off-peak 
periods. In addition, Metropolitan believes that off-peak pricing can 
help to resolve problems of cost-shifting.
    A number of commenters emphasize certain benefits of a well 
designed congestion pricing policy, claiming that price signals can 
assist RTOs and market participants in determining the efficient size 
and location of both new generation and new grid expansions.\479\ Los 
Angeles argues that ensuring accurate market signals through the 
creation of a congestion pricing mechanism will be the keystone to 
future system planning. Los Angeles states that these signals should 
alert generators to the advantages of siting in congested areas, 
motivate marketers and distribution companies to develop demand-side 
management options, and generally foster marketplace innovation. Los 
Angeles also believes that congestion price signals should help in 
determining the proper size of transmission upgrades that the RTO might 
build to relieve congestion. Otter Tail believes there exists a great 
need for new transmission capacity and, indeed, argues that the overall 
focus of the NOPR and FERC transmission policy should be on providing 
the appropriate financial incentives to assure investment in and 
expansion of the system.\480\ To ensure that price signals translate 
into appropriate expansion of the grid, SMUD believes that the RTO must 
be sufficiently independent and strong to require the expansion of the 
grid. NASUCA notes that, while congestion cost pricing may help to 
signal where new generation and transmission lines are needed, it may 
not be necessary for the efficient daily operation of the transmission 
grid.
---------------------------------------------------------------------------

    \479\ See, e.g., Allegheny, EME, United Illuminating, EPSA, 
SMUD, Los Angeles, NASUCA, CSU.
    \480\ Other commenters emphasize the need for significant 
investments to expand transmission capacity. See, e.g., EPRI, 
Salomon Smith Barney.
---------------------------------------------------------------------------

    Other commenters believe that it may be difficult to design market 
mechanisms to provide incentives for the efficient expansion of the 
grid.\481\ H.Q. Energy Services states that currently, the rules for 
congestion management do not act as a sufficient incentive to 
transmission owners to upgrade facilities. NWCC states that it is 
unclear whether congestion charges can act as a means of driving 
transmission expansion, since adding transmission is, by nature, 
capacity-based. NWCC also states that it is unclear whether congestion 
costs will be an adequate incentive for market participants to finance 
transmission expansion on their own, given the extensive permitting and 
regulatory requirements that are involved. LIPA states that, while new 
location-based pricing mechanisms have not been in place long enough to 
determine if they will provide empirical evidence that is helpful in 
identifying efficient transmission expansions, it believes that the 
mechanisms do not provide sufficient incentives for development of 
transmission. Also, LIPA claims that they do not provide a useful 
signal when reliability, as opposed to economic efficiency, drives the 
need for transmission enhancements.
---------------------------------------------------------------------------

    \481\ See, e.g., Transmission ISO Participants, SoCal Edison, 
H.Q. Energy Services, LIPA, NWCC.
---------------------------------------------------------------------------

    SoCal Edison criticizes the congestion management policies 
implemented by the Cal ISO, stating that procedures intended to 
encourage the voluntary mitigation of congestion through investment in 
new transmission may not provide a sufficient incentive. SoCal Edison 
contends that, while correct congestion price signals will assist in 
the identification of transmission investment needs, they will not 
eliminate fundamental disputes among affected market participants over 
the responsibility for the costs of new transmission or eliminate the 
risks associated with attempting to construct new transmission 
projects. It asserts that the Commission cannot simply assume that the 
market will respond to congestion signals if, at the same time, it is 
creating a regulatory climate that discourages investment in new 
transmission. SoCal Edison believes that impediments to grid expansion 
can be overcome only if the Commission adopts transmission pricing 
policies that more accurately reflect the value that new transmission 
investments bring to electric consumers. Similarly, FirstEnergy argues 
that if the Commission desires an efficient generation market that 
optimizes the public good, then a mechanism that allows transmission 
owners to capitalize on increases in the transmission capacity at fair 
market value must be found. FirstEnergy contends that the interaction 
of these free market forces will drive the proper allocation of 
resources between transmission and generation over the long term.
    Locational Marginal Pricing. A number of commenters advocate the 
use of locational marginal pricing (LMP) for congestion 
management.\482\ Professor Hogan states that, with LMP, the security-
constrained economic dispatch process would produce prices for energy 
at each location, incorporating the combined effect of generation, 
losses and congestion. He states that the corresponding transmission 
price between the location where power is supplied and where it is used 
would be determined as the difference between the energy prices at the 
two locations. Professor Hogan therefore contends that this same 
framework is easily extended to include bilateral transactions. 
Professor Hogan states that, with LMP, the system operator coordinates 
the dispatch and provides the information for settlement payments, with 
regulatory oversight to guarantee comparable service through open 
access to the pool run by the system operator through a bid-based 
economic dispatch. He claims that PJM implemented LMP after 
experimenting with an alternative market model and pricing approach 
that proved to be fundamentally inconsistent with a competitive market 
and user flexibility. He states that the earlier pricing system allowed 
market participants the flexibility to choose between bilateral 
transactions and spot purchases, but did not simultaneously present 
market participants with the costs of their choices. He states that 
this created perverse incentives. Professor Hogan argues that LMP is 
the only workable system that can support a non-discriminatory 
competitive market that allows for participant choice and flexibility.
---------------------------------------------------------------------------

    \482\ See, e.g., Professor Hogan, PJM, NERA, Sithe, Allegheny, 
Mid-Atlantic Commissions, DOE, Duke, United Illuminating, EME.
---------------------------------------------------------------------------

    PJM states that the Commission correctly concludes that LMP will 
``encourage efficient use of the transmission system, and facilitate 
the development of competitive electricity markets.'' PJM notes that, 
under LMP, transmission customers are assessed congestion charges 
consistent with their actual use of the system and the actual 
redispatch that their transactions cause. It claims that this provides 
an economic choice to non-firm transmission customers to self-curtail 
their use of the transmission system or pay congestion charges 
determined by the market. PJM believes that by basing congestion 
charges on the true redispatch cost, parties behave in a rational and 
efficient manner. It states that the market determines the clearing 
price for transmission congestion and which customers ultimately 
utilize the transmission system. PJM states that the use of fixed 
transmission rights (FTRs)

[[Page 882]]

enables market participants to pay known, fixed transmission rates and 
to hedge against congestion charges.
    The FTC believes that accurate LMP signals for investment to reduce 
congestion may become even more important as distributed generation 
presents opportunities for small-scale, fine-tuned (with respect to 
both size and location) generation investments to relieve transmission 
congestion, in place of large-scale transmission or generation 
investments. EME endorses the LMP pricing approach adopted by PJM and 
the New York ISO, and states that the Midwest ISO and the Alliance RTO 
should be encouraged to adopt similar approaches. The CalPX notes that 
the separation of the CalPX and the ISO in California does not prevent 
the use of a locational pricing model that incorporates the individual 
buses and transmission lines in the network.
    Allegheny believes that ``[c]onsistent locational marginal price 
dislocations readily identify system expansion, or other congestion 
relief, requirements as well as serve as an indicator of the most 
economic fix to congestion patterns over time.'' It claims that there 
would be no incentives for the RTO or transmission owners to maintain 
congestion, since there is no financial impact on them from LMP because 
any excess payments received by the RTO during congestion are returned 
to holders of FTRs. Allegheny recommends that the Commission remain 
flexible in considering other pricing innovations for congestion 
management, but believes that a simplified locational marginal pricing 
methodology should be established as a default market mechanism against 
which other pricing innovations are evaluated.
    Some commenters, however, criticize the locational marginal pricing 
approach to congestion management.\483\ APX argues that, because LMP 
requires the RTO to implement a centrally optimized dispatch, it will 
discourage, if not eliminate, the commitment of forward contracts in 
the energy market and replace the price discovery of forward markets 
with ex post pricing. APX contends that because LMP price calculations 
occur only periodically and in a single iteration, price visibility is 
restricted compared to a continuous forward market. APX claims that 
this diminished visibility can make the result less efficient and more 
vulnerable to an exercise of market power. APX contends that, for most 
industries, a process of continuous trading creates efficiency in a 
competitive market, while the LMP optimization process has no role for 
trading. APX asserts that no competitive industry uses optimization to 
simulate and substitute for market outcomes. APX contends that under 
LMP, the system operator, not the market, will specify the structure of 
the optimization problem. APX claims that markets process information 
much more flexibly and comprehensively through the self-interested 
trading behavior of buyers and sellers. APX asserts that this is the 
strength of markets and the critical shortcoming of LMP.
---------------------------------------------------------------------------

    \483\ See, e.g., APX, LIPA, TDU Systems, CP&L, Virginia 
Commission, Tri-State, Dynegy.
---------------------------------------------------------------------------

    Dynegy claims that markets for FTRs have yet to fulfill their 
promise to provide market participants with critically important price 
certainty for their transmission transactions. For example, Dynegy 
states that allocation problems still exist, in that only a small 
portion of available FTRs is being auctioned off in certain markets 
while a large number are being withheld for incumbents' use. Dynegy 
argues that in order for FTRs to provide a truly effective hedge 
against transmission price increases resulting from LMP in the hourly 
market, hourly FTRs would have to be available in a liquid market at a 
moment's notice, but nothing close to such a market exists. Dynegy 
suggests that, because the LMP model has yet to be implemented 
successfully due to the lack of a liquid FTR market, the time is ripe 
to look at other models, such as a physical rights model.
    LIPA claims that neither the opportunity to obtain fixed 
transmission rights nor the prospect of locational price reductions are 
sufficient to encourage efficient generation and transmission 
expansions. For example, LIPA notes that awarding a transmission 
expander transmission rights that entitle it to collect congestion 
rents on the expanded capacity creates an incentive that runs counter 
to the purpose of the expansion; i.e., the more successful the 
expansion is in eliminating congestion, the less value the incentive 
has for the expander. Also, LIPA believes that locational pricing 
systems are biased toward using generation to solve congestion problems 
on the transmission grid and, as a result, could lead to market power 
abuse by an operator that sites a new generator in a load pocket and 
then takes advantage of transmission limitations to manipulate the 
operation of other generators that it owns.
    The Virginia Commission claims that pricing mechanisms 
incorporating locational marginal prices tend to produce intense 
signals over short time frames, particularly when constraints are 
seasonal and driven by extraordinary events such as extreme weather. 
The Virginia Commission therefore believes that, at least initially, 
locational marginal prices may provide incentives for short-term 
actions for congestion relief, rather than longer term solutions such 
as the construction of additional transmission or generating facilities 
in a particular location.\484\ The Virginia Commission also states that 
the use of locational marginal pricing is heavily dependent on the 
existence of transparent short-term competitive power markets. It urges 
the Commission to evaluate carefully proposals that place greater 
reliance on market mechanisms through the use of price signals, and to 
condition the use of such mechanisms on the existence of such things as 
fully functioning power exchanges, the establishment of fixed 
transmission rights and the existence of secondary markets for such 
rights.
---------------------------------------------------------------------------

    \484\ The Brattle Group believes that, in addition to locational 
congestion pricing, some form of regulatory incentives may be needed 
to bring about efficient investment in the transmission grid.
---------------------------------------------------------------------------

    CP&L argues that while the proposed congestion management rule 
appears to permit only PJM-redispatch types of arrangements, CP&L does 
not believe that the PJM model is the only workable congestion 
management process. Rather, CP&L believes that congestion is best 
managed through the coordinated reservation and scheduling of 
transactions on the grid rather than post-congestion fixes. Also, TDU 
Systems states that it may be difficult to transplant the PJM model to 
regions that do not have a centrally dispatched, tight power pool to 
use as an RTO platform.
    Some commenters claim that LMP is more complex than necessary,\485\ 
although Allegheny believes that today's technology mitigates these 
concerns. The FTC states that, despite the apparent virtues of LMP, it 
may be reasonable to back away from a full application of an LMP 
approach if doing so provides benefits to consumers from increased 
competition in generation markets. For example, the FTC states that, in 
light of its alleged complexity and the difficulty that financial 
markets may have in anticipating congestion charges, LMP may inhibit 
the formation of efficiency-enhancing futures markets in electricity 
generation and trading because congestion prices are more uncertain 
under LMP than under other pricing approaches (such as zonal 
transmission congestion pricing). The FTC thus suggests that the 
Commission may want to continue to entertain alternatives to LMP if a 
reasonable case is made that benefits to consumers are

[[Page 883]]

greater under the alternatives than under LMP.
---------------------------------------------------------------------------

    \485\ See, e.g., PG&E, PJM/NEPOOL Customers, FTC, Tri-State, 
Dynegy.
---------------------------------------------------------------------------

    Managing Congestion with Tradable Transmission Rights. Several 
commenters emphasize the importance of including explicit transmission 
rights in any congestion management plan that relies on market 
mechanisms.\486\ EPSA believes that when transmission rights are 
clearly defined and allocated, ATC calculations can be made more 
accurately and congestion management simplified. DOE notes that 
financial transmission rights will provide a hedge against long-term 
fluctuations in spot prices, will encourage the development of 
competitive markets and will likely contribute to efficient generation 
and transmission resource planning. SMUD emphasizes that, without the 
pricing hedge provided by such rights, it cannot guarantee its 
customer-owners low cost or reliable transmission service.
---------------------------------------------------------------------------

    \486\ See, e.g., PJM, SMUD, DOE, Enron/APX/Coral Power, EPSA, 
NSP, Seattle, Professor Hogan, EME.
---------------------------------------------------------------------------

    A number of commenters emphasize that transmission rights must be 
tradeable in a secondary market.\487\ Indeed, some commenters believe 
that the use of firm (physical) transmission rights along with a robust 
secondary market in these rights is the most workable solution for 
efficient congestion management.\488\ Seattle notes that with an 
effective market for transmission rights, market participants may be 
afforded transmission-based options for resolving congestion. It states 
that market participants that invest in transmission facilities that 
increase capacity can receive the right to use or sell that capacity. 
Enron/APX/Coral Power believes that the RTO should be charged with 
developing a workable market approach to congestion and parallel-path 
management based on clear and tradeable rights for transmission usage 
that promote efficient regional dispatch, and support the emergence of 
secondary markets for transmission rights. Enron/APX/Coral Power 
contends that this will require that RTO systems be operated as they 
are in the Western Interconnection based on physical rights. It 
suggests that, in order to ensure a firm right to schedule service over 
an interface when it is constrained, a customer would have to 
demonstrate ownership of sufficient property rights in the interface. 
Enron/APX/Coral Power suggests three options for obtaining rights: (1) 
From the RTO in the primary auction or other primary form of 
allocation; (2) from holders of rights in the secondary market; and (3) 
from the RTO in the form of short-term released rights not scheduled by 
their holders. Enron/APX/Coral Power states that by defining and 
enhancing physical property rights, the market for those rights will 
provide ex ante transmission prices that include the cost of purchasing 
rights in constrained interfaces. It claims that this will permit 
dispatch decisions to be made on the basis of delivered energy prices. 
Enron/APX/Coral Power states that to ensure that no market participant 
can exercise market power by hoarding property rights, the rights 
should be designed as use-or-lose so that if a right is not scheduled 
it can be used by others on a non-firm basis.
---------------------------------------------------------------------------

    \487\ See, e.g., DOE, NSP, Enron/APX/Coral Power, Seattle, 
Nevada Commission.
    \488\ See, e.g., APX, Enron/APX/Coral Power, Tri-State, Desert 
STAR.
---------------------------------------------------------------------------

    Similarly, Dynegy proposes a physical rights model in which a 
limited amount of firm physical rights would be sold and only those 
holding physical rights would be allowed to schedule when capacity is 
constrained. Under Dynegy's proposal, only those with preassigned FTRs 
would be allowed to schedule on a firm basis at a set price. Dynegy 
states that others could submit non-firm schedules, subject to 
curtailment, or, if the party is willing, redispatch. Dynegy adds that 
the proponents of rights that are financial only argue that it is 
impossible to define physical rights as ``100 percent firm'' from a 
given source to a given sink. Dynegy states that, while such arguments 
are convincing, the capacity between a source and sink may actually be 
available for a significant percentage of the time to a reasonable 
degree of certainty and, accordingly, could be sold as firm.
    APX states that the definition of transmission property rights 
requires the calculation of stable power distribution factors that show 
the proportion of a power transaction that flows over each path on the 
grid connecting the source-sink pair. It states that after defining the 
property rights, the RTO can conduct an auction to allocate them. APX 
states that, following the auction, holders of transmission rights can 
retain them or trade them in a secondary forward market. APX believes 
that FTR trading will provide a more direct and comprehensive valuation 
of rights than LMP. Desert STAR states that it plans to rely on firm 
transmission rights markets as the primary vehicle for managing 
commercially significant congestion, and the use of incremental/
decremental generation bids to manage other congestion.
    Other commenters, however, doubt that a system of physical 
transmission rights can be used effectively to manage congestion.\489\ 
NERA states that most commodity markets operate according to a process 
based on physical contracts or rights traded in decentralized markets 
separated from physical operations. NERA adds, however, that most 
commodities do not flow on an integrated grid where network 
externalities are so strong and complex that a monopoly system operator 
is needed. NERA argues that network externalities on any complex 
electricity grid make it virtually impossible to define physical 
transmission rights that will use the system fully and yet can be 
traded in decentralized markets. Also, Professor Joskow believes that 
on complex electric power networks with loop flow, a financial rights 
system can be designed more easily and can work more smoothly and 
efficiently than can a physical rights system.\490\
---------------------------------------------------------------------------

    \489\ See, e.g., NERA, Professor Joskow, Allegheny.
    \490\ Professor Joskow notes that Enron/APX/Coral Power claims 
that two unpublished papers he has co-authored with Jean Tirole 
conclude that physical rights designed on a use-it-or-lose-it basis 
(so that they cannot be hoarded) more effectively prevent the 
exercise of market power than financial rights, which can always be 
hoarded. He states that this is not what the papers conclude.
---------------------------------------------------------------------------

    Some commenters offer additional notes of caution regarding the use 
of transmission rights. For example, APPA states that one must guard 
against market participants using transmission rights to act 
strategically. APPA argues that if a generator can adversely affect 
transfer capability, it may seek to purchase and resell transmission 
rights in the secondary market after manipulating its internal 
operations to create congestion on the grid. RECA considers proposals 
that allow customers to purchase long-term rights to mitigate the risk 
of congestion pricing to be unacceptable because such proposals result 
in long-term firm customers having to pay a premium for price 
stability. Also, CSU contends that no party should hold any entitlement 
over a constrained path due to transmission ownership which predates 
the formation of the RTO. CSU argues that, because all parties 
dedicating bulk transmission assets to the RTO will be fully 
compensated for their embedded costs, there should exist no reserved 
rights of use other than those purchased from the RTO. In addition, 
Great River is concerned that the NOPR's proposal regarding the 
establishment of clear and tradable transmission rights is not 
consistent with the flexibility that transmission customers currently 
have under network service. Great River urges the Commission to 
carefully consider congestion management proposals that preserve 
network-like

[[Page 884]]

service, even if such proposals do not result in the identification of 
asset-based transmission rights.
    Other Mechanisms for Managing Congestion. Some commenters support 
yet other market mechanisms for managing congestion.491 EPSA 
notes that other pricing approaches that deserve consideration include 
the RTO's use of supply-side bids to relieve congestion in load 
pockets, as well as the use of bilateral arrangements to solve 
congestion problems. Also, NSP recommends that the RTO offer a 
``firming'' service, at posted rates, that would provide customers with 
the assurance that their transaction will occur under most curtailment 
conditions. In addition, NSP proposes that the RTO offer a real-time 
redispatch service that will allow transmission customers to buy 
through congestion at real-time prices. Cal ISO notes that the 
Commission has accepted its zonal approach to congestion management, 
which relies on market mechanisms to manage inter-zonal congestion. 
PG&E claims, however, that while providing a more understandable 
picture of congestion, such a system must still solve the problem of 
intra-zonal congestion. Also, the Montana Commission recommends that 
the congestion management regime that was developed as a part of the 
IndeGO proposal serve as a model for how to manage congestion on the 
transmission system. However, Avista claims that the IndeGo proposal 
proved to be too complicated to solve a problem that exists only on a 
few select transmission paths in the Pacific Northwest.
---------------------------------------------------------------------------

    \491\ See, e.g., Cal ISO, Montana Commission.
---------------------------------------------------------------------------

    Costs and Revenues in Congestion Management. A number of commenters 
urge the Commission to pay close attention to issues related to the 
distribution of the costs and revenues of congestion management among 
market participants.492 In particular, several commenters 
caution that congestion pricing mechanisms should ensure that 
congestion costs are fairly allocated and should not result in 
excessive revenues or monopoly profits for transmission 
owners.493 APPA states that only after we have a nationwide 
framework of truly independent RTOs should the Commission consider a 
new approach to transmission pricing that would allow the RTO to price 
transmission capacity rights and usage on congested paths above 
embedded costs while discounting uncongested paths below embedded 
costs, subject to a balancing account to ensure that the total 
transmission revenue requirement is not over-recovered.
---------------------------------------------------------------------------

    \492\ See, e.g., TDU Systems, NCPA, Los Angeles, Wyoming 
Commission, SMUD, South Carolina Authority.
    \493\ See, e.g., APPA, RECA, TDU Systems, Los Angeles, EPSA.
---------------------------------------------------------------------------

    Similarly, TDU Systems believe that while the formation of RTOs is 
a unique opportunity to experiment with new forms of transmission 
pricing, the Commission should be mindful that an RTO will be a large 
regional transmission monopoly. TDU Systems question the wisdom of 
designing congestion pricing mechanisms to ensure that limited 
transmission capacity is used by market participants who value that use 
most highly. It states that such an auction-to-the-highest-bidder 
approach could reap monopoly rents for transmission providers, at the 
expense of consumers. TDU Systems thus argues that over-reliance on 
economic self-interest and market mechanisms in transmission pricing 
may become a recipe for new forms of undue discrimination. It suggests 
that an incentive to avoid expanding the system in order to collect 
monopoly rents can be removed by placing any excess revenues from 
congestion pricing in a fund earmarked for transmission system 
expansion.
    TDU Systems also recommends that the Commission encourage 
congestion management plans that distinguish between congestion caused 
by the RTO's obligation to provide service to firm transmission 
customers, and congestion caused for economic reasons. It argues that, 
in the case of the former, the costs of relieving the congestion should 
be averaged over the firm RTO transmission customers that are using its 
system. However, it claims that economic congestion occurs because 
market participants wish to take advantage of short-term production 
cost economies to minimize their power costs. In this case, TDU Systems 
argues that the specific loads purchasing the generation should pay the 
associated congestion costs. Also, RECA states that long-term firm 
transmission customers are the ones that use and pay to support the 
system throughout the year, but the auction approach allows a short 
term trader to outbid these customers at the very times they need it 
most. Enron/APX/Coral Power notes that, if the RTO's regulated rates 
for transmission service, including congestion management, are properly 
designed to reward the RTO for cutting operating costs and maximizing 
throughput, then it would not have to assign the grid expansion costs 
to new generators that interconnect. Instead, the RTO would charge the 
new generator only the cost of local interconnection with the grid.
    Dynegy claims that, with respect to each transmission provider's 
system, there is a predictable level of constraints and, similarly, 
some representative level of costs associated with relieving those 
constraints. Dynegy believes that such costs should be rolled into firm 
transmission rates that can be quoted up front and with certainty. 
Dynegy argues that transmission providers would have an economic 
incentive to operate their transmission systems efficiently if they are 
given an uplift cost target, and are rewarded for beating the target 
and penalized for exceeding the target. EPSA states that some 
congestion pricing mechanisms can impose potentially huge costs on 
individual transactions, which can be detrimental to the goal of 
fostering wholesale competition. EPSA thus urges the Commission to 
consider whether these pricing mechanisms provide greater benefits than 
a system that internalizes more of the congestion costs. Indeed, EPSA 
argues that it is still appropriate to spread many of those costs to 
all system users because redispatch generally benefits all users of the 
transmission system.
    NCPA asserts that, in order to prevent large increases in the cost 
of generation for customers in congested areas, some non-discriminatory 
way must be found to return the extra revenues collected to those 
customers. NCPA believes that this will require restructuring of 
tariffs, but failure to address the problem is likely to keep utilities 
with customers in congested areas out of the California ISO. Similarly, 
the South Carolina Authority is concerned that certain centralized 
market mechanisms would cause cost shifts for those participating in an 
RTO, and if so, potential participants opt out. Also, the Wyoming 
Commission is concerned that, by offering rewards for transmission 
investment such as a higher return on equity, the Commission would 
effectively be discouraging a more market-oriented review of 
alternatives to building transmission to solve congestion problems.
    Some commenters emphasize the importance of ensuring full cost 
recovery for generators that are redispatched by an RTO to alleviate 
transmission constraints or to provide other support 
services.494 NERC contends there must not be disincentives, 
in the form of unrecovered costs, to having generators perform these 
vital functions. MidAmerican asserts that optimal dispatch will occur 
during congestion management as long as all power suppliers are fully 
compensated at

[[Page 885]]

market prices. Cinergy claims that, unless generators have the ability 
to recover lost revenues for reducing generation in response to 
congestion management needs, generators have no incentive to follow 
dispatch orders. SMUD contends that the Commission needs to develop 
congestion management principles that ensure that market participants 
will receive fair market value for facilities that they have owned and 
operated for many years.
---------------------------------------------------------------------------

    \494\ See, e.g., Allegheny, Platte River, NERC.
---------------------------------------------------------------------------

    Importance of Scale in Congestion Management. A number of 
commenters argue that the achievement of an appropriate scale by an RTO 
will be important to the effective management of 
congestion.495 LG&E states that the Commission should 
require RTOs to be of sufficient size to be capable of meaningfully 
addressing congestion. It believes that if a proposed RTO's ability to 
address congestion would be impaired by its size or configuration, then 
the Commission should either refuse the RTO's application or should 
condition approval on attaining the necessary size and configuration to 
manage regional congestion issues. Industrial Consumers state that, 
although congestion management can be addressed with non-market 
solutions such as transmission loading relief procedures, it is far 
better to internalize the problem within an RTO with an appropriate 
scope and configuration. Minnesota Power notes that, currently, it can 
have transactions curtailed by two different procedures, NERC 
Transmission Loading Relief and MAPP Line Loading Relief. It claims 
that an RTO will provide transmission users with region-wide, standard, 
congestion management.
---------------------------------------------------------------------------

    \495\ See, e.g., LG&E, ComEd, Midwest ISO Participants, Midwest 
ISO.
---------------------------------------------------------------------------

    The Midwest ISO states that an appropriately sized RTO will be able 
to relieve congestion on a broad scale. However, it claims that its own 
redispatch options will be limited by the failure of border companies, 
such as FirstEnergy and AEP, to join it. Also, it notes that longer 
term congestion relief involves the construction of transmission 
facilities. It claims that, if border companies are not members, the 
Midwest ISO will not have the ability to coordinate required 
transmission construction by those entities. Also, the Midwest ISO 
Participants state that new transmission facilities required to relieve 
constraints may involve both the companies of the Alliance RTO and the 
Midwest ISO Participants. The Midwest ISO Participants believe that, 
with planning and authority split between these two regional entities, 
these facilities may not be optimally constructed or located.
    Ontario Power, however, takes a different view. It claims that many 
of the advantages that would flow from expanding U.S. markets to 
include Ontario can be realized without requiring the Independent 
Electricity Market Operator (IMO) in Ontario to join a larger RTO at 
this time. Ontario Power believes that these advantages could be 
achieved by negotiating agreements between the IMO and other RTOs. 
Also, Central Maine states that if transmission line loading relief is 
performed on a market basis, many of the benefits that might result 
from merging existing ISOs could be realized without actually requiring 
those ISOs to merge.
    Tri-State argues that the Commission should provide an incentive 
for non-participating transmission owners to join an RTO by allowing 
the RTO to use a pricing and congestion management structure that 
withholds the benefits of the RTO from entities that refuse to turn 
control of their transmission assets over to the RTO. Also, Vernon 
claims that non-participants can take unfair advantage of ISO-
controlled facilities by scheduling their own loads over ISO grid 
facilities that parallel the non-participant paths, instead of 
scheduling them over their own wires. Vernon contends that having thus 
freed up their own wires, the non-participants can then put their 
facilities to various uses, such as to avoid the increased ISO grid 
congestion.
    Congestion Management Between RTOs. Many commenters believe that 
effective congestion management must take into account effects that 
extend beyond the RTO's boundaries.496 NERC states that 
congestion management approaches that work within a particular region 
may not adequately deal with transactions that originate or terminate 
outside the region. NERC believes that as RTOs develop congestion 
management approaches, the Commission must require that they be 
compatible with what is happening elsewhere.
---------------------------------------------------------------------------

    \496\ See, e.g., NERC, Mass Companies, Industrial Consumers, 
Montana Commission, Indiana Commission, AEP.
---------------------------------------------------------------------------

    Industrial Consumers believe that congestion management, especially 
during emergency conditions, is an interconnection-wide responsibility. 
It asserts that, if multiple RTOs are allowed within an 
interconnection, congestion management must be coordinated across RTO 
boundaries. Industrial Consumers argues that an RTO can accomplish this 
only by sharing data on system conditions (e.g., ATC calculations) with 
neighboring RTOs, agreeing to protocols for cross-boundary actions to 
mitigate congestion, and cooperating in a process to ensure fair 
compensation to generators that are redispatched.
    UAMPS believes that if a state is involved in the consideration of 
various potential solutions to regional congestion, it will likely be 
more willing to accept that a particular proposal to construct new 
transmission within its borders is indeed the most efficient solution 
to a genuine problem, and to provide the necessary approvals for that 
construction.
    Transcos and Congestion Management. Some commenters are concerned 
that, if a for-profit company owns transmission (e.g., a transco), it 
may not have the correct incentives to manage congestion 
efficiently.497 ISO-NE argues that if such a company seeks 
to operate transmission and markets as an RTO, it will have competing 
responsibilities and economic interests. ISO-NE believes that, given 
the company's economic motivations, market participants may have 
insufficient confidence in such a company's determinations of whether a 
transmission-expansion solution to congestion is preferable to a 
generation-based solution. EAL believes that compensating a wire-owning 
RTO on the basis of invested capital could lead to over-building of 
transmission. New Smyrna Beach is concerned that a for-profit 
transmission company will exhibit a bias toward transmission 
construction when other, more economical alternatives might exist. New 
Smyrna Beach states that the Commission should consider requiring the 
RTO to conduct a competitive bidding process when it determines that 
transmission construction, or an alternative, is needed to relieve 
transmission constraints.
---------------------------------------------------------------------------

    \497\ See, e.g., ISO-NE, EAL, New Smyrna Beach, Industrial 
Consumers.
---------------------------------------------------------------------------

    Industrial Consumers asserts that transcos would compete head-on 
with generation companies wherever there is congestion. It thus 
believes that transcos-as-RTOs would have a serious conflict of 
interest if they have the authority over congestion management and over 
the decision whether to eliminate congestion with new generation or 
transmission facilities. Industrial Consumers believes that where new 
generation is a more cost-effective option than construction of new 
transmission facilities, the cheaper option should be built, and 
markets should be given the opportunity to make

[[Page 886]]

the choice. Industrial Consumers believes, however, that this will 
require that the markets have access to redispatch costs, congestion 
valuations (from a secondary market for capacity reservations), and 
other data on grid conditions. This is information that is better 
disclosed by a disinterested independent RTO than a self-interested 
transco or generation company.
    Cal DWR questions whether either ISOs or transcos have an incentive 
to use transmission alternatives (such as demand-side management, load 
shedding, distributed generation, or generation) to reduce the overall 
cost of transmission. However, it believes that this problem may be 
more acute for a transco, for which revenues and return are directly 
tied to the use of their transmission assets.
    However, other commenters claim that there is no basis for concerns 
that a transco will favor a transmission solution to 
constraints.498 Entergy contends that, if a generation 
solution is the most efficient way to resolve congestion, a new 
generator will likely realize that and try to locate in the appropriate 
area. Entergy states that an RTO's obligations as an open access 
transmission provider leave it with no choice but to interconnect with 
the new generator. Also, Entergy argues that an RTO will not have the 
unfettered ability to propose and build inefficient transmission 
solutions. It believes that review by state regulators with siting 
authority, and prudence review by the Commission, will make it 
difficult for an RTO to build inefficient and unnecessary transmission 
additions. Enron/APX/Coral Power and JEA believe that a transco may, in 
fact, be well suited for congestion management. Enron/APX/Coral Power 
states that placing responsibility for managing congestion in the RTO's 
hands complements their view that an RTO-Transco must be obligated to 
assume delivery risk (i.e., deliver physically firm power) in exchange 
for being rewarded for cutting costs and increasing system throughput.
---------------------------------------------------------------------------

    \498\ See, e.g., Trans-Elect, FirstEnergy, Entergy.
---------------------------------------------------------------------------

    The Need for Flexibility in the Design of Market Mechanisms. 
Commenters in general showed considerable support for the NOPR's 
proposal to give RTOs considerable flexibility in experimenting with 
different market approaches to managing congestion.499 Mass 
Companies state that the NOPR's willingness to allow RTOs latitude to 
develop local approaches to congestion management is particularly 
appropriate, given the difference in conditions in different parts of 
the country. CP&L believes that congestion management is an area where 
a one-size-fits-all solution would miss the mark and unnecessarily 
increase the cost of forming and operating an RTO. SRP believes that a 
flexible approach is needed because the use of market mechanisms for 
congestion management is in its infancy, and poorly designed market 
mechanisms can exacerbate problems and adversely impact reliability.
---------------------------------------------------------------------------

    \499\See, e.g., Mass Companies, SRP, CP&L, Southern Comany, PJM/
NEPOOL Customers, United Illuminating, Georgia Commission, JEA, 
Florida Commission, NYPP, Cinergy.
---------------------------------------------------------------------------

    The Florida Commission states that the details of proposals for 
managing congestion using a market mechanism should be determined on a 
regional basis with endorsement by the state regulatory body. The 
Florida Commission recommends that the Commission continue to monitor 
discussions of these issues within NERC and not duplicate or foreclose 
their development and resolution at NERC.
    Montana-Dakota recommends that the Commission not limit the 
experimentation with market mechanisms to the provision of firm 
transmission service. Montana-Dakota believes that there is potential 
to further improve transmission services by allowing RTOs the ability 
to implement congestion management methods for non-firm services rather 
than relying only on the use of TLR to curtail such services.
    Many commenters express support for the proposal to allow RTOs 
flexibility in developing approaches to congestion 
pricing.500 Some, such as Florida Power Corp. and Desert 
STAR, believe that allowing flexibility in pricing may provide 
incentives for transmission owners to join or form an RTO. Florida 
Power Corp. argues that such flexibility allows transmission owners to 
deal with issues such as cost shifting, and believes that providing 
more specific guidance will only limit possible options.
---------------------------------------------------------------------------

    \500\ See, e.g., PJM/NEPOOL Customers, United Illuminating, 
Florida Power Corp., Desert STAR, Oregon Commission, NERC.
---------------------------------------------------------------------------

    However, the FTC cautions that the Commission should not allow its 
policy of flexibility to continue indefinitely. The FTC states that 
although experimentation with transmission congestion pricing 
alternatives to LMP may be appropriate at present, it does not believe 
that great uncertainty about the most effective approach to 
transmission congestion management need exist indefinitely. It suggests 
that the Commission may wish to establish a date in the not-too-distant 
future when it will undertake a comparative analysis of the consumer 
costs and benefits of alternative transmission pricing regimes. The FTC 
states that if one or more approaches provide substantially superior 
results for consumers, the Commission may wish to initiate a rulemaking 
on policies to encourage RTOs to adopt these approaches. The Oregon 
Commission recommends that the Commission evaluate the effectiveness 
and efficiency of various congestion pricing experiments, and based on 
its evaluation, require RTOs to use the better methods. However, the 
Oregon Commission estimates that the process of refining congestion 
pricing methods may take a decade or more.
    NERC states that there are strongly held, differing opinions 
throughout the industry on how congestion prices should be designed. 
NERC states that, while flexibility is one important consideration, the 
various regional solutions must be able to work together. It believes 
that the Commission can provide the leadership needed to bring the 
industry to closure on these issues. NERC notes that this may require 
the Commission to be more proscriptive, and it should not hesitate to 
do so. In this regard, Minnesota Power suggests that the Commission 
encourage neighboring RTOs with constrained interfaces to jointly 
develop constraint relief procedures including common constraint 
pricing where appropriate.
    Timing of Implementation.With regard to the NOPR's proposal to 
allow RTO's up to one year after start-up to implement the congestion 
management function, commenters express a variety of opinions. Some 
indicate that one year is an appropriate additional time 
period.501 Others, however, believe that it is essential 
that the RTO have some form of congestion management system in place 
when it begins operation.502 SMUD and CMUA state that a 
significant deterrent to participating in the Cal ISO has been the fact 
that, in California, Cal ISO transmission is strictly a short-term 
transaction given that Cal ISO has not yet fully implemented FTRs. SMUD 
emphasizes that, without the hedge provided by FTRs, it cannot 
guarantee its customer-owners low cost or reliable transmission 
service. TANC believes that allowing an RTO to begin operations without 
a congestion management procedure in place greatly increases the 
opportunity for market power abuses as well as market inefficiency.
---------------------------------------------------------------------------

    \501\ See, e.g., Industrial Consumers, Allegheny, PGE, Entergy.
    \502\ See, e.g., SMUD, Tri-State, CMUA, TANC, Desert STAR, 
Cinergy.

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

[[Page 887]]

    Duke states that, ideally, the permanent congestion management 
function should be in place on the first day of RTO operation. Then, 
Duke notes, it would not be necessary to incur the cost of 
implementing, and developing strategies and behavior appropriate to an 
initial system, only to have to incur additional costs and changes in 
behavior to adapt to a permanent system. However, Duke states that 
congestion management issues are complex and substantial information 
management systems must be put in place. Consequently, Duke believes 
one year from the time the RTO becomes operational may not be a 
sufficient length of time to implement the congestion management 
function.
    Desert STAR states that the new approaches to congestion management 
called for by newly competitive markets will take additional time to 
work out and, therefore, the Commission should be willing to consider 
additional time on a case-by-case basis. However, in order to ensure 
reliable operation, Desert STAR believes some congestion management 
system must be in place when the RTO begins operation.
    Some commenters believe that more than one year of additional time 
may be needed for the RTO to implement the congestion management 
function. NSP states that if the RTO has a state-estimator model with 
the necessary properties, it is possible that a congestion management 
system, of the type preferred by NSP, could be implemented within about 
18 months from the time of project initiation. However, for regions 
without the necessary models, NSP expects the time-line would likely be 
three years from time of project initiation.
    Montana Power believes that there will be many ``growing pains'' 
associated with implementation of RTOs that will take time to work out, 
especially in areas like the Pacific Northwest, which have no history 
of tight pool operation. Montana Power believes that allowing one-year 
for implementing a market mechanism for congestion management is a very 
aggressive schedule. Montana Power thus encourages the Commission to 
allow up to three years. Similarly, Avista states that, with the IndeGo 
experience in mind, it encourages the Commission to allow two to three 
years for implementation of this function, especially where it is 
demonstrated that the RTO will comply immediately with other 
characteristics and functions identified in the Commission's Final 
Rule.
    The Florida Commission believes that the Commission should not 
impose any arbitrary time period for implementation of congestion 
management. It states that NERC is working with the regions on this 
issue and FERC should monitor those activities before setting any 
deadlines, if at all. Also, JEA believes that requiring the congestion 
management function to be in place within one year from the start-up of 
RTO operation may be feasible only for those RTOs structured as 
transcos from the beginning.
    Commission Conclusion. As we proposed in the NOPR, we conclude that 
an RTO must ensure the development and operation of market mechanisms 
to manage congestion. Furthermore, as we proposed, we will require that 
responsibility for operating these market mechanisms reside either with 
the RTO itself or with an another entity that is not affiliated with 
any market participant.
    We agree with the large number of commenters that believe that the 
use of market mechanisms to manage congestion is superior to the use of 
administrative curtailment procedures or other approaches that do not 
take into account the relative value of transactions that are curtailed 
and those that are allowed to go forward. In addition, we conclude that 
the RTO or an independent entity must assume an active role in 
developing and implementing any congestion market mechanisms, because 
the use of such mechanisms must necessarily be closely coordinated with 
the operational activities that the RTO performs on a day-to-day and, 
in many cases, moment-to-moment basis.
    Some commenters argue that an RTO should not be allowed to operate 
a centralized market for congestion management. The commenters contend 
that, if such a market is operated by an RTO or other entity that is 
independent of the market, a robust market in forward contracts for 
energy will not develop. As a result, these commenters claim, society 
will never obtain the efficiency benefits that would otherwise flow 
from a marketplace in which buyers and sellers are able to trade 
actively among themselves. These commenters also argue that the price 
certainty provided by forward markets will be replaced with the 
uncertainty of prices that are determined after the fact.
    We disagree with these commenters and see no reason why the RTO's 
operation of a market for congestion management should inhibit the 
ability of others to offer forward contracts for energy, or other 
market instruments that provide price certainty. We recognize that some 
of the market redispatch programs undertaken to date are experimenting 
with various ways to manage congestion efficiently-including relying 
upon decentralized markets to effect the necessary 
redispatch.503 It is too early to tell if these 
decentralized markets will work efficiently. But given the short time 
frame in which system operators often must react to congestion 
situations, experience may ultimately show that markets for congestion 
management can achieve more efficient and effective results if they are 
centrally operated. Therefore, we will not deny here the RTO, or other 
independent entity, the opportunity to operate a market--either 
centralized or de-centralized--for congestion management.
---------------------------------------------------------------------------

    \503\ See, e.g., the market redispatch experiment of NERC 
(Docket No. ER99-2012-000).
---------------------------------------------------------------------------

    As we proposed in the NOPR, we will require the RTO to implement a 
market mechanism that provides all transmission customers with 
efficient price signals regarding the consequences of their 
transmission use decisions. We are convinced that efficient congestion 
management requires that transmission customers be made aware of the 
cost consequences of their actions in an accurate and timely manner, 
and we believe that this is best accomplished through such a market 
mechanism. Also, as we proposed in the NOPR, we believe that congestion 
pricing proposals should seek to ensure that (1) the generators that 
are 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. Although we agree with some commenters that price signals can 
also assist in determining the efficient size and location of new 
generation and grid expansions, we share the view of LIPA and others 
that price signals alone cannot be relied upon to identify all needed 
enhancements.
    While we will not prescribe a specific congestion pricing 
mechanism, we note that some approaches appear to offer more promise 
than others. As we stated in our order approving the PJM ISO and 
reiterated in the NOPR, markets that are based on locational marginal 
pricing and financial rights for firm transmission service appear to 
provide a sound framework for efficient congestion 
management.504 A number of commenters express strong support 
for the LMP approach. As PJM notes in its comments, LMP assesses 
congestion charges directly to transmission customers in a manner 
consistent with

[[Page 888]]

each customer's actual use of the system and the actual dispatch that 
its transactions cause. In addition, LMP facilitates the creation of 
financial transmission rights, which enable customers to pay known 
transmission rates and to hedge against congestion charges. We further 
note that, where financial rights holders are entitled to receive a 
share of congestion revenues, the availability of such rights helps to 
address the concerns of commenters who fear that congestion pricing can 
lead to the over-recovery of transmission costs. The Commission 
recognizes, however, that LMP can be costly and difficult to implement, 
particularly by entities that have not previously operated as tight 
power pools.
---------------------------------------------------------------------------

    \504\ See PJM, 81 FERC at 62,252-53.
---------------------------------------------------------------------------

    The principal alternative to LMP advocated by commenters is an 
approach that manages congestion by means of physical transmission 
rights that are tradable in a secondary market. Under this approach, 
the RTO may be required to issue the transmission rights initially 
through an auction or allocation process. Market participants would 
then generally have to demonstrate ownership of sufficient rights in a 
constrained interface before they would be allowed to schedule firm 
service over the interface. Such an approach greatly reduces the role 
of the RTO in congestion management. While the approach of trading 
physical transmission rights in a secondary market may prove to be 
workable in regions where congestion is minor or infrequent, in other 
regions where congestion is more of a chronic problem, it may not be 
workable. Also, commenters such as NERA and Professor Hogan claim that 
the network interactions on complex electricity grids make it difficult 
to define physical transmission rights that will use the system fully 
and yet can be traded in decentralized markets. We expect RTOs and any 
affected stakeholders to consider carefully such issues as they 
formulate specific pricing proposals.
    While our experience has shown that, in specific situations, some 
approaches to congestion pricing appear to have advantages over others, 
we have not yet identified one approach as being clearly superior to 
all others. Furthermore, the Commission recognizes that an RTO's choice 
of a congestion pricing method will depend on a variety of factors, 
many of which may be unique to that RTO. Therefore, we will allow RTOs 
considerable flexibility to propose a congestion pricing method that is 
best suited to each RTO's individual circumstances.
    Some commenters appear to confuse the need to redispatch generators 
to maintain reliability with the need to take specific actions to 
relieve congestion. Commenters generally agree that the RTO should have 
clear authority to order redispatch for reliability purposes. However, 
for congestion management, we conclude here that the RTO should attempt 
to rely on market mechanisms to the maximum extent practicable. We 
recognize, of course, that there may be times when even well-
functioning markets will fail to provide the RTO with the options it 
needs to alleviate a specific instance of congestion. In those cases, 
the RTO must have the authority to curtail one or more transmission 
service transactions that are contributing to the congestion. Although 
the act of curtailing a transaction may sometimes require the 
redispatch of generation, we clarify that we are not requiring the RTO 
to redispatch any generators exclusively for the purpose of managing 
congestion.
    In the NOPR, we stated that a workable market approach to 
congestion management should establish clear and tradeable rights for 
transmission usage, promote efficient regional dispatch, support the 
emergence of secondary markets for transmission rights, and provide 
market participants with the opportunity to hedge locational 
differences in energy prices. Most commenters agree that these are 
reasonable features of any congestion management proposal. However, 
Enron/APX/Coral Power believes that the RTO should not be allowed to 
provide a hedging instrument. It contends that the ``monopoly wires 
business'' should not be allowed to encroach on what it views as the 
highly competitive and innovative business of providing hedges against 
locational price differences of energy or capacity, or against price 
volatility of these or any other competitive products. In response, we 
note that, while decentralized markets may ultimately prove to be 
capable of providing such products, as these commenters claim, we do 
not yet have evidence to that effect. Therefore, in the interest of 
allowing RTOs flexibility to experiment with different market 
approaches, we will not prohibit the RTO from offering such products 
through markets that it may operate.
    Finally, with regard to the timing of implementation of the 
congestion management function, we will adopt our proposal to allow the 
RTO to take up to one year after start-up to implement market 
mechanisms for managing congestion. Most commenters agree that some 
period of time is needed for implementation. However, a number of them 
indicate that the RTO must have some form of congestion management 
system in place when it begins operation. We agree, and clarify that, 
upon start-up, the RTO must have in place effective protocols for 
managing congestion while preserving reliability. Because the NOPR did 
not make this point explicitly, we do so here.
3. Parallel Path Flow (Function 3)
    In the NOPR, the Commission proposed to require that an RTO develop 
and implement procedures to address parallel path flow issues within 
its region and with other regions.\505\ The Commission noted that 
measures to address parallel path flow between regions may not 
necessarily be in place on the first day of RTO operation, and proposed 
to allow up to three years after start-up for this function to be 
implemented.\506\ The Commission sought comments on whether such an 
additional implementation time period is warranted, and whether three 
years is an appropriate additional time period.
---------------------------------------------------------------------------

    \505\ The terms ``parallel path flow'' and ``loop flow'' are 
sometimes used interchangeably to refer to the unscheduled 
transmission flows that occur on adjoining transmission systems when 
power is transferred in an interconnected electrical system.
    \506\ FERC Stats. and Regs. para. 32,541 at 33,743-44.
---------------------------------------------------------------------------

    Comments. Virtually all commenters support the NOPR's proposal to 
require that an RTO develop and implement procedures to address 
parallel path flow issues as a separate function.\507\ Industrial 
Consumers states that parallel path flow-related disputes will diminish 
as a result of RTOs addressing this issue.\508\ But PGE notes that 
grandfathering existing transmission contracts may impede the RTO's 
ability to address loop flow.
---------------------------------------------------------------------------

    \507\ See, e.g., ComEd, East Texas Cooperatives, EPSA, 
Industrial Consumers, LG&E, NASUCA, NSP, PJM, Southern Company and 
Williams. However, Cinergy argues that parallel path flows should 
not be considered as a separate function but should be considered as 
a characteristic under the scope and regional configuration because 
that will allow an RTO to address congestion management issues along 
with parallel path issues.
    \508\ Industrial Consumers also notes that the first sentence in 
the proposed regulation should be modified to read as ``RTO must 
develop and implement procedures to address parallel path flow 
issues within its region and with other regions in the 
interconnection within which it resides.'' (Suggested change 
underlined)
---------------------------------------------------------------------------

    Many commenters assert that parallel path flow and congestion 
management issues are closely related to one another since both the 
issues involve identification of power flows resulting from a specific 
transaction.\509\ Therefore, they argue that any solution to parallel 
path flow should recognize

[[Page 889]]

this close relationship. For example, Industrial Consumers believes 
that an RTO can take preemptive actions against potential curtailment 
situations to manage congestion resulting from loading of chronically 
constrained transmission interfaces due to loop flow. PJM suggests that 
the use of redispatch solutions like LMP not only is more efficient and 
beneficial to a competitive market, but is preferable to curtailing 
transactions under TLR to address congestion due to loop flow. South 
Carolina Authority is convinced that over the long run the problem of 
parallel path flow needs to be addressed as a planning issue, focusing 
on appropriate reinforcements to constrained transmission lines.
---------------------------------------------------------------------------

    \509\ See, e.g., EPSA, Florida Power Corp., FTC, Georgia 
Transmission, LG&E, Mass Companies, NSP and PJM.
---------------------------------------------------------------------------

    Many commenters recommend that an RTO should encompass as large a 
region as possible so that it can ``internalize'' most of the loop flow 
within its region.\510\ However, others argue that the loop flow issue 
can be solved satisfactorily only if it is addressed at the 
interconnection level.\511\ They believe that while a large RTO will 
``internalize'' most of the parallel path flows within its region, 
parallel path flows between RTOs will remain. Some other commenters are 
convinced that cooperative efforts among regional entities works best 
when it comes to resolving issues such as parallel path flow 
issue.\512\ NERC notes that it is in the process of developing the 
needed information system to address the parallel path flow issue on an 
interconnection basis and urges the Commission to direct the RTOs to 
work closely with it to coordinate efforts to resolve this issue. 
Southern Company and Industrial Consumers support NERC's initiative in 
solving the loop flow issue. Cleveland states that the national grid 
should be viewed as a single electrical system which calls for a 
universal approach rather than a regional approach to resolve the loop 
flow issue. The universal approach, Cleveland argues, will not only 
improve the integrity and reliability of the national grid but also 
eliminate the need for any policy shift in the future.
---------------------------------------------------------------------------

    \510\ See, e.g., LG&E, Michigan Commission, NASUCA, New Smyrna 
Beach, NSP, PJM and South Carolina Authority.
    \511\ See, e.g., Cleveland, East Texas Cooperatives, Georgia 
Transmission, Industrial Consumers, NY ISO, Southern Company, TEP. 
Industrial Consumers note that several other issues need to be 
addressed at the interconnection level and not at the regional 
level. They are ATC calculation, inadvertent flows and congestion 
management.
    \512\ Central Maine Reply at 9; NYPP Reply at 10.
---------------------------------------------------------------------------

    Commenters from Western System Coordinating Council (WSCC) assert 
that the loop flow issue in their region was solved by the adoption of 
WSCC Flow Mitigation Plan (Plan) that provides for controlling 
unscheduled flows through the use of phase shifting transformers.\513\ 
SRP suggests loop flow in WSCC should continue to be addressed at the 
WSCC level and not at the RTO level because WSCC may end up with four 
or more RTOs. PG&E recommends that the establishment of property rights 
such as FTRs be explored as a means to solve loop flow issues, on the 
basis that developing property rights will ensure the most efficient 
use of the transmission lines. Enron/APX/Coral Power urges RTOs in the 
Eastern Interconnection to move toward the Western model. NASUCA 
believes that RTOs should perform a cost-benefit analysis of 
controlling loop flows with phase shifting transformers.
---------------------------------------------------------------------------

    \513\ See, e.g., PG&E, Seattle, SRP and TEP.
---------------------------------------------------------------------------

    Most commenters support the NOPR's proposal for an additional 
implementation time period of three years for coordination among 
RTOs.\514\ They argue that the proper resolution of loop flow presents 
a number of complex issues that may require negotiations and agreements 
among neighboring RTOs and that the additional time period will give 
them an opportunity to coordinate their efforts. Allegheny supports an 
additional time period for implementation of this function but urges 
the contract path methodology be replaced at a faster pace than three 
years. Industrial Consumers notes that an additional time period of 
three years is necessary for NERC to solve the loop flow issue at the 
interconnection level. However, Florida Power Corp. and Florida 
Commission observe that the severity of parallel path flow varies from 
region to region and therefore opposes setting an arbitrary time limit 
for the implementation of this function. Duke likewise believes that 
the deadline for the implementation of this function should be 
determined by the Commission on a case-by-case basis.
---------------------------------------------------------------------------

    \514\ See, e.g., Cal ISO, Desert STAR, Entergy, Industrial 
Consumers, NECPUC, NERC, NY ISO, PGE, SRP, Tri-State, TVA, UtiliCorp 
and WPSC. Cleveland also argues that a similar grace period should 
be given for the implementation of function # 5. (TTC and ATC 
Calculation). Cleveland at 14.
---------------------------------------------------------------------------

    Commission Conclusion. We reaffirm our preliminary determination 
that an RTO should develop and implement procedures to address parallel 
path flow issues within its region and with other regions. Most 
commenters agree that the formation of RTOs, with their widened 
geographic scope of transmission scheduling and expanded coverage of 
uniform transmission pricing structures, provide an opportunity to 
``internalize'' most, if not all, of the effect of parallel path flow 
in their scheduling and pricing process within a region. NERC notes 
that it is in the process of developing the needed information system 
to address parallel path issues on an interconnection basis, and we 
will direct RTOs to work closely with NERC, or its successor 
organization, to resolve this issue. As noted by Industrial Consumers, 
parallel path flow-related disputes will diminish as a result of RTOs 
addressing this issue.
    Commenters from Western System Coordinating Council (WSCC) state 
that they adopted the WSCC Flow Mitigation Plan (Plan) to address 
parallel path flow issue in their region. SRP suggests that parallel 
path flow in WSCC continue to be addressed at the WSCC level and not at 
the RTO level because WSCC may end up with more than one RTO. We will 
not here make any judgments on the merits of WSCC's Plan as a solution 
for parallel path flow issues. However, we clarify that this rule does 
not prevent addressing parallel path flow issues on a larger-than-
single-RTO basis. In fact, we require RTOs to develop and implement 
procedures for addressing parallel flow issues with other regions.
    In the NOPR we proposed that the RTO have measures in place on the 
date of initial operation to address parallel path flow issues within 
its own region. We also noted that measures to address parallel path 
flow issues between RTO regions may not necessarily be in place on the 
first day of RTO operation. We proposed to allow up to three years 
after start-up for this function to be implemented. Most commenters 
support the NOPR's proposal for an additional time period of three 
years. A few commenters \515\ prefer a case-by-case approach. Since 
severity of the parallel path flow varies from region to region, some 
parts of the Nation may choose to resolve inter-regional parallel path 
flow issues sooner than the required three years. Consequently, we will 
adopt our proposal in the NOPR that the RTO have measures in place to 
address parallel path flow issues in its region on the date of initial 
operation. We also adopt three years as an adequate time period for 
implementation of measures to address parallel path flow issues between 
regions.
---------------------------------------------------------------------------

    \515\ Florida Power Corp., Florida Commission and Duke.
---------------------------------------------------------------------------

    We recognize that these measures to address parallel path flows 
combined with the requirement that the RTO be the sole provider of 
transmission services over facilities that it owns or controls will 
eliminate or diminish the ability of transmission users to choose among 
different contract paths owned by different service providers within 
the

[[Page 890]]

RTO region. However, these users will have the ability to move power 
anywhere within the RTO at a single rate and under a single set of 
terms and conditions. We believe this is pro-competitive and represents 
one of the fundamental benefits that is envisioned by the Rule. As we 
noted in the NOPR, the creation of large RTOs that can internalize 
most, if not all, of the effect of parallel path problems through their 
scheduling and pricing actions provides a unique opportunity to resolve 
a major operating concern that has caused problems on both the Eastern 
and Western Interconnections and which is a significant impediment to 
promoting efficient competition in generation markets.\516\ Therefore, 
in reviewing the competitive implications of a proposed RTO application 
under section 203, we believe that any inability of transmission 
customers to choose among different contract path suppliers within an 
RTO will be outweighed by their enhanced ability to reach numerous 
buyers and sellers of electricity throughout the region.
---------------------------------------------------------------------------

    \516\ See FERC Stats. and Regs. para. 32,541 at 33,744.
---------------------------------------------------------------------------

4. Ancillary Services (Function 4)
    The fourth proposed minimum function is that the RTO must serve as 
the supplier of last resort for all ancillary services required by 
Order No. 888.\517\ This supply obligation for the RTO is necessary 
because only the single grid operator will be able to provide certain 
ancillary services, not all transmission customers may be able to self-
supply (some own generation, others do not), and because it typically 
is more efficient for the RTO to provide some ancillary services for 
all transmission users on an aggregated basis.
---------------------------------------------------------------------------

    \517\ FERC Stats. and Regs. para. 32,541 at 33,744.
---------------------------------------------------------------------------

    In carrying out this function, the Commission proposed that all 
market participants would have the option of self-supplying or 
acquiring ancillary services from third parties. In addition, the RTO 
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; must be able to exercise direct or indirect 
operational control over all ancillary service providers; must promote 
the development of competitive markets for ancillary services whenever 
feasible; and must ensure that its transmission customers have access 
to a real-time balancing market.
    Comments. Supplier of Last Resort. Comments on whether an RTO 
should serve as a supplier of last resort are mixed. A large number of 
commenters support the Commission's proposal, as written.\518\ Detroit 
Edison believes that the RTO should serve as the sole supplier of 
ancillary services to transmission customers and that the RTO should be 
permitted either to purchase services directly from generation 
suppliers or to purchase generation resources for this purpose. First 
Energy believes that the RTO's obligation as the supplier of last 
resort for ancillary services cannot be eliminated, since it is the 
basis of reliability.\519\
---------------------------------------------------------------------------

    \518\ See, e.g., Entergy, Industrial Consumers, NECPUC, Cal ISO, 
EPSA, FirstEnergy, LG&E, PacifiCorp, Empire District, EME, Southern 
Company, UtiliCorp, PGE, PNGC, PSNM, TDU Systems, Nevada Commission.
    \519\ See also Florida Power Corp.
---------------------------------------------------------------------------

    On the other hand, a few commenters suggest that the Commission 
allow flexibility. Duke believes that an RTO should always have the 
responsibility for ensuring that transmission customers have arranged 
adequate ancillary service and that those services are delivered. They 
suggest that where a competitive market for ancillary services exists, 
the RTO should not be required to provide such ancillary services as a 
supplier of last resort.\520\ And a number of commenters take issue 
with one or more aspects of the proposed requirements, although many of 
these commenters generally support the proposal.
---------------------------------------------------------------------------

    \520\ See, e.g., NASUCA, Seattle, CalPX, Mass Companies.
---------------------------------------------------------------------------

    For example, some commenters suggest that more information is 
needed. Southern Company suggests that the Commission allow NERC to 
finalize an ancillary services policy before mandating changes to 
ancillary service requirements.\521\ Professor Hogan suggests further 
investigation into developments in ancillary services.\522\
---------------------------------------------------------------------------

    \521\ Southern Company notes that NERC's Interconnected 
Operations Services Working Group is currently addressing the 
ancillary services that should be required in a competitive 
environment and has issued a proposed policy for public comment and 
review.
    \522\ NWCC recommends that additional research regarding the 
application of ancillary services to wind and other intermittent 
generation technologies be conducted.
---------------------------------------------------------------------------

    Other commenters believe that the focus of the proposal should be 
narrowed. Los Angeles suggests that an RTO should be the ``safety net'' 
of last resort for providing generation-based ancillary services. As 
such, the RTO would not play a significant role in the energy market 
and can remain essentially indifferent to energy market issues. PG&E 
believes that an RTO could set appropriate rules for ancillary services 
but would not itself procure such services from the marketplace absent 
clearly defined emergency situations or in its role as provider of last 
resort. Avista states that while a transitional ``supplier of last 
resort'' role may be appropriate, an RTO should generally not become 
deeply involved in any of the markets for generation services.
    A number of commenters suggest that the obligation to provide 
ancillary services should be expanded to include more or different 
sellers. MidAmerican believes that each control area should retain 
responsibility for the provision of ancillary services and should be 
allowed to self-provide or acquire necessary ancillary services in the 
most economical means it sees fit to meet performance compliance 
standards. East Texas Cooperatives suggests that the Commission require 
both transmission owners and the RTO to offer ancillary services at 
cost-based rates unless a seller can demonstrate a competitive market 
in a particular ancillary service. PPC and Desert STAR also believe 
that the role of provider of last resort of ancillary services would 
better rest with local control areas or independent generators that can 
supply ancillary services. Steel Dynamics requests that the final rule 
require generation-owning members of RTOs to maintain Commission 
approved cost-based tariff schedules for ancillary services. Georgia 
Transmission believes that any RTO members that are capable of 
providing ancillary services should be the providers of ``first 
resort,'' and the ability to acquire such services from different 
providers would enhance competition in these markets.
    While not specifically objecting to the RTO being the supplier of 
last resort for ancillary services, some parties suggest that the 
Commission should allow other mechanisms to work.\523\ California Board 
urges the Commission to allow consideration of other means for ensuring 
that the need for ancillary services is addressed. It recommends that 
the final rule reflect a requirement that the RTO filings must indicate 
how default provision of ancillary services will be accomplished 
without necessarily requiring the RTO to be the provider of last 
resort. Enron/APX/Coral Power advocates a form of performance-based 
ratemaking in which the RTO would have an incentive to perform its 
ancillary service function as efficiently and economically as possible. 
Florida Commission recommends that an RTO only be responsible for 
providing non-competitive ancillary services and

[[Page 891]]

should require users to purchase or self-provide the other competitive 
services.
---------------------------------------------------------------------------

    \523\ See, e.g., CMUA, LPPC, California Board, San Francisco, 
Oneok, SMUD, Avista, Sithe, Seattle.
---------------------------------------------------------------------------

    Similarly, FTC suggests that the Commission consider arrangements 
in which the RTO's primary role is to provide a market mechanism for 
transmission customers to acquire ancillary services for themselves. It 
argues that this method may reduce costs by allowing customers to 
customize their purchases of ancillary services to better fit their 
specific needs.\524\ Some commenters suggest that final RTO regulations 
expressly recognize the administration of an ancillary service exchange 
as an alternative to the provider-of-last-resort obligation that is 
imposed on a RTO under the proposed regulations.\525\ For example, ISO-
NE believes that a competitive market for ancillary services is a 
superior supply mechanism, and ISO-NE suggests that the text of 
proposed Sec. 35.34(j)(4) be amended to read:

    \524\ See also Empire District.
    \525\ See, e.g., Cinergy, APX, EAL, NY ISO, JEA.
---------------------------------------------------------------------------

    An RTO must develop and maintain a market or other contractual 
arrangements for the supply of all ancillary services required by 
Order No. 888, FERC Stats. & Regs. para. 31,036 (Final Rule on Open 
Access and Stranded Costs), and subsequent orders.

    Comments were also sought on the circumstances under which an RTO's 
obligation as supplier of last resort could be eliminated.\526\ Several 
commenters believe that the supplier of last resort obligation can be 
eliminated once a viable competitive market develops within the RTO 
region.\527\ For example, WPSC suggests that an RTO must continue to 
fulfill the role of supplier of last resort for these services or a 
power exchange must be available to supply these services. WPSC 
believes that it would be difficult to predict the circumstances under 
which the market for ancillary services is sufficiently robust that the 
RTO's role as supplier of last resort may be eliminated. WPSC believes 
that it would be a mistake to eliminate that role in any market where 
the generation market concentration levels as measured by the 
Herfindahl-Hirschman Index exceed 1,800. TDU Systems states that it is 
not aware of a market in any of the ancillary services that is now 
sufficiently competitive to warrant elimination of an ancillary service 
from this obligation. However, TDU Systems acknowledges that there may 
never be a competitive market for certain ancillary services and that 
an alternative mechanism must be created.
---------------------------------------------------------------------------

    \526\ FERC Stats. and Regs. para. 32,541 at 33,745.
    \527\ See, e.g., WPSC, APS, Florida Commission, Duke.
---------------------------------------------------------------------------

    The NOPR also asked for comments on whether a different set of 
ancillary services requirement for RTOs is needed because RTOs will not 
own generating resources. Comments on this issue were mixed.
    Sithe and several other commenters 528 generally believe 
the Commission's initial set of guidelines on ancillary services is 
reasonable, and that a new set of ancillary services requirements for 
RTOs is unnecessary. LG&E adds that, as already is the case under the 
open access tariff, an RTO should be allowed to choose to add to the 
list of ancillary services in recognition of local or regional 
conditions. MidAmerican believes that while no additional or revised 
ancillary services are required, an RTO must ensure that sufficient 
transmission capacity is available to allow delivery of backup supply, 
planning reserves and the existing six ancillary services.
---------------------------------------------------------------------------

    \52\ See, e.g., PGE, TDU Systems, Cal ISO, Duke, Tri-State.
---------------------------------------------------------------------------

    On the other hand, Los Angeles believes that a different set of 
ancillary services requirements than those required currently from a 
vertically integrated utility should apply to an RTO which does not own 
generation resources. They envision an ultimate industry structure of 
complete desegregation of generation and transmission assets so that 
any incentive (either real or perceived) for the transmission provider 
to act in a discriminatory manner is eliminated.
    NSP requests that the Commission refer to the draft NERC policy 
that discusses the role of an operating authority as an unbundled 
procurement agent for community ancillary services. They describe this 
document as a good ``guidepost'' for the Commission to follow in the 
RTO NOPR, and for the establishment of additional ancillary services 
such as system blackstart and frequency responsive reserve.\529\ Desert 
STAR and Cal ISO agree that additional blackstart ancillary service may 
be required. TDU Systems believes that RTOs should be required to offer 
backup service and an additional load following service. It describes 
backup service as required to meet contingencies during periods 
following those covered by the OATT's reserve services, and load 
following service as required to complement the OATT's minute-to-minute 
regulation service with a service matching hour-to-hour variations in 
load. Industrial Consumers recommends that the Commission remove 
Schedule 4 (energy imbalance service) from any tariff administered by 
an RTO. They suggest that this service be provided by the real-time 
balancing market as proposed in the NOPR.
---------------------------------------------------------------------------

    \529\ See also Eric Hirst.
---------------------------------------------------------------------------

    Self-Supply Option. Nearly all who commented on the self supply 
option generally agree that, where feasible, all market participants 
should have the option of self-supplying or acquiring ancillary 
services from third parties. \530\ Some commenters strongly endorse the 
self-supply model. For example, APS believes that it should be the aim 
of the RTO to have each transmission customer self-supply its 
generation-related ancillary service requirements to the fullest extend 
practical. Los Angeles suggests that the role of the RTO should be 
limited to ensuring that the transmission customer has adequately 
provided for the necessary ancillary services for each transaction, and 
the RTO provide such services only in the event of non-compliance. It 
believes that the RTO should develop specific rules and protocols that 
would support the self-provision of ancillary services. Some 
commenters, including PJM/NEPOOL Customers and LG&E, suggest that it is 
important for the development of a competitive market in ancillary 
services that RTO customers not be required to purchase them from the 
RTO, and that an RTO must not prohibit or interfere with the ability of 
all market participants to have the option of acquiring competitive 
ancillary services or providing such services through buy/sell 
transactions from customer-owned generation.
---------------------------------------------------------------------------

    \530\ See, e.g., CMUA, Cal ISO, LG&E, PG&E, PJM/NEPOOL 
Customers, PPC, APX, Metropolitan, MidAmerican, NSP, Seattle, SMUD, 
Desert STAR, TDU Systems, Tri-State.
---------------------------------------------------------------------------

    On the other hand, FirstEnergy states that the Commission should be 
very cautious that policies that encourage self-supply of ancillary 
services do not compromise the very ability of the RTO to ensure 
reliable and secure network operation. It maintains that the provision 
of ``self-supplying'' ancillary services is untested, the 
infrastructure needed is as yet undeveloped, and the process of 
providing them could potentially lead to abuses. FirstEnergy identifies 
this issue as one of the reasons that NERC is pushing for mandatory 
compliance requirements.\531\ It believes that an RTO must have the 
ability to evaluate and accept/approve those NERC-certified sources 
that reliably contribute to support the grid.
---------------------------------------------------------------------------

    \531\ FirstEnergy notes that NERC is developing certification 
and verification criteria for ancillary service providers.
---------------------------------------------------------------------------

    Authority to Determine Amounts and Location of Ancillary Services. 
Most commenters generally support the proposal that the RTO have the

[[Page 892]]

authority to determine the quantities and, where appropriate, the 
location at which ancillary services must be provided.\532\ In 
addition, CMUA suggests that the RTO be responsible for enforcing 
compliance with established standards.
---------------------------------------------------------------------------

    \532\ See, e.g., Industrial Consumers, PJM, Turlock, Cal ISO, 
Florida Power Corp., PJM/NEPOOL Customers, LPPC, PGE, SMUD, TDU 
Systems, NYPP, Tri-State, Nevada Commission.
---------------------------------------------------------------------------

    PJM/NEPOOL Customers requests that RTO decisions regarding the 
amounts and locations of ancillary services consider both stakeholder 
input and NERC standards. It believes that this requirement would 
ensure that the RTO does not impose unnecessarily high ancillary 
service obligations that will inhibit the operation of the competitive 
market. In addition, PJM/NEPOOL Customers asks that the Commission 
ensure that the RTO exercises this authority only to the extent 
necessary for reliability purposes, since decisions regarding ancillary 
services could impact the competitive electricity supply market.
    NYPP requests that the RTO's authority not be exclusive. It 
suggests that properly constituted local and regional reliability 
councils authorized by FERC should have the authority to establish 
criteria necessary to maintain the reliability of the transmission 
system including the reliability of discrete locations.
    Duke notes that the Commission has previously recognized NERC's 
leadership role in developing concepts in the area of ancillary 
services.\533\ It encourages the Commission to recognize and adopt 
NERC's development of ancillary service definitions and reliability 
standards.\534\
---------------------------------------------------------------------------

    \533\ Citing FERC Stats. & Regs. para. 31,036 at 31,705 (1996).
    \534\ See also Eric Hirst.
---------------------------------------------------------------------------

    Industrial Consumers and Steel Dynamics request that the Commission 
first approve the standards by which the RTO determines the 
requirements. They requests that these standards include the 
development of ``metrics,'' i.e., standardized units of measurement 
such that the performance of each service can be verified. In addition, 
Industrial Consumers recommends modifying the requirement to ensure 
seamless application between multiple RTOs and for transactions that 
only go through an RTO. It suggests adding an additional requirement to 
Sec. 35.34(j)(4)(ii):

    The Regional Transmission Organization must support the minimum 
required amounts of each ancillary service for transactions between 
itself and other Regional Transmission Organizations in the 
interconnection and through itself.

    Control Over Ancillary Services Providers. All commenters that 
commented on this subject believe that the RTO should be able to 
exercise some operational control, either directly or indirectly, over 
any supplier of ancillary services.535 SMUD supports the RTO 
establishing well documented and specific operating criteria and the 
ability to require compliance with such operating criteria, including 
monetary penalties and commission-approved sanctions. JEA believes that 
this control should be exerted only where pre-existing contractual 
rights are established.536
---------------------------------------------------------------------------

    \535\ See, e.g., PJM, Cal ISO, Florida Power Corp., Cinergy, Los 
Angeles, PSNM, SMUD, Duke.
    \536\ See also Cinergy.
---------------------------------------------------------------------------

    Some commenters would broaden the requirement. For example, 
FirstEnergy is concerned that limiting the RTO's control to ancillary 
services providers rather than all generation located within the RTO 
may compromise the RTO's ability to operate the transmission system 
reliably. It suggests that the Commission allow a greater flexibility 
for the RTO and all generation owners located within the RTO to develop 
an agreement for provision of ancillary services through the RTO that 
provides for the necessary requirements for voluntary generation 
participation in the ancillary services market including operational 
control if appropriate, and the necessary requirements for calling on 
ancillary services from connected generation necessary for the reliable 
operation of the transmission system.
    On the other hand, PJM/NEPOOL Customers suggest that the RTO 
control be limited to those providers that the RTO will rely on to 
fulfill its obligation as supplier of last resort for ancillary 
services. It claims that control over additional generators is 
unnecessary and may affect the operation of the competitive market.
    Metropolitan recommends that the Commission allow RTO indirect 
control of existing large hydroelectric plants to protect and 
facilitate use of existing systems that have been operational for a 
substantial period of time and to preserve the integrity of the FERC 
hydro license. It states that allowing indirect control would eliminate 
the need for costly installation of software and 
infrastructure.537
---------------------------------------------------------------------------

    \537\ See also NYPP, PSNM.
---------------------------------------------------------------------------

    Promote Competitive Markets for Ancillary Services.Most commenters 
support the proposal in the NOPR that RTOs promote competitive markets 
for ancillary services.538 Seattle suggests that the RTO 
provide incentives to ensure a robust, transparent market with many 
buyers and sellers of ancillary services. PJM/NEPOOL Customers states 
that it is important that the RTO not impede the development of 
competitive markets for ancillary services and that the RTO actually 
facilitate the development of these markets. However, it stresses that 
the RTO and incumbent transmission owners should not be permitted to 
have market-based rates for ancillary services until a viable 
competitive market for such services develops.539
---------------------------------------------------------------------------

    \538\ See, e.g., FTC, LPPC, Avista, APX, PJM/NEPOOL Customers, 
Seattle.
    \539\ See also TDU Systems.
---------------------------------------------------------------------------

    Sithe advocates that the final rule grant RTOs the authority to 
administer spot markets for ancillary services and establish rules 
obligating all participants to meet uniform requirements. PG&E believes 
that the RTO should not be the sole purchaser of ancillary services. 
Instead, it should facilitate the development of bilateral markets for 
as many of the ancillary services as possible, thereby allowing market 
participants to self-provide those ancillary services.
    Access to Real-Time Balancing Markets. In the NOPR, the Commission 
proposed that an RTO must ensure that its transmission customers have 
access to a real-time balancing market. We proposed that the RTO must 
either develop and operate such markets itself or ensure that this task 
is performed by another entity that is not affiliated with any market 
participant. The Commission noted that although system-wide balancing 
is a critical element of reliable short-term grid operation, this does 
not necessarily require that there be a moment-to-moment balance 
between the individual loads and resources of bilateral traders and 
load-serving entities and the schedules and actual production of 
individual generators. We also noted that unequal access to balancing 
options for individual customers can lead to unequal access in the 
quality of transmission service available to different customers, and 
that this could be a significant problem for RTOs that serve some 
customers who operate control areas and other customers who do not. The 
Commission proposed to give RTOs considerable discretion in how a real-
time balancing market would be operated.
    We invited comments on the use of market mechanisms to support 
overall system balancing and imbalances of individual transmission 
users. In addition, we invited responses to the following questions. Is 
it feasible to rely on markets to support a function that is so time-
sensitive? Can such markets be

[[Page 893]]

made to function efficiently if the RTO is not a control area operator? 
For the imbalances of individual transmission customers, should a 
distinction be made between loads and generators? Should customers have 
the option of paying for all imbalances in such a market or only 
imbalances within a specified band?
    Several commenters hold the view that it is indeed feasible to rely 
on markets to support a balancing function that is time-
sensitive,540 and many agree that access to a real-time 
balancing market would be of considerable benefit to market 
participants.541 NERA claims that technical logic dictates 
that an electricity system have a central process to co-ordinate real-
time physical operations. NERA argues that to the extent that this 
process is not based on markets, it must be based on less efficient 
command-and-control methods. NERA also claims that economic and 
commercial logic requires that a commodity market have short-term 
trading arrangements to bring market positions into agreement with 
physical reality, and argues that to the extent that market trading 
does not reflect physical reality, some non-market process must close 
the gap between the market and reality. NERA asserts that these two 
propositions imply that the best way to maximize the role of the market 
and minimize the role of non-market processes is to base real-time 
physical operations on a spot market and to allow market participants 
to use this market for commercial purposes to the extent they find this 
useful.
---------------------------------------------------------------------------

    \540\ See, e.g., Duke, PJM, Illinois Commission, Cal ISO, NERA.
    \541\ See, e.g., Enron/APX/Coral Power, Eric Hirst, NYPP, 
Powerex, East Texas Cooperatives, Industrial Consumers, Professor 
Hogan.
---------------------------------------------------------------------------

    Enron/APX/Coral Power states that access to a real-time energy 
balancing market is central to assuring comparability in open access, 
and Industrial Consumers believes that this proposal is the beginning 
of a much needed ``paradigm shift'' in the manner in which ancillary 
services are defined and provided in the marketplace. Eric Hirst states 
that implementation of a real-time balancing market would permit FERC 
to eliminate the Order No. 888 requirement that transmission providers 
offer an energy imbalance service to transmission customers. He argues 
that elimination of energy imbalance service, with its awkward and 
arbitrary deadband and penalty payments, would be a pro-competitive 
change. Professor Hogan claims that without an efficient spot market 
and the associated transparent spot prices, it will be much more 
expensive and difficult to arrange balancing and settlement for the 
increasing number of retail access programs in the states. East Texas 
Cooperatives agrees that real-time balancing markets are desirable but 
believe that simply commanding RTOs to promote the development of 
competitive markets for ancillary services provides no incentive for 
the RTO and its members to do so.
    Also, two commenters argue that access to real-time balancing 
markets would eliminate some significant barriers to entry for non-
traditional resources such as renewable and distributed 
energy.542 In particular, EPA notes that providing such 
access would eliminate arbitrary energy imbalance penalties that are a 
major barrier to intermittent resources such as wind and solar energy.
---------------------------------------------------------------------------

    \542\ See EPA and Project Groups.
---------------------------------------------------------------------------

    Some commenters believe that the RTO itself should develop and 
operate a real-time balancing market.543 PJM/NEPOOL 
Customers believe that the development of such a market is an essential 
function of the RTO that will facilitate the further development of 
retail competitive supply markets. PJM states that a real-time 
balancing market can best be provided through a power exchange operated 
by an RTO. Commenters are divided as to whether the development of a 
real-time balancing market requires that the RTO be a control area 
operator. Several believe that such markets are possible whether or not 
the RTO operates a control area.544 Indeed, MidAmerican 
believes that, to function efficiently, these markets normally must 
operate in a region that is larger than a typical control area. 
However, others take an opposite view.545 FirstEnergy, for 
example, argues that the timing, dispatch and telecommunications 
infrastructure needed to operate a real-time balancing market today can 
only be done by a control area operator and then only for a combined 
load within a control area with ample generation resources under 
automatic generation control.
---------------------------------------------------------------------------

    \543\ See, e.g., PJM, PJM/NEPOOL Customers, Professor Hogan, 
NERA.
    \544\ See, e.g., Tri-State, Illinois Commission, MidAmerican, 
Duke.
    \545\ See, e.g., PJM/NEPOOL Customers, Southern Company, 
FirstEnergy.
---------------------------------------------------------------------------

    Some commenters provide detailed recommendations regarding the 
rules that should govern the RTO's operation of real-time balancing 
markets.546 Professor Hogan notes that the complex network 
interactions in an electric grid require that there be an entity that 
can provide certain critical coordinating services, and that the most 
obvious example of such services is energy balancing. He states that 
the operator should offer an energy balancing redispatch service where 
market participants can make offers to buy and sell energy.
---------------------------------------------------------------------------

    \546\ See, e.g., Professor Hogan, Allegheny.
---------------------------------------------------------------------------

    He believes that the best approach would be to run the balancing 
market as a ``bid-based, security-constrained economic dispatch'' with 
voluntary participation by generators and loads. Professor Hogan 
emphasizes that the RTO must not reject voluntary bids, stating that 
the natural extension of open access and the principles of choice would 
suggest that participation in the coordinated balancing market offered 
by the operator should be voluntary. He states that market participants 
can evaluate their own economic situation and make their own choice 
about participating in the operator's economic dispatch or finding 
similar services elsewhere. He believes that any other rule would 
require some form of discrimination, and adds that there should be a 
strong burden of proof for those who argue that it is necessary to 
restrict voluntary bids, or discard consideration of some bids. 
Professor Hogan claims that experience in PJM and elsewhere shows that 
his suggested approach can work.
    However, several commenters take a very different view, claiming 
that the development of a real-time balancing market is not a viable 
option.547 For example, FirstEnergy is concerned that a 
real-time balancing market is not practical to implement. It claims 
that transmission customers do not yet have the real-time metering and 
associated communication needed to dispatch and match fluctuating loads 
to generation. FirstEnergy argues that it would be much better to tie 
this service to the NERC effort of certifying ancillary service 
providers for control of generation, and activate the service when the 
technology and installation can be accommodated. Seattle states that it 
performs its own real-time energy balancing and expects to continue to 
do so. Seattle opposes adding this function to an RTO because Seattle 
believes it will increase the overhead costs of the organization. 
Seattle believes that market participants that require this service 
should contract with third parties that stand ready to provide it. 
Florida Power Corp. states that, given the complexity of implementing 
short term transmission service in general, it is difficult to imagine 
that a market for

[[Page 894]]

energy imbalance service could be developed. It argues that if the 
market is limited to the generators needed for control, the development 
of market mechanisms will depend on resolving issues such as the 
mitigation of potential market power. Florida Power Corp. suggests that 
an RTO could contract with generators to perform this balancing 
function using a mechanism that is market-like in that generators would 
be selected based on their bids to perform the function over some 
designated period of time, albeit not on an hourly basis.
---------------------------------------------------------------------------

    \547\ See, e.g., Seattle, FirstEnergy, Florida Power Corp.
---------------------------------------------------------------------------

    Several commenters believe that control areas or RTOs should not be 
the sole provider of energy imbalance services,548 while 
others argue that the role of RTOs should be limited to that of a 
supplier of last resort. 549 UtiliCorp states that, in 
addition to serving as a supplier of last resort, the RTO must ensure 
public access to real-time balancing information. SMUD argues that any 
burden on the RTO that falls outside of the core function of ensuring 
regional transmission reliability will add cost and complexity to an 
already costly and complex endeavor. SMUD recommends that the 
Commission should limit its focus on generation to the role that 
generation-related service plays in promoting reliable transmission. 
Desert STAR and FirstEnergy believe that the Commission should give 
deference to RTOs regarding the development of markets for real-time 
balancing.
---------------------------------------------------------------------------

    \548\ See, e.g., Southern Company, Tri-State.
    \549\ See, e.g., UtiliCorp, Avista, APX.
---------------------------------------------------------------------------

    FirstEnergy believes that, ultimately, ancillary service provision 
must be based on a free-market pricing mechanism, and Southern Company 
believes that if a real-time balancing market is desired in a region, 
it will develop without a mandate. FirstEnergy asserts that the 
detrimental effects of regulated and capped ancillary service markets 
have been observed in the California and PJM markets. Also, APX 
believes that the Commission should let the market, not the RTO, 
provide the trading arrangements in the power industry. APX asserts 
that efficiency in the competitive market comes from the de-centralized 
trading activity of self-interested buyers and sellers, and that 
competition will develop further when market participants self-provide 
their ancillary services which they acquire in forward contract 
markets. In APX's view, the RTO should not provide a centrally 
optimized dispatch because a central dispatch will discourage, if not 
eliminate, the commitment of forward contracts in the energy market and 
replace the price discovery of forward markets with ex post pricing. To 
the extent that the RTO must acquire ancillary services, including 
balancing services, APX believes that the RTO should acquire them from 
a market created by market participants, and not create its own 
markets. NERA, however, states that this argument ignores the fact that 
preventing the ISO from operating balancing markets does not eliminate 
the network interactions and real-time events that are inherent in any 
electricity network. Rather, according to NERA, it merely forces the 
ISO to manage these interactions and events by less efficient and more 
intrusive non-market means. NERA contends that if the objective really 
is to maximize the role of competitive market forces and minimize the 
extent to which the monopoly ISO determines the outcome, the ISO should 
operate market-clearing mechanisms that reflect network interactions 
and real-time events as accurately as possible. Similarly, ISO-NE 
claims that it does not understand how operating a market in which (as 
in New England, currently) an RTO does not buy and sell the pertinent 
commodities can constitute ``taking a position'' in those markets such 
that its operation is perceived as biased. ISO-NE believes that because 
it does not own market assets or commodities, an ISO-type RTO is 
exceptionally well situated to run a fair and non-discriminatory 
market. ISO-NE states that the linkages among transmission operation/
dispatch, generation commitment/dispatch, and economic and market 
forces strongly support the integration of a physical market with an 
RTO's operations. Nevertheless, ISO-NE states that other financial 
power markets are welcome and can co-exist in the same region with an 
RTO market.
    Several commenters offered their views as to whether unequal access 
to balancing options leads to unequal access in the quality of 
transmission service available to different customers, and whether this 
is a significant problem when RTOs serve some customers that operate 
control areas and other customers that do not.\550\ A number of 
commenters believe that the present system does lead to undue 
discrimination.\551\ Enron/APX/Coral Power states that both the NERC 
and pro forma tariff rules are inequitable and discriminatory in that 
large customers rarely will be significantly out of balance due to the 
law of large numbers. Enron/APX/Coral Power states that such customers 
are given great flexibility to balance their scheduled deliveries and 
load, while smaller customers are much more likely to exceed the 1.5 
percent deviation band, making them immediately subject to penalties. 
Enron/APX/Coral Power believes that by offering real-time balancing to 
all transmission customers, the NOPR promises to redress this inequity. 
TDU Systems recommends that, pending the development of competitive 
balancing markets, the existing inequity between control area operators 
and other users be partially redressed by enlarging the deadband for 
imbalances to be repaid or received in kind to no less than five 
percent of scheduled amounts. It also recommends that the penal 
character of these charges should be reduced to a ten percent premium, 
except in cases of abuse.
---------------------------------------------------------------------------

    \550\ See, e.g., Enron/APX/Coral Power, LG&E, PJM/NEPOOL 
Customers, FirstEnergy, TDU Systems, Florida Power Corp.
    \551\ See, e.g., Enron/APX/Coral Power, PJM/NEPOOL Customers, 
TDU Systems.
---------------------------------------------------------------------------

    PJM/NEPOOL Customers argue that, to the extent current control area 
operators wish to maintain access to inadvertent energy accounts to pay 
back imbalances and avoid penalties, other transmission customers must 
have the same opportunity. In the alternative, it recommends that all 
users be required to cash-out through the RTO balancing process. 
Utility Engineers recommends implementing a pricing plan for 
inadvertent interchange by participants of the RTO, where the price for 
inadvertent interchange is geographically differentiated to reflect 
losses and constrained transmission paths. They claim that such a 
pricing plan would need a continuous auction, which could be achieved 
through establishing a pricing formula.
    With regard to providing access to inadvertent energy accounts, 
other commenters argue that there are valid reasons for distinguishing 
between customers that are control areas and those that are not. 
FirstEnergy argues that no other entity, other than control areas, can 
or should have that access to inadvertent accounts. It claims that, if 
market participants are provided with the authority to ``go 
inadvertent'' as control area operators currently have, the strain on 
the grid would drastically degrade system reliability, requiring much 
higher reserve capacity requirements. FirstEnergy believes that 
marketers would ``borrow'' from the grid during high price time periods 
and make whole on their borrowing during low price time periods, thus 
distorting the true price signal. Florida Power Corp. notes that in 
addition to balancing generation against load, control area balancing 
also includes a requirement for contributing to the maintenance of

[[Page 895]]

system frequency. In contrast, it notes that the non-control area 
transmission customer's balancing requirement is limited to the 
directly measured load it serves. Florida Power Corp. also claims that, 
if a system of payments was substituted for the inadvertent payback 
system presently used, control area operators would simply be 
circulating large sums of dollars between themselves to accomplish the 
same result at a higher administrative cost. LG&E suggests that the 
Commission treat such technical issues separate from the RTO NOPR and 
work in conjunction with NERC's parallel efforts in this area. Also, 
Florida Commission believes that inadvertent energy accounting between 
control areas should continue to be allowed within the operating 
standards of NERC.
    With regard to any requirement that loads and resources must be in 
balance from moment-to-moment, Professor Hogan and Eric Hirst believe 
there is no need for individual loads and generation to balance their 
schedules separately, and PJM/NEPOOL Customers states that balancing 
should be required only to ensure that generators deliver the amount 
scheduled and committed. Professor Hogan argues that individual 
balancing requirements both complicate the task for the RTO and provide 
a device to reinforce market power. Eric Hirst states that the RTO's 
costs of providing or absorbing imbalance energy should be charged 
equitably to those that under-generate and over-consume, with 
compensation to those that over-generate and under-consume. He states 
that this will result in charges and payments netting roughly to zero 
in each hour. However, Enron/APX/Coral Power believes that any RTO 
proposal should include development of an ex post energy balancing 
market in which buyers and sellers are given a finite amount of time 
after the market has closed to find others with offsetting positions.
    Regarding the imbalances of individual transmission customers, 
commenters disagree as to whether a distinction should be made between 
loads and generators. MidAmerican and Florida Power Corp. believe that 
loads and generators should be treated differently. MidAmerican 
contends that it is much easier to control generators than it is to 
control load, and in the future managing imbalances will become more 
complex in that control from the load-side will involve the response of 
potentially thousands of entities that may or may not respond as 
quickly as central generation. MidAmerican states that a distinction 
exists between loads and generators both in magnitude and response 
time. Florida Power Corp. claims that load and generators are not 
always similarly situated. It states that the nature of energy 
imbalance service depends on whether a generator and the load that it 
serves are in the same control area or are in different control areas. 
Eric Hirst, TDU Systems, and Duke believe that, in general, the market 
rules and principles should be the same or comparable for generators 
and loads, although TDU Systems believes that loads may be less likely 
than generators to abuse the system by leaning on it. Eric Hirst states 
that the use of imbalance markets would eliminate the asymmetry between 
generation and load in FERC's definition of energy imbalance.
    Finally, the NOPR also asked whether customers should be able to 
pay for all imbalances in a market or only imbalances within a 
specified band. Duke believes that it is appropriate to let the market 
participants determine how imbalances will be determined and paid. PJM/
NEPOOL Customers believes that the RTO should provide transmission 
users with as many service offerings as possible, including the ability 
to opt for different balancing pricing proposals. Florida Power Corp., 
however, believes that there should only be one method of settling the 
imbalance market. It claims that complexity and opportunities for 
gaming increase with options for settlement.
    MidAmerican believes that transmission customers should pay for all 
energy imbalances caused by the mismatch of scheduled energy and actual 
load. It recommends that imbalance charges be based on market prices at 
the time the imbalance occurred, and should include a penalty, in 
appropriate circumstances, to deter future imbalances. MidAmerican 
contends that if transmission customers are allowed to avoid payment 
within a specified bandwidth, gaming of the transmission system will 
occur.
    PJM/NEPOOL Customers and Professor Hogan, however, argue that the 
RTO should not be allowed to impose balancing penalties on transmission 
users. Eric Hirst states that RTOs should maximize the use of price 
signals rather than penalties to encourage appropriate behavior on the 
part of generators and loads, and Professor Hogan states that such 
prices should reflect the marginal cost for power. Eric Hirst believes 
that penalties should be imposed only to counter the perverse 
incentives that are created when metering or billing procedures require 
prices to be calculated over time intervals that do not correspond to 
those used to measure generation and consumption quantities. Using the 
example of the California ISO, he states that mismatches between ten 
minute prices and hourly quantities provide unintended incentives to 
generators to ignore ISO dispatch instructions or to ignore their 
schedules. He claims that aligning the time periods for price 
determination and billing would eliminate these perverse incentives. He 
adds that, where penalties are needed, they should be closely tied to 
the costs incurred by the ISO.
    TDU Systems argues that if markets for balancing services are fully 
competitive, transmission users should be able to use them to deal with 
any amount of imbalance. TDU Systems recommends that until such markets 
are fully competitive, it may be necessary to restrict such purchases 
to a deadband to prevent abuse. It believes that any such deadband 
should be less restrictive than that of the pro forma tariff. In that 
regard, it recommends that the minimum within-band allowance should be 
no less than the greater of two megawatts or five percent for loads or 
capacities up to 200 MW, with declining percentage tolerances as loads 
and capacities increase in size.
    Commission Conclusion. We conclude that an RTO must serve as the 
provider of last resort of all ancillary services required by Order No. 
888 and subsequent orders.
    Since some commenters interpreted the ``supplier'' of last resort 
obligation as proposed in the NOPR to require that the RTO be the 
direct supplier of ancillary services,552 we have made a 
minor change to the requirement by substituting the term ``provider'' 
for ``supplier.'' We clarify that this obligation requires that the RTO 
have adequate arrangements in place for the provision of ancillary 
services.
---------------------------------------------------------------------------

    \552\ See, e.g., LPPC, Los Angeles, Georgia Transmission, JEA, 
PPC. A direct supplier of ancillary services either owns or operates 
generation.
---------------------------------------------------------------------------

    The ancillary services adopted in Order No. 888 were defined using 
the control area and its operator as the basis because a majority of 
transmission service was provided by control area operators and they 
controlled the generation facilities that supplied ancillary services. 
We note that since we are not requiring the RTO to be a single control 
area operator, we can not require an RTO that owns no generation to be 
the direct supplier of ancillary services. Therefore we will give the 
RTO and its participants flexibility in developing adequate 
arrangements for the provision of ancillary services to all 
transmission

[[Page 896]]

customers that request service over the facilities under RTO control.
    The RTO could fulfill its ancillary services obligations through a 
variety of mechanisms, including contractual arrangements, indirect or 
direct control of specified generation facilities, or market 
mechanisms. However, regardless of the method of provision, the 
ancillary services must be included in the RTO administered tariff so 
that transmission customers will have access to one-stop shopping for 
transmission service.
    We conclude that all market participants must continue to have the 
option of self-supplying or acquiring ancillary services from third 
parties subject to any general restrictions imposed by the Commission's 
ancillary services regulations in Order No. 888 and subsequent orders. 
In such instances, the RTO must determine if the transmission customer 
has adequately obtained these services. The Commission believes that 
allowing self-supply provides a possible competitive check on the RTO 
to ensure that to the extent it does provide the services, it acquires 
them at lowest cost.
    In the NOPR we asked whether additional or revised ancillary 
services are needed. While a completely unbundled and competitive 
environment may require a modification to the ancillary services 
required by Order No. 888, comments suggest that an immediate change is 
unnecessary. We will not, at this time, make changes to the ancillary 
services described in Order No. 888. However, we will allow an RTO to 
propose other services in recognition of local or regional conditions.
    We conclude that the RTO 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 generators 
or other facilities that provide ancillary services must be subject to 
direct or indirect operational control by the RTO. The RTO must promote 
the development of competitive markets for ancillary services whenever 
feasible. To ensure the reliable operation of the system, an RTO must 
have authority to determine quantities and locations for ancillary 
services. The RTO should consider stakeholder input as well as 
established industry standards in determining these requirements. The 
Commission anticipates that some of the generation-based ancillary 
services could be acquired in short-term markets. This has been the 
approach taken by most of the ISOs that we have approved, and we see no 
reason that this would be different for transcos or other types of RTO 
entities. Apart from establishing the general requirement to use 
competitive markets, the Commission will allow the RTO considerable 
flexibility in determining many of the detailed market design 
questions, with case-by-case review by us.
    As we proposed in the NOPR, we conclude that 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. We 
have determined that real-time balancing markets are necessary to 
ensure non-discriminatory access to the grid and to support emerging 
competitive energy markets. Furthermore, we believe that such markets 
will become extremely important as states move to broad-based retail 
access, and as generation markets move toward non-traditional 
resources, such as wind and solar energy, that may operate only 
intermittently.
    Some commenters believe that implementation of real-time balancing 
markets presents technical problems that may prevent RTOs in some areas 
of the country from making such markets available to market 
participants. For example, some argue that it is difficult if not 
impossible for an RTO that is not a control area operator to operate an 
efficient real-time balancing market. These commenters suggest that to 
the extent such markets are feasible and desirable in a particular 
region, the RTO, its stakeholders and market participants should be 
given the flexibility to develop markets in accordance with their needs 
and capabilities.
    We are not convinced that, at this time, technical considerations 
preclude the development of a real-time balancing market for any 
potential RTO. As discussed elsewhere in this Final Rule, we are 
requiring each RTO to be the security coordinator for its region and to 
have, at a minimum, the authority to exercise a combination of direct 
and functional control over facilities within its region. Thus, even if 
an RTO is not a control area operator, it should have sufficient 
operational authority to ensure that a real-time balancing market can 
be implemented. With regard to the issue of flexibility, we believe 
that real-time balancing markets are essential for development of 
competitive power markets. Therefore, although we will give RTOs 
considerable discretion in how they operate real-time balancing 
markets, we will not allow implementation of such markets to be 
discretionary.
    Our conclusions regarding provision of real-time balancing markets 
are similar to our conclusions regarding markets for congestion 
management; that is, we will not prevent an entity other than an RTO 
that is unaffiliated with market participants, from seeking to offer 
transmission customers a real-time balancing market. However, because 
this function is so time-sensitive and requires such close coordination 
with the actual dispatch, experience may ultimately show that it cannot 
be performed to a high degree of efficiency unless it is made a part of 
the RTO's central or hierarchical dispatch activities. Also, we do not 
agree that an RTO's operation of a real-time balancing market will 
interfere unduly with the efforts of others to establish markets in 
forward contracts for energy.
    We asked in the NOPR whether customers should have the option of 
paying for all imbalances in a real-time balancing market or only 
imbalances within a specified band. Based on the comments received, we 
decline to give a generic solution for all RTOs in this rule. An RTO 
may propose one approach or the other but should explain how it 
proposes to overcome any disadvantages of the approach selected.
    In the NOPR, we noted that unequal access to balancing options can 
lead to unequal access in the quality of transmission service, and that 
this could be a significant problem for RTOs that serve some customers 
who operate control areas and other customers who do not. We conclude 
that control area operators should face the same costs and price 
signals as other transmission customers and, therefore, also should be 
required to clear system imbalances through a real-time balancing 
market. We believe that providing options for clearing imbalances that 
differ among customers would be unduly discriminatory.
    Finally, we asked in the NOPR whether, for the imbalances of 
individual transmission customers, a distinction should be made between 
loads and generators. We conclude that, for the purpose of determining 
cost responsibility for imbalances, no distinction needs to be made. 
The system-wide balance between load and generation is affected 
comparably by changes in load and changes in generation. Therefore, the 
cost of an imbalance is unaffected whether the imbalance is determined 
ultimately to be the responsibility of load or of generation. However, 
commenters point out certain differences between loads and generators 
(such as in the time needed to respond to an operator's

[[Page 897]]

instructions) that are important from the standpoint of system 
operation. These differences can be relevant to the determination of 
the appropriate penalties to assess to loads and generators that fail 
to submit accurate schedules. Thus, for purposes of assessing penalties 
for inaccurate schedules, we conclude that a penalty mechanism that 
treats loads and generators differently may be appropriate.
5. OASIS and Total Transmission Capability (TTC) and Available 
Transmission Capability (ATC)
    In the NOPR, the Commission proposed that an RTO must be the single 
OASIS site administrator for all transmission facilities under its 
control and independently calculate TTC and ATC. The Commission stated 
that the most controversial aspect of OASIS operation is the 
calculation and posting of ATC \553\ and noted that there is widespread 
dissatisfaction with the reliability of posted ATC numbers. To 
alleviate this problem, the Commission proposed that the RTO become the 
administrator of a single OASIS site for all transmission facilities 
over which it is the transmission provider.\554\ The NOPR outlined 
three levels at which an RTO could be involved in ATC calculations. At 
Level 1, the RTO would post ATC values received from transmission 
owners. At Level 2, the RTO would receive raw data from transmission 
owners and itself calculate ATC values. At Level 3, the RTO would 
itself calculate ATC values based on data developed partially or 
totally by the RTO.
---------------------------------------------------------------------------

    \553\ FERC Stats. and Regs. para. 32,541 at 33,747.
    \554\ Id. at 33,748.
---------------------------------------------------------------------------

    In the NOPR, the Commission envisioned that RTOs would operate at 
Level 3 to ensure that ATC values are based on accurate information and 
to minimize the opportunities for manipulation.\555\ The Commission 
also proposed that: (1) An RTO must formulate a validation system to 
check any ATC data supplied by others; (2) in the event of a dispute 
over ATC values, the RTO's data should be used pending the outcome of 
the dispute resolution process; and (3) the RTO must formulate the 
operating standards (subject to regional and national reliability 
requirements) underlying ATC calculations.\556\
---------------------------------------------------------------------------

    \555\ See id.
    \556\ Id.
---------------------------------------------------------------------------

    Comments. Most commenters who address the subject agree with the 
Commission's observations regarding dissatisfaction with ATC/TTC data. 
Moreover, most commenters on the subject endorse the proposal that an 
RTO must be the single OASIS site administrator for all transmission 
facilities under its control.\557\ Some commenters, however, are 
opposed to mandating the RTO as the OASIS site administrator. For 
example, Central Maine argues that it should not be precluded from 
operating its own site because as a ``wires-only company'' it has an 
incentive to operate an efficient site in order to maximize use of 
transmission capacity. EEI asserts that OASIS operation can occur 
independently of formation of an RTO and that the tasks and problems of 
OASIS operation will not become naturally easier to solve with the 
creation of an RTO.
---------------------------------------------------------------------------

    \557\ See, e.g., NASUCA, WPSC, EAL, NERC, Industrial Consumers, 
Entergy, Mass Companies, JEA, LG&E, NY ISO, NJBUS, Sithe, TAPS, How 
Group, Southern Company, PG&E, PJM, UtiliCorp, Williams, Cinergy, 
Oneok, East Texas Cooperatives, Cal DWR, Tri-State, Seattle, New 
Smyrna Beach, RUS, Cinergy, Nevada Commission, and Enron/APX/Coral 
Power.
---------------------------------------------------------------------------

    Most commenters also support the Commission's proposal to have the 
RTO independently calculate ATC and TTC.\558\ In addition, a number of 
commenters emphasize that independent and disinterested RTOs could be 
trusted and empowered to maintain reliable ATC data and calculate 
accurate values.\559\ Moreover, several commenters are concerned with 
consistency across RTOs and contend that RTOs must also coordinate ATC 
values with adjacent regions and with the NERC regional reliability 
councils.\560\
---------------------------------------------------------------------------

    \558\ See, e.g., Sithe, RUS, TAPS, PG&E, SMUD, Cal DWR, New 
Smyrna Beach, East Texas Cooperatives, WPSC, EAL, NERC, NASUCA, 
Seattle, Georgia Transmission, First Rochdale, Tri-State, Industrial 
Consumers, Enron/APX/Coral Power, Cinergy, Oneok, PJM, Williams, 
Empire District, PJM/NEPOOL Industrial Customers, Entergy, Mass 
Companies, Nevada Commission, NJBUS, and LG&E.
    \559\ E.g., FMPA, East Texas Cooperatives, NJBUS, Empire 
District, Entergy, Oneok, First Rochdale, Seattle, EAL, Sithe, WPSC, 
Sithe, PG&E, SMUD, New Smyrna Beach, and PJM/NEPOOL Customers.
    \560\ See, e.g., Industrial Consumers, Seattle and WPSC.
---------------------------------------------------------------------------

    Many commenters concur with the Commission's conclusions about the 
different levels of RTO involvement in ATC calculations. These 
commenters believe that Level 1 is insufficient for reliable and 
trustworthy data and that an RTO should independently calculate ATC 
values. Several commenters, however, disagree about the appropriate 
timing for Level 3 compliance. Some commenters, such as Cinergy, argue 
that upon commencement of operation, an RTO should be required to 
perform all studies and analysis needed for accurate ATC values 
consistent with Level 3. APX supports each RTO reaching Level 3 as 
quickly as possible. Enron/APX/Coral Power asserts that upon 
commencement of operation, an RTO should operate at Level 2 and, as it 
gains operational experience, migrate to Level 3. SMUD supports RTO 
operation at Level 3 but is concerned about the significant costs 
associated with developing data.
    JEA is opposed to any RTO structure that gives an RTO complete 
authority over ATC calculations for transmission that JEA will continue 
to own. JEA asserts that transmission owners are in the best position 
to assess the capabilities of their own transmission system. Therefore, 
absent formation of a transco, JEA does not support relying on an RTO 
for ATC and TTC calculations because JEA argues that ownership and 
control of the assets would be split between two or more entities whose 
interests are not always the same.
    Both Cal ISO and NY ISO argue that the final rule should provide 
flexibility in the OASIS requirements to accommodate network systems 
like the Cal ISO and the NY ISO in which transmission service is not 
explicitly reserved. In addition, numerous commenters argue that the 
Commission should expand the minimum requirements to have every RTO 
employ a single set of OASIS practices and terminology.\561\ They note 
that consistency in OASIS procedures will allow seamless trades across 
RTOs.
---------------------------------------------------------------------------

    \561\ See, e.g., Williams, EPSA, Cinergy, Empire District and 
PJM/NEPOOL Customers.
---------------------------------------------------------------------------

    How Group also focuses its comments on the standardization of 
transmission transactions. It notes that without some level of 
standardization only a limited number of market participants who learn 
all of the differences between RTOs can perform transactions that span 
multiple RTOs. How Group proposes that each RTO establish a 
coordinating committee with neighboring RTOs and transmission customers 
in order to: (1) Coordinate the naming of interconnected facilities, 
sources, sinks, paths, points of receipt and/or delivery between the 
RTO and its neighbors; (2) coordinate the sharing of necessary data for 
the calculation of transmission capability on interconnected paths; and 
(3) foster coordination with neighbors in adopting standardized 
business practices. It also suggests that continued industry-wide 
coordination is necessary to formulate common definitions for types of 
transmission and ancillary services, curtailment priorities, and timing

[[Page 898]]

requirements for arrangement of transmission services.
    Only one commenter expressed concern about the proposal to use the 
RTO's ATC values in the event of a dispute. Southern Company contends 
that the existing transmission owner's data are preferable to the RTO's 
data. Southern Company argues that existing transmission owners have 
experience in operating the regional transmission facilities and, 
therefore, are best qualified to determine ATC values.
    Some commenters raise other OASIS-related issues that were not 
addressed in the NOPR. For example, commenters argue that: (1) All 
reservations and scheduling, including that for network service, should 
occur on the OASIS; (2) sanctions should be levied against transmission 
providers that skew their ATC values; and (3) the power flow 
methodology rather than the contract path model should be used for 
scheduling.\562\ A few commenters address issues relating to Capacity 
Benefit Margin (CBM). NASUCA argues that administration of CBM should 
be a required function of RTOs and that a uniform methodology for 
calculating CBM is needed. Similarly, Idaho Commission asserts that 
requiring the posting of CBM on OASIS with a narrative explanation of 
its derivation would be beneficial. Empire District states that the 
Commission should provide better guidance about how to calculate CBM.
---------------------------------------------------------------------------

    \562\ See, e.g., Ontario Power, Williams, NERC and EPSA.
---------------------------------------------------------------------------

    Commission Conclusion. After considering the comments, we continue 
to believe that an RTO must be the single OASIS site administrator for 
all transmission facilities under its control. As numerous commenters 
note, independent RTOs can be trusted to maintain an OASIS site with 
reliable and current data that is easy to use. In addition, a single 
OASIS site for each region instead of multiple sites will enable 
transactions to be carried out more efficiently.
    However, in response to those who argue for flexibility in OASIS 
requirements, we clarify that this requirement does not mean that each 
RTO must itself operate the OASIS for its region. Our concern is that 
there be no more than one OASIS site for the facilities under the RTO's 
control, and that the RTO ensure that the OASIS site operator have the 
same attributes of independence we require for an RTO. Thus, we will 
allow an RTO the flexibility to contract out OASIS responsibilities to 
another independent entity, if justified. More specifically, we do not 
intend to keep an RTO from participating in a ``super-OASIS'' jointly 
with other RTOs.
    We reaffirm that an RTO should operate at what the NOPR 
characterizes as Level 3 for ATC/TTC calculations, which requires the 
RTO itself to calculate ATC values based on data developed partially or 
totally by the RTO. Most commenters believe that Levels 1 and 2, where 
the RTO would accept the transmission owners' ATC calculations or data, 
are insufficient for reliable and trustworthy ATC values. Level 3 
ensures that ATC values are based on accurate information and 
consistent assumptions. When data are supplied by others, the RTO must 
create a system for tests and checks that ensure customers of 
coordinated and unbiased data. We also agree with commenters who 
recommend that RTOs coordinate ATC values with adjacent regions.
    We recognize that the NOPR was silent on the appropriate timing for 
Level 3 compliance. Commenters suggested that: (1) An RTO should reach 
Level 3 compliance upon commencement of operation; (2) an RTO should 
reach Level 3 as quickly as possible; or (3) an RTO should operate at 
either Level 1 or 2 upon commencement of operation and as it gains 
operational experience, migrate to Level 3. We conclude that an RTO 
OASIS site, including ATC calculations, must be fully operational at 
Level 3 upon commencement of service. All parties to a transmission 
transaction need precise ATC values to make scheduling decisions.
    We affirm that in the event of a dispute over ATC values, the RTO's 
values should be used pending the outcome of a dispute resolution 
process. Only one commenter, Southern Company, disagreed with this 
proposal and we are not persuaded by its arguments. Each RTO must 
develop procedures to validate its ATC values.
    How Group and other commenters address issues relating to the 
standardization of transmission transactions. Standardization of 
transactions involves two separate concerns: (1) Many transactions will 
cross RTO boundaries; and (2) numerous customers will do business with 
multiple RTOs. Without standardized communications protocols and 
business practices, the costs of doing business will be increased as 
market participants will be required to install additional software and 
add personnel to transact with different RTOs and regions. Therefore, 
to promote interregional trade, standardized methods of moving power 
into, out of, and across RTO territories will be needed.
    We believe that standards for communications between customers and 
RTOs must be developed to permit customers to acquire expeditiously 
common services among RTOs. For example, we envision the creation of 
standardized communications protocols to schedule power movements and 
to acquire auction rights. These protocols would not standardize what 
the rights are, or the nature of the auctions. Instead, the focus of 
the communications protocols would be on how customers communicate 
their intentions to an RTO and how customers receive an RTO's 
responses.
    We agree with How Group and others that certain business and 
communication standards \563\ are necessary, and we believe that these 
standards will facilitate the development of efficient markets. We 
believe, however, that these issues need further examination based on a 
complete record.
---------------------------------------------------------------------------

    \563\ We believe that the communications standards and protocols 
would, like the current OASIS, make use of: (1) The Internet for 
communications; (2) interactive displays using World Wide Web 
browsers; (3) file uploads and downloads for computer-to-computer 
communication; and (4) templates defining the file uploads and 
downloads.
---------------------------------------------------------------------------

    A few other commenters discussed issues that were not addressed in 
the NOPR. For example, commenters argue that: (1) All transmission 
transactions (reservations and scheduling) should occur on the OASIS; 
(2) sanctions should be levied against transmission providers that skew 
their ATC values; and (3) the power flow methodology for scheduling, 
rather than the contract path model, should be utilized. In addition, 
NASUCA, Empire District and the Idaho Commission raise issues relating 
to CBM. These issues are too detailed for this proceeding and we will 
not address them at this time. Commenters will have the opportunity to 
bring up these issues in response to specific RTO filings, as well as 
during OASIS Phase II proceedings and in the CBM docket (Docket No. 
EL99-46-000).
6. Market Monitoring (Function 6)
    In the NOPR, the Commission proposed that RTOs perform a market 
monitoring function. Specifically, RTOs would be required to: (1) 
Monitor markets for transmission service and the behavior of 
transmission owners and propose appropriate action; (2) monitor 
ancillary services and bulk power markets that the RTO operates; (3) 
periodically assess how behavior in markets operated by others affects 
RTO operations and how RTO operations

[[Page 899]]

affect those markets; and (4) provide reports on market power abuses 
and market design flaws to the Commission and affected regulatory 
authorities, including specific recommendations. In addition, the 
Commission asked a number of questions regarding the role of RTOs in 
market monitoring, the tools RTOs should use, and similar issues.
    Comments. Commenters address a number of issues regarding the 
market monitoring function. The issues can be grouped into three 
general areas: (1) The need for and scope of a market monitoring 
function; (2) who should perform the market monitoring function and how 
it should be performed; and (3) what are the specific components or 
procedures of a market monitoring plan.
    Need For and Scope of Market Monitoring. As a general proposition, 
a variety of commenters favor having RTOs serve as market 
monitors.\564\ Commenters, such as Blue Ridge, argue that RTOs should 
conduct market monitoring because they will be in the best position to 
deal with the growing volume of multiparty transactions and discern any 
manipulation or preferential treatment. Several commenters, such as the 
Florida Commission, note that the appropriate role for RTOs in market 
monitoring and the various aspects of the function will depend upon the 
nature of the RTO that is ultimately established. TEP claims that RTO 
market monitoring needs to be flexible given the costs involved in such 
a function. PP&L Companies believes that RTO market monitoring should 
focus on properly structuring business rules to foster efficient 
transactions and gathering statistical information to make available to 
the Commission or other enforcement agencies. EEI and Allegheny 
recommend that RTO market monitoring identify market design flaws and 
propose solutions that lead to greater efficiency, competitiveness and 
reliability.
---------------------------------------------------------------------------

    \564\ See, e.g., New York Commission, South Carolina Authority, 
Mass Companies, LG&E, ISO-NE, TAPS, SMUD, NECPUC, WPSC, Project 
Groups and Tri-State.
---------------------------------------------------------------------------

    A number of commenters support having the RTO should serve as the 
``first line of defense'' for detecting design flaws and market power 
abuses.\565\ Cal ISO suggests that the RTO serve as a first line of 
defense in conjunction with state commissions and local regulatory 
authorities in the region, particularly in the operation of hourly and 
real-time markets where potential buyers may not have the ability to 
decline electric service, and where transmission and ancillary services 
markets tend to have high concentrations. PJM believes that market 
monitoring by RTOs provides a continual check on market activities and 
accordingly, RTOs should have clear authority to investigate potential 
market power abuses or flaws and to compel market participants to 
produce relevant information. SMUD contends that although RTO 
monitoring should be the first line of defense, an independent RTO 
monitoring unit must not be a substitute for review by the Commission 
and other regulatory agencies.
---------------------------------------------------------------------------

    \565\ See, e.g., Metropolitan, DOE, CMUA, NASUCA and Project 
Groups.
---------------------------------------------------------------------------

    In contrast, some commenters, such as Cinergy, argue that, if 
transmission markets realize the efficiencies envisioned in the NOPR, 
the commodity market should be able to regulate itself, with the 
Commission and the courts serving as backstops. SNWA cautions that RTOs 
may be too focused on safe and reliable operations to be a first line 
of defense. Some commenters, such as Metropolitan and Southern Company, 
claim that there is no benefit in having RTO monitoring replicate the 
costly regulatory responsibility that already exists in state and 
Federal agencies.
    Several commenters propose an expansive RTO market monitoring role. 
NECPUC proposes that monitoring include mitigation of both market flaws 
and market power. East Texas Cooperatives and SMUD believe that RTO 
market monitoring should include remedying market abuse. Project Groups 
believes that an RTO should monitor energy and ancillary services 
markets and their interplay, and develop indices and criteria to 
evaluate activities and behaviors that may reflect market power abuse. 
Advisory Committee ISO-NE suggests that the RTO monitor transmission 
and ancillary services markets to identify design flaws and market 
power, and to administer or propose remedial actions. Dynergy claims 
that monitoring should include oversight of transmission owners' 
behavior. EPSA proposes that the RTO also document any significant 
market impacts attributable to application of reliability rules.
    Some commenters support limits on market monitoring by the RTO. 
Commenters, such as Southern Company and Entergy, argue that RTO 
monitoring should not reach to any market the RTO does not operate, nor 
should it encompass market power abuse and the effect of existing 
structural conditions on the competitiveness of electricity markets. 
Entergy adds that the RTO will not be in a good position to monitor 
markets it does not operate. Several commenters claim that the purpose 
of monitoring should be to look for market flaws, not act as policeman 
looking for bad behavior.\566\ Desert STAR recommends that any proposed 
remedy be restricted to market flaws within the RTO's area of 
operation. Enron/APX/Coral Power argues that evaluation of the 
structure of power markets and policing market power lies outside of an 
RTO's core competencies as the operator of the transmission system. 
Tri-State opposes RTO monitoring of power markets because it would add 
to the complexity and cost of RTOs and impermissibly involve the RTO in 
issues about generation market power. NY ISO opposes monitoring to the 
extent that it encompasses the RTO playing an investigative and 
enforcement role. Nonetheless, in its view, the RTO could mitigate 
evident market power problems on a prospective basis by applying pre-
approved remedies.
---------------------------------------------------------------------------

    \566\ See, e.g., Desert STAR, CRC and Tri-State.
---------------------------------------------------------------------------

    Sithe recommends that RTOs not have the authority to compel the 
provision of commercially sensitive data and should instead rely on 
nonproprietary information to monitor markets. PG&E contends that 
commercially sensitive information should not be released to anyone 
except in accordance with Commission-approved rules. PP&L raises 
concerns regarding the ability of the RTO market monitoring 
organization to guarantee confidentiality of commercially sensitive 
information supplied to it. Seattle argues that any claims of 
commercial sensitivity must be tempered by the need to create an 
efficient, self-policing, transparent market for nondiscriminatory 
transmission services.
    Various commenters would limit the RTO market monitoring function 
to information gathering.\567\ They argue that the NOPR proposal is 
overly broad, too extensive and open-ended, and a potentially 
burdensome requirement. Sithe argues that the application of mitigation 
measures by the RTO could have real commercial impacts on market 
participants that often cannot easily be measured or repaid after the 
fact; therefore, market participants should have an opportunity to 
review and comment on monitoring procedures prior to their 
implementation. Seattle claims that the Commission should take a 
minimalist approach by facilitating market monitoring through greater 
public information disclosure. PG&E believes that the RTO should not 
regulate the functioning of the energy market. Duke supports RTO 
identification and description of alleged market abuses to appropriate 
authorities

[[Page 900]]

through the regulatory framework that exists today.
---------------------------------------------------------------------------

    \567\ See, e.g., CP&L, TDU Systems, PP&L and PG&E.
---------------------------------------------------------------------------

    Other commenters question the need for or otherwise oppose an RTO 
market monitoring function, in general, as a form of back door 
regulation.\568\ They contend that RTO monitoring will be unduly 
burdensome, overtaxing and costly to the ratepayers. Los Angeles and 
Salomon Smith Barney argue that RTO monitoring may interfere with the 
proper relationship between the RTO and its customers, which they claim 
should be focused solely on providing nondiscriminatory open access 
transmission services. UtiliCorp argues that the assignment of market 
monitoring functions to a commercial entity such as a transco (other 
than those functions concerned strictly with transmission pricing) may 
raise antitrust concerns both for the transco and its customers.
---------------------------------------------------------------------------

    \568\ See, e.g., Industrial Consumers, Williams, Southern 
Company, PSE&G, Arizona Commission, Georgia Transmission and East 
Kentucky.
---------------------------------------------------------------------------

    Commenters differ on whether market monitoring should continue 
indefinitely. East Texas Cooperatives believes that continuous RTO 
market monitoring is necessary because, in its view, antitrust laws and 
complaints to the Commission provide only a slow, after-the-fact 
remedy. Entergy recommends that any RTO self-monitoring be allowed to 
terminate after a fixed period, subject to Commission approval. 
Industrial Consumers suggests that market monitoring be limited to the 
period when the risk of discriminatory conduct is greatest. Los Angeles 
claims that, once the Commission determines that generation markets are 
workably competitive, market forces should be allowed to discipline the 
markets. If an RTO market monitoring function is required, PSE&G 
suggests a five-year sunset provision.
    Who Should Perform Market Monitoring and How Should it Be 
Performed. Many commenters address the issue of whether the RTO should 
perform market monitoring depending on the form of the RTO (i.e., 
whether the RTO is a for-profit or a not-for-profit organization). Most 
commenters raise concerns about and generally oppose a for-profit RTO 
monitoring markets.\569\ The commenters generally argue that, due to 
its economic and business interests, a for-profit RTO cannot 
objectively monitor itself. CP&L submits that a for-profit RTO may be a 
competitor of other market participants in the provision of congestion 
relief and ancillary services, which would make unbiased monitoring of 
those markets difficult. TDU Systems would limit a for-profit RTO's 
role to data collection. Other commenters recommend that for-profit 
RTOs employ a fully independent organization to monitor market 
conditions.\570\ A few commenters, however, support for-profit RTOs 
serving as market monitors.\571\ Entergy claims that market monitoring 
conducted by a transco could be as effective as for any other type of 
RTO as long as procedures are in place that ensure its independence.
---------------------------------------------------------------------------

    \569\ See, e.g., Dynegy, South Carolina Authority, Industrial 
Consumers and East Texas Cooperatives.
    \570\ See, e.g., PJM/NEPOOL Customers, Cal ISO, Tri-State and 
Metropolitan.
    \571\ See, e.g., Entergy and Duke.
---------------------------------------------------------------------------

    Commenters also address whether an RTO that is an ISO needs to 
insulate its market monitoring function from other RTO functions to 
ensure independence and objectivity. A number of commenters generally 
believe it is appropriate for ISOs to internally monitor market 
activities either through staff devoted to the function or through a 
committee of ISO members assigned to the function.\572\ They argue that 
an ISO, which would be free of commercial interests, can be trusted by 
market participants, and therefore should not have to undertake costly 
establishment of autonomous monitoring units. Mid-Atlantic Commissions 
note that PJM ISO's monitoring unit is a neutral body that has access 
to and maintains confidentiality of market sensitive data in accordance 
with sharing arrangements with each of the states in the region. 
California Board contends that, if the internal unit is independent and 
has the ability to report and/or consult with state and Federal 
authorities without needing additional approval, those regulators are 
likely to respect the opinions and recommendations of the market 
monitoring unit. CalPX suggests that RTOs and separate power exchanges 
coordinate their market monitoring functions and jointly conduct 
research to lower costs. EPSA suggests that the information and market 
data, if collected by an independent and unbiased RTO, could be relied 
upon by market participants in formulating business strategies, and by 
regulators for purposes of reviewing and approving modifications to 
regulated aspects of RTO structures and operations.
---------------------------------------------------------------------------

    \572\ See, e.g., PJM, ISO-NE, NY ISO, WPSC and East
---------------------------------------------------------------------------

    Most commenters, however, would require an ISO (i.e., a not-for-
profit RTO) to make its market monitoring function more independent. 
Pennsylvania Commission contends that an independent ISO is absolutely 
necessary to perform market monitoring functions. EEI points out that 
while an RTO's independence may ensure that its recommendations do not 
favor particular market participants, this does not ensure that it will 
monitor its own performance objectively. In its view, an ISO should use 
outside experts within the monitoring committee or on an ad hoc basis 
to address concerns about objectivity. Similarly, PG&E contends that 
experience has shown that an ISO's rules and actions may interfere with 
the proper functioning of the market. Industrial Consumers contend that 
an RTO's operations must be sufficiently transparent that it is the 
market participants that do the real monitoring. FTC suggests that 
internal RTO monitoring could be problematic if the internal monitoring 
unit is given enforcement powers, because this could both devolve into 
re-regulation and raise conflict of interest issues. FTC recommends 
that the Commission's RTO rules explicitly make clear that self-
monitoring controlled by an RTO does not create an antitrust exemption 
for the RTO and its participants.
    Los Angeles believes that market monitoring should be conducted by 
an independent body. CP&L, however, believes that delegation to a 
private party is questionable, where its objectivity may also be 
challenged on grounds of conflict of interest, particularly, if the 
delegated authority includes the ability to impose sanctions and 
penalties. Oregon Commission believes that RTOs should appoint a local 
committee to use RTO data to monitor the market for ancillary services 
because RTOs, as major buyers and sellers of such services, will want 
to protect their market shares. The Commission should consider 
establishing its own regulatory advisory bodies to monitor markets. DOE 
also claims that the Commission should avoid reliance upon RTO 
monitoring to the exclusion of the Commission's own monitoring efforts. 
Alliant believes that moving responsibility for monitoring market power 
to another organization would allow the RTO to focus on the many 
technical demands that will be placed on it. Metropolitan believes 
market monitoring should occur on two levels: an internal group 
responsible for data gathering and publication and frequent preliminary 
analysis of anomalous conduct; and formal analyses performed by a group 
or committee independent of RTO management whose results and 
recommendations would not require RTO approval.
    LG&E proposes that the RTO make its monitoring findings public and 
refer

[[Page 901]]

them to an appropriate regulatory body. Industrial Consumers opposes 
giving deference to the RTO's recommendations for correcting such 
market power abuses and flaws. Instead, it believes that stakeholders 
and market participants should use the RTO reports to make their own 
recommendations.
    NYPP believes that structural solutions are matters for 
legislators, courts or regulatory agencies. In contrast, PJM believes 
that, if the market issue is a structural one, the RTO should be able 
to propose structural remedies to the Commission.
    In the case of localized market power, MidAmerican submits that it 
would be inappropriate for the RTO to take corrective competitive 
actions in the case of localized must run generating unit market power. 
Similarly, PG&E contends that RTOs should allow temporary supply and 
price issues to be resolved by the competitive forces of the market, 
unless there is a threat to the physical supply of power or a 
Commission determination that markets are not workably competitive.
    CalPX believes that monitoring and reporting should be simplified 
in order to reduce costs and to rationalize staff and committee work 
loads. Also, the RTO and power exchange compliance related staffs 
should jointly conduct research that is beneficial both to increase 
coordination and reduce costs. NY ISO submits that RTOs that are ISOs 
should not be required to establish costly and otherwise burdensome 
autonomous market monitoring units.
    Many commenters address the issue of the appropriate role for the 
Commission and the state commissions in market monitoring. Commenters 
overwhelmingly believe that the Commission and state commissions have 
an important role to play, whether it is a primary role as market 
monitors, or a secondary role providing oversight of market monitoring 
activities by RTOs.
    Some commenters believe that market monitoring is better handled by 
the existing statutory and regulatory agency frameworks than by 
RTOs.\573\ They suggest a continuing, if not mandatory, role for the 
Commission and other Federal and state authorities in conjunction with 
any market monitoring undertaken by RTOs.\574\ PP&L Companies argues 
that, in Gulf States Utilities Co. v. FPC,\575\ the Supreme Court made 
it clear that the Commission is charged with serving as the first line 
of defense to protect and preserve competition in wholesale power 
markets.
---------------------------------------------------------------------------

    \573\ See, e.g., Salomon Smith Barney, South Carolina 
Commission, PG&E, Enron/APX/Coral Power and Duke.
    \574\ See, e.g., SMUD, Tri-State, Cinergy, TDU Systems, EPSA, 
Industrial Consumers, CMUA, PJM/NEPOOL Customers, NY ISO, ISO-NE and 
DOE.
    \575\ 411 U.S. 747 (1973).
---------------------------------------------------------------------------

    TDU Systems and Sithe contend that regulatory commissions cannot 
abdicate to RTOs the responsibility to ensure that wholesale electric 
markets are free of market power. Many commenters see RTOs serving to 
forward any claims of market abuse and market power to the various 
federal and local regulatory agencies consistent with their respective 
jurisdictions. PJM and LG&E see the Commission reviewing remedies and 
approving penalties and sanctions. Desert STAR and CRC see the 
Commission acting as a backstop to an RTO's ADR process or mitigation 
plan. EEI suggests that RTOs regularly inform the Commission about 
monitoring results, which will enable it to respond quickly to problems 
not resolved by the RTO. SoCal Cities suggest that RTOs share 
responsibility to remedy structural defects in the market or impose 
general sanctions for market power abuse with appropriate state and 
federal agencies, but not duplicate their responsibilities such as 
implementation of the FPA. CalPX believes that there is a decreasing 
role for regulatory oversight as a result of a progression toward 
greater RTO self-regulation.
    Florida Power Corp. and Nevada Commission suggest close 
coordination of RTO market monitoring with state regulators. Nevada 
Commission also suggests that RTOs collaborate their monitoring efforts 
with neighboring RTOs, as well as audit the records of those parties 
who violate the RTO's rules. Project Groups recommends adding an eighth 
minimum function under which RTOs provide data support for states' 
policies, monitoring the competitive impacts of emissions regulations, 
verifying compliance with state generation portfolio standards.
    NARUC claims that the states need to be heavily involved in RTO 
market monitoring and that the Commission should work with the states 
to make utility codes of conduct more effective. In its view, such 
collaboration is the most effective means of monitoring market power in 
generation, since the RTO would have information for the region on 
transmission planning, generation expansion and transmission 
constraints, and state commissions would have utility specific data and 
information on local operations. NARUC argues that such collaboration 
is critical because state commissions are responsible for both 
evaluating local markets to assure competitiveness and for licensing 
electric supplies, and abusers of market power can inhibit competition 
and distort the prices of locally regulated services. NASUCA similarly 
claims that market participants, state and federal regulatory agencies, 
and state consumer advocates periodically review the indices and 
screens to be used for RTO market monitoring. The RTO should 
periodically issue confidential reports to federal and state regulatory 
authorities and state consumer advocate offices, that describe the 
state of the markets and the results of matters under investigation.
    A number of state commissions suggest a continuing oversight role 
over RTO monitoring by the Commission and the states.\576\ Oregon 
Commission recommends that the Commission establish its own regulatory 
advisory bodies to monitor ancillary services markets. For a for-profit 
RTO, it recommends that a regional oversight committee perform this 
function with the Commission reviewing any oversight committee reports.
---------------------------------------------------------------------------

    \576\ See, e.g., Florida Commission, New York Commission and 
Michigan Commission.
---------------------------------------------------------------------------

    Commenters also address a number of issues related to the ability 
of RTOs to perform self-assessments. A number of commenters believe 
that RTOs are capable of objective analysis. NY ISO contends that an 
ISO will have no incentive to distort the results of its analysis. 
Cinergy recommends that RTOs be limited to monitoring the behavior of 
the markets they administer because of the ready access to relevant 
information. Los Angeles comments that, if the RTO is not primarily 
responsible for providing ancillary services, it should not be burdened 
with surveying that market.
    Other commenters oppose RTOs monitoring the markets that they 
operate because of conflict of interest concerns.\577\ EEI argues that 
independence from market participants does not ensure that the RTO will 
be able to monitor its own performance objectively, e.g., a non-profit 
RTO may not have sufficient incentives to minimize the costs under its 
control. Oregon Commission comments that RTOs cannot be entrusted to 
monitor ancillary services markets, where they will be providing 
services and have incentives to protect market share. Industrial 
Consumers contends that market participants must perform monitoring 
and, accordingly, an RTO's operations should be fully transparent. SNWA 
and PG&E claim that the RTO

[[Page 902]]

should establish an independent body to monitor and evaluate its 
performance.
---------------------------------------------------------------------------

    \577\ See, e.g., Florida Power Corp., CMUA and DOE.
---------------------------------------------------------------------------

    Some commenters, such as Salomon Smith Barney and Michigan 
Commission, oppose the RTO monitoring markets where the RTO takes a 
market position because the RTO plays the dual role of seller of 
services and policeman. Alliant contends that an RTO will be competing 
with generation providers in congestion management and have an 
incentive to build transmission facilities. Similarly, CP&L contends 
that a for-profit RTO may compete with others in providing ancillary 
services, and therefore any proposal by the RTO monitor for remedial 
action raises serious conflict of interest concerns. Industrial 
Consumers suggests that, even in markets where the RTO is the supplier 
of last resort, the RTO should not have quasi-regulatory powers.
    Commenters also address the issue of whether RTOs should be 
required to provide periodic assessments of markets they do not 
participate in or operate, thereby assessing the effect of existing 
structural conditions on the competitiveness of their region's 
electricity markets. Some commenters oppose this proposal. Tri-State 
opposes an RTO monitoring of power markets because it would not only 
violate the Commission's goal of separation between transmission and 
power sales, it would also add a level of complexity and cost to the 
operation of the RTO. Justice Department believes that the RTO cannot 
reasonably be expected to monitor activities with which it has no 
involvement. Justice Department therefore recommends that the 
Commission consider requiring each separate electric power trading 
institution to monitor any market that it operates.
    On the other hand, a number of commenters favor extending RTO 
monitoring responsibility to markets they do not operate. PJM/NEPOOL 
Customers argues that the independence of the RTO would enable market 
participants and the Commission to have confidence in the RTO's 
assessments. ISO-NE favors RTOs monitoring power markets. NASUCA 
recommends that RTOs monitor bulk power markets, capacity markets, 
transmission rights markets, ancillary services markets and any other 
potentially competitive markets. FTC suggests that, where an RTO is 
smaller than one of the major interconnects, the Commission may wish to 
encourage all the RTOs within each of the interconnects to coordinate 
their efforts to examine the effects of market rules or variations 
between RTOs in market rules on the volume and price of inter-RTO 
transactions. Cal ISO also sees collaborative market monitoring and 
assessment by neighboring RTOs and at the national level.
    Florida Power Corp. recommends that an RTO that is an ISO be 
required to make regular assessments as to whether it has sufficient 
operational authority to ensure its ongoing ability to provide 
reliable, open access transmission service on a comparable basis to all 
customers--nonetheless, the RTO should not be self-regulating.
    For those regions where the real-time balancing function is 
performed by an ISO, Advisory Committee believes that the ISO should 
monitor market power in generation markets. SoCal Edison claims that, 
where markets are not yet workably competitive, the RTO, with 
Commission approval, should ensure that prices are just and reasonable 
through appropriate temporary mechanisms such as price caps. PG&E 
counters that, in no case, should RTOs be permitted to use control of a 
power exchange for unilaterally capping prices set by the market.
    Many commenters address the issue of how the RTO should report, if 
at all, its monitoring activities. The Commission did not propose to 
establish detailed standards on the format and content of monitoring 
reports, noting that such matters are best left to the RTO. We asked 
commenters to address whether reporting should be limited to when a 
specific problem is encountered, or whether periodic reporting on the 
state of competition and transmission access would be more appropriate.
    Commenters express mixed views on reporting requirements. CRC 
supports the concept of RTOs reporting to the Commission regarding RTO 
design flaws, and New York Commission suggests that RTOs report on 
market power abuse as well. Florida Power Corp. submits that, if market 
monitoring is necessary, it should be performed by the RTO reporting 
and filing appropriate information with state and Federal regulators. 
Project Groups wants the provision of data to support state programs 
pertaining to the monitoring of the competitive impacts of emissions 
regulations. Project Groups argue that RTOs would be uniquely 
positioned to support data collection for verification of green 
marketing claims and compliance with information disclosure 
requirements and portfolio standards. EEI opposes a Commission mandate 
for RTOs to track generation source and emissions data. EEI recommends 
the RTO voluntarily undertake this task to meet specific state 
compliance requirements provided appropriate safeguards protect 
competitively sensitive information. EEI expresses concern regarding 
the possibility that the RTO would have authority to collect and 
disclose information from a generation source where the state has not 
imposed such a requirement.
    Several commenters favor issuance of monitoring reports at regular 
intervals. Project Groups believes that RTO monitoring units should 
issue public reports on their activities and findings, including annual 
reports on the general state of the market. Metropolitan supports 
reporting at regular intervals from an external monitoring source; 
however, during initial startup, more frequent reporting is advisable 
to assist participants' understanding of the market operation. East 
Texas Cooperatives believes that RTOs should prepare periodic reports 
to the Commission with the precise form left to the discretion of the 
RTO.
    California Board contends that regular reports on market 
performance should issue at least on a yearly basis, and include all 
relevant data that can be made publicly available. NASUCA contends 
that, to further create trust in the RTOs' ability to effectively and 
objectively monitor the market, RTOs should periodically issue reports 
describing the state of the markets that it is monitoring, items under 
investigation by the RTO, and any results from completed 
investigations. In its view, market participants, state and federal 
regulatory agencies and state consumer advocates should participate in 
the development and periodic review of the indices and screens the RTO 
will use to monitor the operation of the markets. Reports should be 
provided to state and federal regulatory authorities as well as state 
consumer advocate offices, on a confidential basis, to enable them to 
independently assess whether additional investigation is merited. Cal 
ISO submits that the Commission should specify regular reporting 
requirements for the RTO's monitoring unit. PJM believes that RTOs 
should periodically report results of monitoring activities to the 
Commission and state agencies.
    Components of a Market Monitoring Plan. Commenters address various 
issues regarding particular elements of a market monitoring plan. Many 
commenters address the issue of whether RTOs should be allowed to 
impose penalties and sanctions. Most commenters would limit the RTO's 
ability to impose penalties or sanctions. Many of them argue that such 
authority should remain the province of the

[[Page 903]]

regulatory and antitrust agencies.\578\ Justice Department claims that 
RTOs lack experience either in detecting exercises of market power or 
in making recommendations on correcting market power problems. SPRA 
questions whether the imposition of sanctions by the RTO may conflict 
with the Supremacy Clause of the Constitution and whether affected 
public power bodies could only consent to such sanctions if they do not 
create indefinite or uncertain liabilities. PP&L argues that, because 
it will be judge and jury, the RTO must demonstrate competitive harm 
before taking any market action. Some commenters, such as CP&L, note 
that a for-profit RTO may not be objective in imposing sanctions 
because it competes with other market participants. Other commenters, 
such as Salomon Smith Barney, claim that RTOs should be limited to 
extracting ordinary commercial penalties when market participants fail 
to follow the market's rules. EPSA claims that RTOs should be empowered 
to intervene in a market within the strict confines of the Commission's 
oversight only when a situation has the potential to become 
catastrophic. Mass Companies opposes allowing a private RTO or one that 
is operated by a non-stakeholder board to enforce violations of market 
standards and impose sanctions and penalties.
---------------------------------------------------------------------------

    \578\ See, e.g., Entergy, Duke, PG&E, PSE&G, PJM/NEPOOL 
Customers and Williams.
---------------------------------------------------------------------------

    Canada DNR claims that it will be problematic for Canadian entities 
subject to the jurisdiction of Canadian provincial and Federal energy 
regulators also to be subject to an RTO that has its disciplinary 
authority backstopped by the Commission. In its view, the issue will 
not be resolved by simply having the appropriate Canadian regulator 
serve as the regulatory backstop to the RTO for each Canadian entity 
because the Canadian regulator may take a different position than the 
Commission.
    A few commenters support authority for RTOs to impose penalties and 
sanctions. Among them, CalPX believes that RTO governing boards and 
power exchange market monitoring committees must be able to take 
appropriate action either by referral to regulatory agencies or 
directly through applicable sanctioning authority. It views this as 
critical for self-policing and providing prompt remedies before 
problems detrimentally affect market results. ISO-NE believes that an 
RTO should have the ability to impose penalties and sanctions, but 
suggests that the RTO not act as an antitrust agency, in order to 
increase the acceptability of sanctions among participants.
    The Commission specifically sought comment on whether penalties 
should be limited to violations of RTO rules and procedures, or whether 
the RTO should be allowed to impose penalties for the exercise of 
market power. More commenters oppose than support RTOs imposing 
sanctions and penalties for market power abuse. Among them, Allegheny 
and Metropolitan claim that this is a proper function of regulatory or 
antitrust authorities. Central Maine argues that the Commission cannot 
grant RTOs the authority to impose corrective actions without affording 
the affected public utilities with procedural due process. EEI believes 
that the RTO tariff may include RTO authority to impose fines or 
sanctions to ensure compliance with RTO rules in accordance with the 
costs imposed by their actions. Pointing to similar positions taken by 
Justice Department and FTC, EEI contends, however, that the RTO should 
not attempt to define or prosecute alleged exercise of market power 
because it is not a regulatory body or an antitrust agency authorized 
to take such actions. It also suggests that limited additional 
authority might be granted during the transition to restructured 
markets to permit the RTO to deal effectively and timely with 
identified market design flaws, software errors, or other unanticipated 
situations that could be costly if no action is taken.
    Cinergy also argues that the RTO should not be allowed to take 
corrective action against individual market participants. It believes 
that claims of market abuse and the exercise of market power should be 
forwarded to the Commission to address consistent with its 
jurisdiction. Similarly, MidAmerican recommends that RTO penalties be 
limited to (1) willful violations of material RTO directives related to 
the operation of regional transmission facilities, Commission approved 
RTO standards for transmission facility operations, and material 
provisions of RTO agreements that conflict with the RTO transmission 
tariff, and (2) violations of RTO transmission tariff provisions 
relating to operating reserves and energy imbalances. NASUCA recommends 
that compliance with RTO rules be enforced with penalties and sanctions 
imposed through a collaborative process involving all market 
participants, regulatory agencies and consumer advocates. However, the 
Final Rule should specify that any actions taken by the RTO cannot 
substitute for penalties or other remedies which may stem from 
independent investigations by governmental authorities. Similarly, ISO-
NE and SNWA generally would impose sanctions based on a participant's 
engaging in patterns of conduct defined in the RTO's rules or its 
tariff.
    NYPP, DOE, and LG&E generally concur that RTO sanctions and 
penalties should only be levied for violations of RTO rules and 
procedures, whereas penalties and sanctions for market power abuses are 
matters for the regulatory and antitrust agencies, legislators, or the 
courts. Florida Power Corp. argues that, since an RTO does not have 
authority to grant or terminate market-based rate authorizations 
premised respectively on the absence or presence of market power, the 
RTO should therefore have no role in passing judgement or imposing 
penalties for the exercise of market power.
    On the other hand, some commenters, such as East Texas 
Cooperatives, are more comfortable with RTO imposition of penalties and 
sanctions for market power abuse. PJM recommends that RTOs be able to 
take corrective action to ameliorate market abuses or flaws and to seek 
Commission approval to add penalties and sanctions to its market 
monitoring plan. NECPUC recommends that market monitoring be expanded 
to include formalized mitigation and sanction rules in connection with 
market design, implementation flaws and market power. NY ISO claims 
that RTOs should mitigate evident market power problems, on a 
prospective basis, by applying pre-approved remedies. CRC submits that 
RTOs investigate whether market power abuse results from a design flaw 
and report the results to the Commission for approval of its mitigation 
plan. WPSC sees RTOs being effective because they will have access to 
real-time data on system conditions and should be given authority to 
take appropriate corrective action immediately to respond to market 
abuses.
    Some commenters also want sanctions against market participants for 
reliability rule violations. PSNM claims that RTOs should defer to 
existing mechanisms where they exist (such as the WSSC's Reliability 
Management System RMS, and NERC Reliability Standards and Measures) for 
sanctions against market participants for poor performance, rather than 
create new monitoring and sanction systems for RTOs. Similarly, Desert 
STAR submits that any RTO should be allowed to pass the reliability 
performance standards sanctions on to participants who do not comply. 
SMUD concurs that an important aspect of enforcing reliability 
standards is ensuring that the RTO has sufficient authority to police 
and

[[Page 904]]

investigate the markets they administer, and assess fines and other 
appropriate penalties, or resolve disputes amongst market participants 
as to any alleged market abuse.
    A few commenters also address the Commission's questions about how 
much discretion the RTO should have in setting penalties (e.g., should 
the RTO's penalty authority be limited to collecting liquidated 
damages). Nevada Commission submits that RTOs should be allowed to 
impose specific penalties and sanctions for non-compliance with RTO 
rules based on liquidated damages and not punitive damages. Cal ISO and 
Metropolitan believe that penalties should be limited to liquidated 
damages. Cal ISO argues that for cases of repeated or intentional 
violations or serious abuses of market power, the RTO should seek 
relief, including imposition of punitive damages, from the Commission 
or other appropriate agencies such as the Justice Department. 
Metropolitan argues that liquidated damages sought by an RTO should be 
approved by the Commission. And Duke opposes the RTO assuming the role 
of market monitor and enforcer; therefore, it recommends that terms and 
conditions for any penalties the RTO might impose should be agreed upon 
by contract during the RTO development process.
    On the other hand, WPSC claims that the RTO should have the 
discretion to determine the amounts of adequate sanctions and penalties 
to discourage anti-competitive conduct. Whether the RTO has acted 
properly can always be reviewed after the fact through a dispute 
resolution procedure either through the Commission or the Justice 
Department. NASUCA contends that sanctions and other penalties should 
be large enough to be an effective deterrent. It suggests that a for-
profit RTO may have incentives to impose unjustified penalties and 
should be required to allocate all revenue derived from sanctions and 
penalties in a way that benefits customers. SMUD offers that, since 
liquidated damages are a mere proxy designed to make a victim whole for 
a transgression, they do not really serve as a deterrent to market 
abusive conduct.
    Several commenters address whether the SEC model of regulating 
stock exchanges, i.e., requiring extensive and sophisticated market 
monitoring of stock exchanges, should applicable to RTO market 
monitoring. Some commenters, such as EEI and PP&L, do not believe the 
model is applicable. EEI claims that monitoring scheme in the 
securities industry is an exception because in most industries the 
market participants bring competitive problems to the attention of 
antitrust authorities. Sithe also opposes any emulation of the NASD or 
NYMEX model of self-regulation at this time because of the limited 
amount of market experience to date.
    PJM/NEPOOL Customers and Cal ISO, however, contend that the RTO 
monitoring function should be similar to that of a stock exchange 
because the RTO is designed to ensure that the exchange of electricity 
can occur readily and easily in a competitive marketplace.
    Commission Conclusion. In the NOPR, the Commission proposed that 
RTOs perform a market monitoring function. Many commenters raise a 
number of issues regarding market monitoring. The issues largely 
encompass the following concerns: the need for and scope of a market 
monitoring function; who should perform this function and how it should 
be performed; and what are the specific components or procedures of a 
market monitoring plan.
    The Commission recognizes that the market monitoring concept is new 
and not yet well-refined, either at the Commission or within existing 
ISOs. We also acknowledge the apprehensions of some parties that market 
monitoring by an RTO could intrude into markets and affect their 
behaviors. The Commission, however, is engaged in finding ways to 
understand market operations in real-time, so that it can identify and 
react to any problems that are preventing the most efficient 
operations. It also has a responsibility to protect against 
anticompetitive effects in electricity markets. \579\ If we are to 
satisfy this goal, we must systematically assess whether our policies 
and decisions are consistent with this responsibility. Market 
monitoring is an important tool for ensuring that markets within the 
region covered by an RTO do not result in wholesale transactions or 
operations that are unduly discriminatory or preferential or provide 
opportunity for the exercise of market power. In addition, market 
monitoring will provide information regarding opportunities for 
efficiency improvements.
---------------------------------------------------------------------------

    \579\ See Gulf States Utilities v. FPC, 411 U.S. 747, 758-59 
(1973).
---------------------------------------------------------------------------

    However, in light of the different forms of RTOs that could be 
developed by market participants and the varying types of markets an 
RTO may be operating within its region, different market monitoring 
plans are likely to be appropriate for different RTOs. Consequently, 
after careful consideration of the comments, the Commission will 
require that RTO proposals contain a market monitoring plan that 
identifies what the RTO participants believe are the appropriate 
monitoring activities the RTO, or an independent monitor, if 
appropriate, will perform. We believe that such approach will provide 
those proposing an RTO sufficient flexibility to design a monitoring 
plan that fits the corporate form of the RTO as well as the types of 
markets the RTO will operate or administer. We have revised the 
regulatory text for the RTO market monitoring function to reflect our 
decision to allow this flexible approach.
    Although we decline at this time to prescribe a particular market 
monitoring plan or the specific elements of such a plan, the RTO must 
propose a monitoring plan that contains certain standards. The 
monitoring plan must be designed to ensure that there is objective 
information about the markets that the RTO operates or administers and 
a vehicle to propose appropriate action regarding any opportunities for 
efficiency improvement, market design flaws, or market power identified 
by that information. The monitoring plan also must evaluate the 
behavior of market participants, including transmission owners, if any, 
in the region to determine whether their behavior adversely affects the 
ability of the RTO to provide reliable, efficient and nondiscriminatory 
transmission service. Because not all market operations in a region may 
be operated or administered by the RTO (e.g., there may be markets 
operated by unaffiliated power exchanges), the monitoring plan must 
periodically assess whether behavior in other markets in the RTO's 
region affect RTO operations and, conversely, how RTO operations affect 
the efficiency of markets operated by others. Reports on opportunities 
for efficiency improvement, market design flaws and market power abuses 
in the markets the RTO operates and administers also must be filed with 
the Commission and affected regulatory authorities.
    In developing its market monitoring plan, the RTO should identify 
the markets that will be monitored, i.e., transmission, ancillary 
services or any other market it may develop (e.g., congestion 
management). With regard to those markets, the monitoring plan should 
examine the structure of the market, compliance with market rules, 
behavior of individual market participants and the market as a whole, 
and market power and market power abuses. The monitoring plan should 
also address how information will be used and reported. The monitoring 
plan

[[Page 905]]

should indicate whether the RTO will only identify problems and/or 
abuses or whether it also will propose solutions to such problems. We 
note that sanctions and penalties may be appropriate for certain 
actions such as noncompliance with RTO rules. However, the monitoring 
plan should clearly identify any proposed sanctions or penalties and 
the specific conduct to which they would be applied, provide the 
rationale to support any sanctions, penalties or remedies (financial or 
otherwise) and explain how they would be implemented. With regard to 
the reporting of market monitoring information, the monitoring plan 
should indicate the types and frequency of reports that will be made 
and to whom the reports will be sent. Under the FPA, the Commission has 
the primary responsibility to ensure that regional wholesale 
electricity markets served by RTOs operate without market power. An 
appropriate market monitoring plan must provide an objective basis to 
observe markets and, if appropriate, provide reports and/or market 
analyses. Market monitoring also will be a useful tool to provide 
information that can be used to assess market performance. This 
information will be beneficial to many parties in government as well as 
to power market participants. This includes state commissions that 
protect the interests of retail consumers, especially where they are 
overseeing the development of a competitive electric retail market. We 
note, however, that the market monitoring function for the RTO does not 
limit the ability of each state within the RTO's region or other 
authorities to decide the nature and extent of its own market 
monitoring activities.
    We are not requiring a plan that necessarily involves the 
collection of data the RTO would not collect in its ordinary course of 
business. We believe that the information collected through the RTO 
market monitoring plan will reflect data that the RTO will collect or 
have access to in the normal course of business (e.g., bid data, 
operational information). In light of our requirements that the RTO 
have operational control over the transmission facilities transferred 
to it and the RTO be the security coordinator for its region, the RTO 
will be in the best position to perform (or provide information to 
another entity, if appropriate, for it to perform) objective monitoring 
functions for the markets that the RTO operates or administers in the 
region.
    In response to commenters' arguments that RTO market monitoring 
results in an impermissible shift of Commission authority to other 
entities, we emphasize that performance of market monitoring by RTOs is 
not intended to supplant Commission authority. Rather it will provide 
the Commission with an additional means of detecting market power 
abuses, market design flaws and opportunities for improvements in 
market efficiency. Further, because market monitoring plans will be 
required to be filed with and approved by the Commission as part of an 
RTO proposal, we will retain the ability to determine what, how and by 
whom activities will be performed in the first instance.
    Because we believe market monitoring is essential, we decline to 
set any sunset date for monitoring at this time. However, as bulk power 
markets evolve and become more competitive, we may revisit the need for 
the type of monitoring the Rule requires.
7. Planning and Expansion (Function 7)
    In the NOPR, the Commission proposed that the RTO planning and 
expansion process must satisfy certain standards. Specifically, RTOs 
would be required to: (1) Encourage market-motivated operating and 
investment actions for preventing and relieving congestion; and (2) 
accommodate efforts by state regulatory commission to create multi-
state agreements to review and approve new transmission facilities, 
coordinated with programs of existing Regional Transmission Groups 
(RTGs) where necessary. We suggested that RTOs be designed to promote 
efficient use, which requires efficient price signals such as 
congestion pricing, and efficient expansion of their regional grid, 
which requires control over planning and expansion. We specifically 
proposed that the RTO have ultimate responsibility for both 
transmission planning and expansion within its region. If the RTO is 
unable to satisfy the planning and expansion requirement when it 
commences operation, we proposed that the RTO must file a plan with 
specified milestones that will ensure that it meets this requirement no 
later than three years after initial operation. In addition, the 
Commission sought comment on whether three years is an appropriate 
amount of time for implementation of this function.\580\
---------------------------------------------------------------------------

    \580\ FERC Stats. & Regs. para. 32,541 at 33,751-53.
---------------------------------------------------------------------------

    Comments. Encourage Market-Motivated Operating and Investment 
Actions for Preventing and Relieving Congestion. Many commenters 
support the Commission's proposal to require that an RTO must ensure 
the development and operation of market mechanisms to plan and 
refinance transmission system expansion. As part of this an RTO should 
provide all transmission customers with efficient price signals that 
show the consequences for their transmission use decisions.\581\
---------------------------------------------------------------------------

    \581\ See, e.g., United Illuminating, Wyoming Commission, 
Industrial Consumers, Champion, NSP, PG&E, Williams, LG&E, FTC and 
APX.
---------------------------------------------------------------------------

    Some commenters, such as JEA and Williams believe that this role is 
best performed by for-profit entities because system expansion 
decisions must be driven by economic considerations. Entergy also 
contends that a transco will not create any bias in the method of grid 
expansion.
    Los Angeles agrees that an RTO should rely upon market signals and 
market solutions in assessing all feasible options (e.g., construction 
of new generation, redispatch of existing generation, grid expansion) 
to assure the least-cost option is pursued. NASUCA also argues that the 
Commission should mandate that RTOs use least-cost planning on a 
region-wide basis for transmission system expansions and upgrades. It 
notes that the larger the region over which least-cost planning is 
conducted, the more economically efficient the outcome is likely to be. 
If market solutions do not develop or are not timely, Los Angeles 
believes that the RTO must have the power to resolve the transmission 
problem. LG&E proposes that RTOs be permitted to use competitive 
bidding as a means to meet new transmission investment needs.
    EPA believes that RTOs should adopt a resource planning process 
with sufficient flexibility to consider non-traditional resources and 
to assign appropriate values to their unique benefits. EPA further 
believes that RTOs should be encouraged to take into account 
environmental costs and benefits that are not reflected in resource 
prices.
    Puget suggest that the Commission should recognize that the concept 
of RTOs may contain some elements that do not enhance the reliable 
operation of the transmission grid. Puget requests that the Commission 
should address more fully how it will mitigate the effects of the 
severance of generation and transmission planning and operation and how 
it plans to ensure maximum reliability at the lowest integrated costs.
    NASUCA recommends that the Commission require RTOs to develop a 
baseline regional transmission expansion plan that would identify the 
regional system's ability to meet essential NERC reliability criteria 
and

[[Page 906]]

isolate potential constraint areas of the existing system where 
upgrades may be necessary or additional generation desirable. Such a 
baseline plan could provide a valuable tool to market participants in 
signaling the best locations for new generation projects. Entergy 
proposes the use of a regional transmission plan that includes a 
regional transmission planning summit process involving all 
stakeholders.
    TAPS, however, questions whether market-based mechanisms to expand 
the transmission grid will emerge readily from an efficient short-term 
transmission pricing regime that accounts properly for the costs of 
congestion. TAPS asserts that, while efficient congestion pricing is an 
important component of a well-designed transmission regime, it is not 
the answer to the concerns that have been raised regarding the lack of 
economic and regulatory incentives to expand the transmission grid.
    Many commenters agree that RTOs should be responsible for 
conducting the studies necessary to assess the need for new 
transmission system enhancement.\582\ However, some commenters argue 
that the role of the RTO should be to facilitate market investment by 
others in new transmission and generation, not to lead the market by 
making its own plans for new facilities. For example, Seattle suggests 
that the RTO should generate information on the locations, frequencies 
and costs of congested paths to guide capital investment. It believes 
that the RTO need not make capital investments directly; rather it 
should seek market mechanisms, such as requesting bids for needed 
capacity, to encourage investments. EME states that performance of this 
role requires accurate accounting for the impact of congestion and new 
generation, and proper allocation of costs to those that require such 
costs to be incurred.
---------------------------------------------------------------------------

    \582\ See, e.g., EME and Seattle.
---------------------------------------------------------------------------

    To ensure that transmission expansion decisions are not biased, 
ComEd proposes that RTO functions be performed by two linked 
organizations that together make up a ``Binary RTO.'' ComEd envisions 
that the Binary RTO would consist of for-profit independent 
transmission companies (ITCs), each operating a large aggregation of 
existing transmission systems, under the oversight of an independent, 
not-for-profit Regional Transmission Board (RTB). The ITCs will 
identify transmission additions, upgrade opportunities, and prepare 
long-range plans which would be reviewed by the RTB and subsequently 
integrated in an RTB-wide planning system.
    Powerex believes that it is better to eliminate congestion at its 
source through facilities upgrades, if economically and environmentally 
feasible, than to attempt to manage congestion on a long-term basis 
through congestion pricing schemes.
    Many commenters support the concept that RTOs must be responsible 
for transmission planning and that single-system planning should be the 
objective of the RTO planning process.\583\ Commenters differ, however, 
on the extent of the RTO's role in the planning process. Some 
commenters, such as Powerex, argue that the RTO must have control over 
transmission service, planning, system impact studies and facilities 
studies, and the authority to determine the need for, and require the 
implementation of, transmission upgrades by member utilities. Other 
commenters, such as LIPA and H.Q. Energy Services, propose that, in the 
absence of transmission expansion proposals from current or proposed 
market participants, the RTO should have the responsibility for 
assessing whether transmission improvements are needed and, if a need 
is found, the RTO should have the authority to order such expansion.
---------------------------------------------------------------------------

    \583\ See, e.g., PNGC, Wisconsin Commission, EAL, Entergy, PJM, 
Minnesota Power and Montana-Dakota.
---------------------------------------------------------------------------

    Some commenters such as NY ISO, on the other hand, express concern 
that exclusive authority by the RTO over transmission planning is 
overly restrictive. NY ISO claims that entities which are responsible 
for coordinating transmission expansion, but which lack authority to 
make enforceable planning decisions, can nevertheless achieve the 
Commission's primary transmission expansion-related goal, i.e., 
ensuring that investments in new transmission facilities are 
coordinated to ensure a least-cost outcome that maintains or improves 
existing reliability levels.
    H.Q. Energy Services objects to NY ISO's arguments as being merely 
concerned with preserving its so-called ``two-tier'' governance system 
which provides NY ISO transmission owners with significant authority, 
or veto power, over interconnections with generating facilities and 
over decisions related to transmission system planning and expansion. 
H.Q. Energy Services does not believe that the two-tier approach is 
appropriate unless the RTO has ultimate decision-making authority.
    Many commenters agree with the proposal that an RTO must be 
ultimately responsible for all transmission expansions and 
upgrades.\584\ These commenters claim that transmission operations must 
be conducted on an independent and fair basis and must be undertaken by 
an impartial entity if transmission services are to be offered on a 
truly non-discriminatory basis. They argue that vesting the RTO with 
the ultimate responsibility for expanding transmission systems 
eliminates the conflict that is inherent in vesting these 
responsibilities with an entity that also has commercial interests that 
are competing with users of the system.
---------------------------------------------------------------------------

    \584\ See, e.g., San Francisco, SoCal Cities and CMUA.
---------------------------------------------------------------------------

    Although SMUD supports having the RTO be responsible for 
transmission planning and expansion, it cautions that, in such a 
paradigm, people that have no responsibility to the ratepayers will be 
deciding planning and expansion issues. Therefore, SMUD argues that the 
Commission needs to scrutinize the recovery of the costs of such 
expansion to ensure that such expansion decisions and costs are 
prudent, just and reasonable.
    Several commenters agree that the RTOs can and should play a 
significant role in the transmission planning and expansion 
process.\585\ Some of these commenters, such as NYPP and Mass 
Companies, however, do not believe that the Commission should require 
that RTOs have authority to order a transmission owner to modify or 
expand its transmission system. Nevada Commission believes that 
transmission owners should be allowed to assist an RTO in the 
development of grid planning criteria and could take the lead in such 
grid planning with RTOs performing more of an overview role. Professor 
Joskow states that the transmission owners, operating through a sound 
RTO/ISO transmission planning process should be expected to be the 
primary, but not necessarily the exclusive, source of network 
enhancement initiatives. WEPCO argues that transmission owners should 
be integrated into the RTO regional transmission plans where they can 
be improved and expanded to meet regional needs most efficiently. 
Turlock contends that the RTO's authority over the transmission system 
it operates must be limited to that system. Turlock argues that the RTO 
should not have the ability to force expansion of lower voltage or 
tangentially related facilities which are beyond the area of its 
responsibility, even if those other facilities might have a small but

[[Page 907]]

theoretically possible impact on the RTO's facilities.
---------------------------------------------------------------------------

    \585\ See, e.g., NYPP, Industrial Customers, Mass Companies and 
Nevada Commission.
---------------------------------------------------------------------------

    CP&L supports a coordinated planning approach which would be 
similar to the planning approaches identified in the Midwest ISO and 
the Alliance RTO filings, where the RTO would have responsibility for 
review of the transmission plan, but the individual transmission-owning 
entities would provide the necessary input to facilitate the 
development of the comprehensive RTO transmission plan. East Kentucky 
argues, however, that an individual transmission owner should be able 
either to require or to veto the building of a particular RTO facility.
    MidAmerican disagrees with the proposal that the RTO have the 
ultimate responsibility for both transmission planning and expansion in 
the region. MidAmerican claims that existing regional transmission 
groups (RTGs) have clear and prominent roles in transmission expansion 
decisions in which planning for transmission improvements are 
coordinated through collaborative processes that already involve many 
interested stakeholders in the widest fashion possible. MidAmerican 
states that throughout the MAPP region there is broad support for 
continuing transmission planning and expansion decisionmaking as a 
collaborative function and that the existing collaborative processes 
adequately accommodate RTO participation.
    Central Maine believes that RTOs/ISOs can and should play a 
significant role in the transmission planning and expansion process, 
but disagrees with the Commission's proposal to give ISOs ultimate 
responsibility for transmission planning and expansion. Central Maine 
does not object to ISOs having oversight responsibility in these area, 
but Central Maine believes that the planning and engineering functions 
should be a shared responsibility between utilities and RTO, i.e., the 
Commission should consider utility planners as a satellite to the ISO/
RTO similar to satellite function served by utility control centers in 
monitoring, switching and dispatching. Central Maine states that the 
Commission should grant individual transmission owning utilities an 
equal voice in determining the technical aspects of transmission 
planning and expansion.
    Although Big Rivers believes that, as proposed in the NOPR, the RTO 
should be the default provider of transmission planning and expansion, 
it agrees with NRECA that incumbent transmission owners should have the 
first opportunity to build required transmission system expansion with 
RTO ability to facilitate needed construction by others.
    Some commenters suggest specific tasks and functions that the RTO 
should perform or have the ability to require as part of the 
transmission planning and expansion function.\586\ For example, SRP 
proposes that at a minimum, each RTO should have the authority to: (1) 
Direct transmission owners to study and evaluate system performance and 
to develop plans to solve known reliability or adequacy problems; (2) 
revise or combine elements of transmission owners' plans to achieve the 
most efficient and reliable transmission expansion plan; (3) approve or 
reject any component of the RTO transmission plan developed by a 
transmission owner; and (4) approve facility additions by third 
parties.
---------------------------------------------------------------------------

    \586\ See, e.g., Project Groups, LIPA and SRP.
---------------------------------------------------------------------------

    Accommodate Efforts by State Regulatory Commission to Create Multi-
State Agreements to Review and Approve New Transmission Facilities. 
Many comments concur that multi-state agreements are to be encouraged 
and that the RTO should be designed to work within that structure.\587\ 
Commenters, including NSP and Nevada Commission, encourage the 
Commission to provide an active role for RTOs to participate with state 
and local government in the siting and licensing of new facilities. PJM 
states that a cooperative relationship between RTOs and the states is 
essential to effective transmission expansion planning. In PJM's view, 
states are more likely to trust the planning decisions of RTOs that 
have no commercial interest in transmission and generation expansion 
than decisions made by transmission-owning entities, which have 
commercial interests.
---------------------------------------------------------------------------

    \587\ See, e.g., Illinois Commission, DOE and New Smyrna Beach.
---------------------------------------------------------------------------

    Cinergy recommends that the final rule include a Commission 
commitment to proceed aggressively to establish a forum to encourage 
coordination of RTO planning and expansion among states through multi-
state certification agreements and multi-state regional planning 
boards. Cinergy notes, however, that the creation of a forum or agency 
to review grid planning and expansion that would consider the public 
interest beyond the constraints of state boundaries may require federal 
legislation. If so, the Commission should be aggressive in its dialogue 
with Congress to obtain the requisite legislative relief.
    The Kentucky Commission suggests creating a voluntary ``Joint Board 
on Regional Transmission Siting'' to develop and review standards for 
transmission expansion. The Joint Board would include participation 
from the Commission, state commissions, RTOs, and other interested 
parties. The Joint Board would also convene ad hoc committees to review 
specific transmission expansion proposals. Pennsylvania Commission also 
prefers a joint Federal-state approach towards regulating RTO site 
approvals, expansion, innovation and customer service. It notes that a 
joint Federal-state approach has been used with success in other areas, 
such as the Susquehanna River Basin Commission, the Delaware River 
Basin Commission and the Joint Pipeline Office which regulates the 
Trans-Alaska Pipeline System.
    Illinois Commission recommends that accommodation of multi-state 
efforts be expanded to include the possibility of multi-state regional 
regulatory oversight organizations. Such organizations could be 
instrumental in coordinating regional solutions to regulatory and 
policy issues.
    Otter Tail expresses concern that multi-state agreements may not 
actually add to the efficient use and expansion of the interstate 
transmission system due to a danger that these types of agreements 
could be mired in state-versus-state political conflict and become 
unworkable, to the detriment of transmission owners, generators, and 
ultimately customers. Industrial Consumers also does not believe that 
requiring an accommodation with ``multi-state agreements'' is 
necessarily productive. It states that nothing now prevents such 
coordination among states, yet there is no obvious evidence that this 
will work. Industrial Customers believes that states will always 
reserve the right to veto a project that may be partially situated 
within their jurisdiction, regardless of the benefits elsewhere.
    East Texas Cooperatives believes that retention of state public 
utility commission authority over siting (and other necessary 
approvals) is necessary to control the risk of overbuilding because 
RTOs will have no real incentive to limit facility construction.
    Commenters generally express support for the proposal that the RTO 
build on existing RTG processes.\588\ For example, Industrial Consumers 
urges that the Commission require existing RTGs to merge their 
functions with the RTOs because RTGs should not be allowed to develop 
an institutional

[[Page 908]]

culture that diverges from the goals and objectives of RTOs.
---------------------------------------------------------------------------

    \588\ See, e.g., Wisconsin Commission, Industrial Customers and 
SRP.
---------------------------------------------------------------------------

    New Smyrna Beach and Oneok claim that market participants will 
undoubtedly benefit from a multi-state siting process for transmission 
because it may make siting of new generation easier if there is more 
certainty that related transmission siting decisions will be made on a 
timely basis with one-stop shopping.
    Several commenters address the role of the Commission in the RTO 
planning and expansion process. Detroit Edison and Wolverine 
Cooperative support the establishment of the Commission as the primary 
channel of certification for transmission siting, construction, and 
expansion. Detroit Edison states that regional reliability 
organizations and the RTOs in each reliability region should be 
permitted to determine necessary changes and additions in transmission 
with input from transmission owners, control area operators, and other 
interested parties. It is vital, it states, that a single 
administrative agency resolve issues related to the siting of 
transmission facilities on a regional basis and have the authority to 
approve transmission expansion plans on a timely basis. Detroit Edison 
believes that the Commission should fill the important role of sole 
regulator over transmission siting and construction, just as it 
currently does in approving the siting and construction of natural gas 
pipelines, and it urges the Commission to work to gain such authority.
    Pennsylvania Commission recommends that, if an RTO determines that 
transmission expansion is necessary, it should file with the Commission 
to demonstrate that need. Once the Commission determines a need exists 
within the RTO, the RTO should then file with the appropriate states 
for a determination of the siting issues. Pennsylvania Commission 
believes that vesting authority for determining the need for 
transmission expansion with the Commission solves several problems that 
are certain to arise in state forums. Federal determination of the need 
for transmission expansion obviates the burden of filing with multiple 
jurisdictions and possibly receiving conflicting determinations.
    Otter Tail states that Commission should seriously consider whether 
the public interest would be better served through adoption of a 
transmission siting policy that is similar to review of interstate 
natural gas pipelines.
    NY ISO claims that in many cases transmission expansion is delayed 
or blocked entirely by environmental and other transmission siting 
regulations. Nevertheless, NY ISO supports the NOPR's proposal that 
RTOs participate in efforts to create multi-state transmission 
expansion agreements.
    East Kentucky believes that there needs to be some regulatory 
oversight authority for facilities that are deemed necessary by an RTO 
planning staff. East Kentucky proposes that this regulatory authority 
be the Commission or a regional regulatory authority.
    Conlon recommends that the Commission have the necessary authority 
to enforce reasonable siting request, or critically needed future 
transmission lines could be delayed causing a reliability risk. 
Granting the right of eminent domain to transcos or ISOs in Federal 
legislation would be another approach. This could be accomplished by 
the Commission recommending to Congress that it have the right of 
eminent domain.
    LG&E believes that it is important that state authority over system 
expansion not impede necessary improvements that enhance the efficiency 
of the regional grid that is, or will be, subject to RTO control. 
Ultimately there may be a need for a congressional solution to the 
current balkanized system for authorizing grid expansion. In its 
comments, the East Central Area Reliability Council explicitly calls 
for such legislative action based on its concern that transmission 
facility expansion requests will fail as they become bogged down in 
multiple state reviews. LG&E shares this concern. Still, until such 
time as the statutory framework for transmission expansion is amended, 
LG&E believes that RTOs represent an opportunity for coordinating 
regional transmission expansion needs among transmission owners and 
state authorities.
    Project Groups maintains that RTOs should be required to coordinate 
and lead in the development of comprehensive least cost regional plans 
for assuring short-and long-term system reliability, and they must 
coordinate the actions necessary for implementing timely system 
upgrades and additions pursuant to those plans. For example, RTOs must 
be given the authority to petition state and local regulators for 
necessary siting authorizations, including certificates of need or 
public necessity and environmental permits, as well as the authority to 
order construction of facilities sited and permitted under state 
regulatory authorities. The Commission should encourage state reliance 
on RTO-approved plans as the primary basis for the exercise of eminent 
domain powers under state law.
    Puget notes that state condemnation powers granted to utilities are 
usually limited for the benefit of the citizens of the state in which 
the utility operates. It is not clear that a state utility can delegate 
its state condemnation power to a regional RTO. Therefore, the final 
rule should expressly address how state condemnation authority can be 
legally exercised by a regional RTO.
    NASUCA maintains that the RTO regional planning efforts must not 
displace state government siting authority. NASUCA states that the 
final rule should specifically recognize state statutory authority to 
regulate siting of transmission facilities. For other planning and 
expansion matters, the Commission should require RTOs to establish a 
process to ensure that the RTO obtains input from state government 
agencies with respect to the regional transmission plan. Nevada 
Commission states that it is imperative that the RTO coordinate 
transmission siting and planning with state agencies. Tri State 
believes that states should continue to fulfill their traditional roles 
in siting transmission facilities. However, it notes that it may be 
necessary for the states to consult with the RTO on transmission 
facility certification since the RTO will be charged with overall 
responsibility for transmission planning and will be required to work 
cooperatively with states and other regional groups.
    CP&L supports state and local governments retaining the authority 
for certification and siting of new transmission facilities. These 
government agencies are closer to the local residents who will be 
affected and can best evaluate the great number of factors that must be 
considered in approving transmission routes.
    Several commenters address the issue of eminent domain authority as 
a component of the transmission planning and expansion function. East 
Kentucky believes that the issue of eminent domain needs to be 
addressed for not only RTOs, but also for the entire open access 
transmission network. East Kentucky questions whether an entity, if 
required by an RTO or the Commission to construct a transmission 
facility, has eminent domain authority that is sufficient to allow the 
entity to acquire all property rights necessary to construct the 
required facility. Consequently, East Kentucky argues that, as a 
general proposition, Congress needs to grant federal eminent domain 
authority to any entity that is required by the Commission or any form 
of RTO to build a facility so that such entity can acquire private 
property rights under Federal law. Because it believes that siting of 
transmission has become the principal impediment to transmission

[[Page 909]]

expansion, EPSA also advocates that the RTO should be delegated 
sufficient authority to direct transmission owners or others to excise 
their eminent domain authority, as necessary, to implement transmission 
system expansion plans independent of the source of funds or the 
beneficiary of the project. Under current law, this authority must come 
from the states. Thus, EPSA also advocates the passage of Federal 
legislation that vests the Commission with primary jurisdiction over 
major transmission planning and siting decisions, perhaps subject to a 
requirement that the Commission consult with a regional siting 
authority or a consortium of affected state siting boards.
    Central Maine disagrees and recommends that the Commission should 
reject EPSA's comments. Central Maine notes that, if a state government 
intends that an RTO have the power of eminent domain, the state 
legislature will grant it. Central Maine argues that RTOs should not be 
granted the power to do something indirectly that they may not do 
directly. Consequently, it believes that EPSA must pursue its proposal 
through the enactment of state legislation.
    Whether Three Years Is an Appropriate Amount of Time for 
Implementation of This Function. Several commenters support the 
Commission's proposal to allow up to three years to implement the 
planning and expansion function.\589\ Some commenters, however, believe 
that three years is too short.\590\ South Carolina Authority suggests a 
five-year period. Florida Commission believes that it is premature to 
set any time limit for implementation of the planning and expansion 
function.
---------------------------------------------------------------------------

    \589\ See, e.g., Tri State, SoCal Edison and PNM.
    \590\ See, e.g., NECPUC, Duke and South Carolina Authority.
---------------------------------------------------------------------------

    On the other hand, several commenters believe that three years is 
too long a period.\591\ Most of these commenters believe that the 
planning and expansion is such an important function that its 
implementation should not be delayed at all. NYC suggests that 
implementation should not be delayed more than a year. SRP argues that 
the uncertainty that currently exists about who ultimately will be 
responsible for building and paying for new transmission facilities is 
causing delays in upgrades. According to SRP, requiring the RTO to 
perform this function upon commercial operation will eliminate this 
uncertainty. Industrial Customers also argues that any delay should not 
be used as an excuse to stall the construction of any facility for 
which the need has been established. SRP suggests that, if a delay in 
implementation is permitted, the RTO should be required to identify the 
entity responsible for financing and building transmission expansion 
prior to the RTO assuming such responsibility.
---------------------------------------------------------------------------

    \591\ See, e.g., Champion, NYC, Turlock, SRP, TDU Systems and 
Industrial Customers.
---------------------------------------------------------------------------

    Commission Conclusion. We reaffirm the NOPR proposal that the RTO 
must have ultimate responsibility for both transmission planning and 
expansion within its region that will enable it to provide efficient, 
reliable and non-discriminatory service and coordinate such efforts 
with the appropriate state authorities. In carrying out this overall 
responsibility, the Commission has concluded that the NOPR's three 
separate requirements for RTO planning and expansion must also be 
satisfied or, in the alternative, the RTO must demonstrate that an 
alternative proposal is consistent with or superior to these three 
requirements. Specifically, an RTO must satisfy the requirement to: (1) 
Encourage market-motivated operating and investment actions for 
preventing and relieving congestion; (2) accommodate efforts by state 
regulatory commissions to create multi-state agreements to review and 
approve new transmission facilities, coordinated with programs of 
existing Regional Transmission Groups (RTGs) where necessary; and (3) 
file a plan with the Commission with specified milestones that will 
ensure that it meets the overall planning and expansion requirement no 
later than three years after initial operation, if the RTO is unable to 
satisfy this requirement when it commences operation.
    As noted above, the RTO should have ultimate responsibility for 
both transmission planning and expansion within its region. The 
rationale for this requirement is that a single entity must coordinate 
these actions to ensure a least cost outcome that maintains or improves 
existing reliability levels. In the absence of a single entity 
performing these functions, there is a danger that separate 
transmission investments will work at cross-purposes and possibly even 
hurt reliability. We also recognize that the RTO's implementation of 
this general standard requires addressing many specific design 
questions, including who decides which projects should be built and how 
the costs and benefits of the project should be allocated.\592\ As with 
other requirements of the Final Rule, we propose to give RTOs 
considerable flexibility in designing a planning and expansion process 
that works best for its region. It is both inevitable and desirable 
that the specific features of this process ``should take account of and 
accommodate existing institutions and physical characteristics of the 
region.'' \593\ We emphasize that, as the transmission provider in the 
region, the RTO is required to provide service under a tariff that is 
consistent with or superior to the Commission's pro forma tariff, and 
that tariff obligates the transmission provider to expand and modify 
its system to provide the services requested under the pro forma 
tariff.\594\ Because an RTO may not own all of the facilities it 
operates, we clarify that nothing in this Rule relieves any public 
utility of its existing obligation under the pro forma transmission 
tariff to expand or upgrade its transmission system upon request. 
Accordingly, we shall evaluate each RTO proposal to ensure that the RTO 
can direct or arrange for the construction of expansion projects that 
are needed to ensure reliable transmission services.\595\ However, the 
Commission reiterates, as discussed below, its strong preference for 
market-motivated operating and investment actions.
---------------------------------------------------------------------------

    \592\ FERC Stats. and Regs. para. 32,541 at 33,751-52.
    \593\ Id. at 33,752.
    \594\ See, e.g., Section 15.4 of the pro forma tariff which 
requires the transmission provider to use due diligence to expand or 
modify its transmission system to provide requested services. Also, 
Section 28.2 of the pro forma tariff requires the transmission 
provider to plan, construct, operate and maintain its transmission 
system in order to provide network service, and to endeavor to 
construct and place into service sufficient transmission capacity to 
deliver network resources to network customers on a basis comparable 
to its own use of the transmission system.
    \595\ We note that existing ISOs have addressed similar issues 
successfully. For example, the PJM ISO is responsible for expansion 
planning, but the transmission owners remain obligated to undertake 
upgrades necessitated by the plan, 81 FERC para. 61,257 at 62,275 
(1997).
---------------------------------------------------------------------------

    We further note that the pricing mechanisms and actions used by the 
RTO as part of its transmission planning and expansion program should 
be compatible with the pricing signals for shorter-term solutions to 
transmission constraints (i.e., congestion management) so that market 
participants can choose the least-cost response. Otherwise, their 
choices may reflect less efficient outcomes for the marketplace. For 
example, if the price of expansion overstates its cost (or the price of 
congestion management understates actual congestion cost), market 
participants likely will continue congestion management solutions to a 
transmission constraint when

[[Page 910]]

expanding the system to relieve congestion is more efficient.
    Market-Motivated Actions. Planning new generation or new 
transmission requires a coordinated approach to ensure reliability and 
efficient congestion management. However, this does not necessarily 
imply that all transmission expansions must be centrally planned by the 
RTO. Where feasible, an RTO should encourage market approaches to 
relieving congestion. A market approach will require providing all 
transmission customers with access to well-defined transmission rights 
and efficient price signals that show the consequences of their 
transmission usage decision. If the RTO's market approach is 
successful, the decisions of where, when and how to relieve congestion 
will be driven by economic considerations.
    Most commenters agree with the NOPR proposal that RTOs should rely 
upon market signals and market solutions in assessing all feasible 
options (e.g., construction of new generation, redispatch of existing 
generation, as well as expansion of the transmission grid) to assure 
that the least costly option is pursued. If an RTO can facilitate 
market-motivated decisions, several commenters point out that its 
planning role may largely be limited to extreme circumstances where 
continuing congestion in an area threatens reliability. However, we 
also recognize that different market approaches to relieving congestion 
are still in the early stages of development. Similarly, while market 
approaches to expansion are the subject of much discussion, they are 
also in the early stages of development.\596\ It is not the intent of 
the Commission either to mandate a market approach to the exclusion of 
an executive decision by the RTO or to mandate any particular market 
approach.
---------------------------------------------------------------------------

    \596\ For example, TDU Systems and other commenters suggest 
that, by promoting competition for new construction, the RTO can 
minimize construction cost and also reduce its own risk profile. For 
example, an ISO in Victoria, Australia (VPX), which operates, but 
does not own transmission assets, uses competitive bidding for new 
transmission facilities. At the Regional ISO Conference in Richmond, 
Virginia on June 8, 1998, Raymond Coxe described how VPX's strategy 
resulted in a number of bidders competing for the right to build, 
own and operate new facilities. He concluded that the ``result of 
this competition was a lower price to the consumers of Victoria than 
would have resulted from regulated transmission service by the 
largest incumbent provider.'' Transcript at 86, Docket PL98-5-006.
---------------------------------------------------------------------------

    Nevertheless, if any market-driven approach is to be successful, 
there must be accurate price signals that reflect the costs of 
congestion and expansion costs. As we stated in the NOPR, accurate 
price signals are the link between current usage and future expansion. 
Therefore, as discussed in more detail in Section III.E.2 Congestion 
Management, every RTO must establish a system of congestion management 
that establishes clear rights to transmission facilities and provides 
market participants with price signals that reflect congestion and 
expansion costs. In implementing its planning and expansion 
responsibility, an RTO must ensure that its decisions are not unduly 
discriminatory and produce efficient outcomes.
    The Commission reaffirms its statement in the NOPR that independent 
governance of the RTO is a necessary condition for nondiscriminatory 
and efficient planning and expansion. While accurate price signals can 
signal the need for expansion, such expansion may not be achieved if an 
RTO operates under a faulty governance system (e.g., a governance 
system that allows market participants to block expansions that will 
harm their commercial interests).
    Multi-State Agreements and RTGs. The final rule fully recognizes 
the statutory authority of the states to regulate siting of 
transmission facilities. Currently, state and local governments and 
regulatory agencies have exclusive authority over the siting process. 
Therefore, an RTO's planning and expansion process must be designed to 
be consistent with these state and local responsibilities.
    RTOs must accommodate efforts by state regulatory commissions to 
create multi-state agreements to review and approve new transmission 
facilities. The Commission encourages the development of multi-state 
agreements or compacts to review and approve new transmission 
facilities. This would expedite transmission construction and eliminate 
duplicative (and possibly conflicting) reviews by multiple states. To 
facilitate any voluntary actions taken by our state colleagues, we will 
require that the RTO planning and coordination system must be able to 
accommodate the possible emergence of new regional regulatory systems.
    Existing RTGs have clear and prominent roles in transmission 
expansion decisions in which planning for transmission improvements are 
coordinated through collaborative processes. To avoid duplicative 
efforts, the RTO process must build on existing RTG planning processes. 
Over time, since the RTO will have ultimate responsibility for planning 
the entire transmission system within its region, we expect that the 
functions of an RTG will be assumed by an RTO to avoid unnecessary 
duplication of effort.
    Three-Year Implementation. If the RTO is unable to satisfy the 
planning and expansion function when it commences operation, it must 
file a plan with the Commission with specified milestones that will 
ensure that it meets this requirement no later than three years after 
initial operation. Recognizing that the planning and expansion function 
may require coordination among multiple parties and regulatory 
jurisdictions, we do not require this function to be in place at the 
initial operation of the RTO. We continue to believe that three years 
is a reasonable deadline for creating an operational planning and 
expansion system. Therefore, we will not extend this deadline or the 
requirement to file a plan with the Commission with an implementation 
timetable. This time period could be affected by the RTO's scope, the 
number of states and market participants, and implementation costs; 
however, the urgent needs of the electricity markets make us 
disinclined to extend these deadlines.
    However, the delay should not stall the construction of new or 
enhanced facilities for which needs have been established, unless the 
RTO makes a positive decision that the facility is not in the best 
interests of the region. Delaying transmission expansion could result 
in significant market inefficiencies as well as unacceptable risks to 
reliability given the long regulatory and construction lead times 
required to build new facilities.
8. Interregional Coordination (Function 8)
    In Order No. 888, the Commission identified eleven principles it 
would use to assess Independent System Operator (ISO) proposals 
submitted to the Commission.\597\ One of these principles required that 
the ISO develop mechanisms to coordinate with neighboring control areas 
to ensure reliability and the provision of transmission services that 
cross system boundaries. The RTO NOPR encouraged transmission entities 
to consider ways to reduce impediments to transactions among 
themselves,\598\ but a coordination requirement was not included 
explicitly in the RTO NOPR. Several commenters pointed out that there 
was no explicit coordination requirement proposed in the RTO NOPR and 
recommended including a function for RTOs similar to the coordination 
principle in Order No. 888.
---------------------------------------------------------------------------

    \597\ Order No. 888, FERC Stats. and Regs. para. 31,036 at 
31,730-32.
    \598\ FERC Stats. and Regs. para. 32,541 at 33,758.

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[[Page 911]]

    Comments. Several commenters identify coordination with other 
regions as a necessary element that should be added more explicitly to 
the RTO functions.\599\ These commenters express this need as either 
required to ensure reliability or necessary for bulk power markets to 
operate over sufficiently large areas. For example, NERC states that 
the need for such coordination effort has increased as the management 
of short-term reliability of the interconnected bulk power system and 
the operation of increasingly competitive bulk power markets have 
become inseparable. Accordingly, NERC recommends that an additional 
function be added to the final rule that requires RTOs to integrate 
their market interface practices and reliability practices. It 
identifies OASIS standards, information sharing with neighboring RTOs, 
ancillary services requirements, parallel path flows, transmission 
loading relief, and interregional congestion management, as practices 
and standards that need to be integrated.
---------------------------------------------------------------------------

    \599\ Many parties supported this requirement including NERC, 
Justice Department, NARUC, NASUCA, Oneok, PJM, Duquesne and 
Industrial Consumers.
---------------------------------------------------------------------------

    Duquesne states that efficiencies can be realized from coordinating 
and developing a seamless marketplace. It recommends that the 
Commission require RTOs to coordinate and plan for seamless and uniform 
transmission rules, scheduling systems and procedures, and reliability 
standards. In addition, Oneok suggests that the Commission encourage 
neighboring RTOs to form reliability compacts under which loop flow and 
other issues involving interregional reliability impacts can be 
resolved.\600\ Also, Wyoming Commission believes that the Commission 
should be flexible with respect to inter-RTO interaction and that it 
may be appropriate to address these issues later rather than in initial 
RTO filings.
---------------------------------------------------------------------------

    \600\ ISO-NE, NY ISO and PJM recently signed a memorandum of 
understanding concerning interregional coordination activities.
---------------------------------------------------------------------------

    Commission Conclusion. Coordination of activities among regions is 
a significant element in maintaining a reliable bulk transmission 
system and for the development of competitive markets. In the NOPR, we 
discussed several region-to-region coordination activities in 
connection with the parallel path, congestion management, and expansion 
planning functions. However, the comments persuade us to add a more 
general interregional coordination requirement as one of the minimum 
RTO functions.

    We will require an RTO to develop mechanisms to coordinate its 
activities with other regions whether or not an RTO yet exists in these 
other regions.\601\ If it is not possible to set forth the coordination 
mechanisms at the time an RTO application is filed, the RTO applicant 
must propose reporting requirements, including a schedule, for itself 
to provide follow-up details as to how it is meeting the coordination 
requirements of this function. We expect the RTO to work closely with 
other regions to address interregional problems and problems at the 
``seams'' between the RTOs. Therefore, as recommended by NERC and 
others, we will add the following regulatory text to our RTO Final Rule 
functions:
---------------------------------------------------------------------------

    \601\ This is similar to the existing ISO Principle #10 in Order 
No. 888 for single control area ISOs: ``An ISO should develop 
mechanisms to coordinate with neighboring control areas.''

    (8) Interregional Coordination: The Regional Transmission 
Organization must ensure the integration of reliability practices 
within an interconnection and market interface practices among 
---------------------------------------------------------------------------
regions.

    An RTO proposal must explain how the RTO will ensure the 
integration of reliability and market interface practices. An RTO may 
ensure the integration of these practices either by developing 
integration practices itself or by cooperating in the development of 
integrated practices with an independent entity that covers all regions 
or, for reliability practices, covers an entire interconnection. The 
term, interconnection,\602\ refers here to any one of three large U.S. 
transmission systems. The Eastern Interconnection covers most of the 
area east of the Rocky Mountains in the United States and Canada. The 
Western Interconnection covers an area that is mostly west of the Rocky 
Mountains in the United States and Canada, as well as a small portion 
of Mexico. The Electric Reliability Council of Texas (ERCOT) 
Interconnection covers much of Texas.
---------------------------------------------------------------------------

    \602\ ``Interconnection'' is a term used by the North American 
Electric Reliability Council and others to refer to an 
interconnected alternating current transmission system. Engineering 
considerations require all generators connected to any one 
interconnection to operate in a coordinated manner, that is, 
synchronously.
---------------------------------------------------------------------------

    This provision does not mean that all RTOs necessarily must have a 
uniform practice, but that RTO reliability and market interface 
practices must be compatible with each other, especially at the 
``seams.'' RTOs must coordinate their practices with neighboring 
regions to ensure that market activity is not limited because of 
different regional practices.
    We understand, as NERC pointed out in its comments, that the 
reliability and market interface practices are becoming highly 
interrelated. The reliability practices affect how markets interface 
with each other, and the market interface practices affect reliability. 
For example, TLR and congestion management are both used to unload an 
overloaded transmission interface, and these two practices must work 
together. We consider congestion management and TLR are best used as 
sequential steps to unload a line, with congestion management used 
first to unload a line in a market-oriented manner, and TLR used to 
unload a line in a fair manner when either congestion management is 
unavailable or an emergency condition requires immediate action. We 
therefore list below TLR as a reliability practice and congestion 
management as a market interface practice, understanding that these and 
other practices listed affect both reliability and markets.
    The integration of reliability practices involves procedures for 
coordination of reliability practices and sharing of reliability data 
among regions in an interconnection, including procedures that address 
parallel path flows, ancillary service standards, transmission loading 
relief procedures, among other reliability-related coordination 
requirements in this Final Rule.
    The integration of market interface practices involves developing 
some level of standardization of inter-regional market standards and 
practices, including the coordination and sharing of data necessary for 
calculation of TTC and ATC, transmission reservation practices, 
scheduling practices, and congestion management procedures, as well as 
other market coordination requirements covered elsewhere in this Final 
Rule.

F. Open Architecture

    In the NOPR, the Commission stated its commitment to a policy of 
``open architecture'' and proposed to require that RTOs be designed so 
that they can evolve over time. The Commission noted that there should 
be no provision in any RTO proposal that precludes the RTO and its 
members from improving their organization to meet market needs.\603\ 
The Commission sought comments regarding the open architecture policy 
in general and the flexibility needs of RTOs in particular.
---------------------------------------------------------------------------

    \603\ FERC Stats. and Regs. para. 32,541 at 33,753.
---------------------------------------------------------------------------

    Comments. Virtually all commenters support the NOPR's open 
architecture concept and recommend that an RTO have the ability to 
evolve over time as

[[Page 912]]

it gains operating experience.\604\ They endorse the principle of 
flexibility to accommodate the changing needs of the market.\605\ WEPCO 
notes that open architecture should permit flexibility and urges the 
Commission not to require an RTO to be the only control area operator 
in the region.\606\ Ontario Power states that the open architecture 
policy should enable RTOs to accommodate Canadian entities in the 
future. Oglethorpe observes that open architecture policy would allow 
RTOs to utilize existing infrastructure and avoid high transition 
costs.
---------------------------------------------------------------------------

    \604\ See, e.g., APX, Arizona Commission, Cal ISO, Central 
Maine, Consumers Energy, CP&L, Conectiv, Desert STAR, DOE, Duke, 
Entergy, EPSA, FirstEnergy, Florida Commission, Georgia 
Transmission, Illinois Commission, Industrial Consumers, LG&E, NERC, 
NPCC, NSP, NU, NY ISO, Oglethorpe, PJM, Seattle, Southern Company, 
SMUD, SRP, TDU Systems, TEP, Tri-State and WEPCO.
    \605\ NSP states that the configuration of electric markets will 
be much different five or ten years from now.
    \606\ WEPCO notes that costs savings associated with creating 
large, efficient electricity markets will dwarf the savings attained 
by reducing the number of operators through control area 
consolidation.
---------------------------------------------------------------------------

    However, Central Maine and Southern Company argue that the 
flexibility implied by open architecture should not be used carte 
blanche. For example, there should be limits to an RTO's evolution 
process because transmission owners have some fundamental rights, such 
as: (1) The right to terminate their participation in the RTO; (2) the 
right to switch to another RTO; (3) the right to merge RTOs; (4) the 
right to recover their costs and a return on investment; and (5) the 
right to protect their assets and employees from damages and injuries.
    LG&E states that the flexibility inherent in the open architecture 
concept should be applied fairly to all market participants, including 
those transmission owners that have already committed to existing or 
proposed ISOs. For example, a member of an existing ISO should be 
allowed to move to another RTO.
    Industrial Consumers perceives a potential downside to the open 
architecture policy in that it may give existing IOUs a license to 
continue their opportunistic behavior rather than facilitating true 
market transformation. Therefore, Industrial Consumers argues that it 
supports the notion of flexibility inherent in the open architecture 
policy only in the absence of market power. Illinois Commission argues 
that the pace of evolutionary improvement of RTOs should not remain in 
the hands of vertically integrated utilities because their interest in 
structural change may not be consistent with the public interest.
    Cinergy, EPSA and Georgia Transmission state that the flexibility 
implied by open architecture should not be used to support deviations 
from minimum characteristics and functions. However, CP&L believes that 
the proposed minimum characteristics and functions are too stringent 
and do not allow for much flexibility that a changing market 
needs.\607\ Georgia Transmission supports the Commission's commitment 
to providing regulatory flexibility to allow RTOs to evolve.
---------------------------------------------------------------------------

    \607\ CP&L and Southern Company state that the Commission should 
establish basic RTO guidelines through a policy statement rather 
than by a rule. They contend that the rules under the NOPR are too 
prescriptive, and will stifle the development of new RTOs.
---------------------------------------------------------------------------

    Many commenters state that the open architecture concept is so 
broad that it will prevent stakeholders from developing meaningful RTO 
proposals. To bring some certainty to the negotiating parties to an RTO 
proposal, CP&L recommends that the Commission find that some necessary 
and reasonable limitations on modifications to RTOs are permissible, 
and these can be overridden only by unanimous consent or a 
supermajority vote.\608\ MidAmerican states that the Commission should 
accept RTO proposals that contain stated limitations, such as a 
transmission owner's right to withdraw from an RTO. MidAmerican argues 
that such limitations are consistent with the Commission's open 
architecture policy and would prevent transmission owners from being 
discouraged to join RTOs. To promote certainty, Entergy notes that the 
Commission should establish a general policy of grandfathering 
previously approved RTOs and not altering their requirements except in 
extraordinary circumstances.\609\
---------------------------------------------------------------------------

    \608\ CP&L notes that participants in Midwest ISO identified 
certain conditions that could be altered only by the transmission 
owners, including revenue distribution, pricing methodology and 
withdrawal rights.
    \609\ Entergy at 42.
---------------------------------------------------------------------------

    Southern Company is concerned that RTOs could evolve in ways that 
are undesirable to the participants that initiated its formation. 
Therefore, it argues that the parties should have some assurance that 
certain key provisions of an RTO would not change in the name of RTO 
evolution. For example, functions, boundaries, transmission rate 
design, and allocation of transmission revenues should not be amended 
by the RTO except by vote of the transmission owners, at least for the 
duration of a specified transition period. Southern Company contends 
that the transmission owners will then know what they are ``getting 
into'' when they join an RTO.
    Many commenters recommend that the Commission should not mandate 
the ultimate organizational form of the RTO given the electric 
industry's current state of structural flux and the uncertainty of the 
future. These commenters argue that the Commission's open architecture 
policy should encourage market participants to develop transmission 
institutions that are effective in meeting the needs of the 
marketplace. FirstEnergy and NU state that there is a range of 
organizational and functional forms--power pool (tight and loose): 
gridco, transco, marketco--which can accomplish the Commission's goal 
of improving the efficiency of the transmission grid, and only time and 
market forces should determine which form is best suited for a specific 
region of the country. Southern Company believes that there should be 
no requirement that would prohibit an RTO with no transmission 
ownership to transform into one that owns transmission (i.e., change 
from an ISO to a transco).
    PJM urges the Commission to clarify that RTOs can propose 
improvements to the RTO independently of its members to meet changing 
market needs. PSE&G is opposed to giving such authority to RTOs because 
it believes that the market participants rather than RTOs should drive 
changes in the structure and operation of electric markets.\610\ Cal 
ISO recommends that the Commission's open architecture policy should 
support the creation of a structure that facilitates the addition of 
new participants, both within and outside of the existing RTO 
boundaries. Illinois Commission urges the Commission to modify the 
proposed paragraph 35.34(k) of proposed regulations to include an 
affirmative expectation that RTOs will change to meet new competitive 
market needs and to improve over time.
---------------------------------------------------------------------------

    \610\ PSE&G Reply Comments at 6-7.
---------------------------------------------------------------------------

    Commission Conclusion. As proposed in the NOPR, we adopt the 
principle of open architecture in order that the RTO and its members 
have the flexibility to improve their organizations in the future in 
terms of structure, geographic scope, market support and operations to 
meet market needs. We will require that the RTO design have the ability 
to evolve over time. In addition, we will provide flexibility to allow 
RTOs to propose changes to their enabling agreements to meet changing 
market, organization and policy needs.

[[Page 913]]

    Open architecture will permit RTOs to evolve in several ways, as 
long as proposed changes continue to satisfy RTO minimum 
characteristics and functions. As a first example, open architecture 
will allow basic changes in the organizational form of the RTO to 
reflect changes in facility ownership and revised corporate strategies. 
As noted by Southern Company, an RTO that initially does not own any 
transmission facilities might acquire ownership of some or all of those 
facilities. With an open architecture design, the RTO's enabling 
agreements should anticipate and facilitate changes of this nature.
    Second, open architecture design accommodates change in the 
geographical scope of RTOs. Electric markets are evolving quickly and 
future market trading patterns cannot be foreseen at the time of RTO 
organization. An open architecture design will enable an RTO to grow 
geographically and possibly merge with another RTO as changes in 
markets suggest a realignment of organizations to meet evolving market 
needs.
    Third, market support is another area that benefits from open 
architecture design. For example, an RTO may not initially operate a PX 
to support a regional spot market, but later determine that the 
establishment of a PX would provide additional benefit in its region. 
With open architecture, the RTO can propose to add a PX function (or a 
PX monitoring function) to its design. Open architecture design ensures 
that such future developments that are beneficial to the marketplace 
are not foreclosed.
    Fourth, open architecture design accommodates changing operational 
needs. Most commenters agree that, as RTOs gain operating experience, 
some changes will become necessary. Cal ISO acknowledges that it had to 
make significant changes to its tariff and operational practices as it 
gained operating experience, and it believes further modifications are 
likely to be identified as additional experience is gained regarding 
evolving competitive markets.
    Finally, as noted in the NOPR, technological change make changes in 
RTO design inevitable and desirable. Accommodating that change will 
require flexibility and adaptability in the RTO organization; open 
architecture will permit design modification to keep pace with 
technology.
    Some commenters argue that the flexibility implied by open 
architecture design should not be interpreted to mean unfettered 
ability on the part of the RTO to modify its structure or processes. We 
agree. Although under our open architecture policy the RTO will have 
the ability to propose whatever changes it believes are appropriate to 
meet the evolving needs of the RTO and the region, any such 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. The Commission will 
consider the merits of any changes to an approved RTO on a case-by-case 
basis. Interested parties will have the opportunity to comment on any 
such proposal. This process will enable all parties and the Commission 
to guard against proposed changes that are likely to stifle 
competition.

G. Transmission Ratemaking Policy for RTOs

    We have concluded that the success of the Commission's efforts to 
have effective and efficient RTOs is dependent in large measure on the 
feasibility and vitality of the stand-alone transmission business. For 
that reason, and to promote economic efficiency, the RTO transmission 
ratemaking policies of the Commission are an important factor of RTO 
success. In light of the restructuring of markets and market 
institutions that is taking place, we now believe that it will be 
helpful to inform the industry about what we consider to be appropriate 
and inappropriate transmission pricing practices for RTOs, and about a 
framework for RTOs to propose efficient and fair pricing reform. 
Accordingly, we provide guidance below on a number of fundamental 
ratemaking issues.
    We believe that it is critically important for RTOs to develop 
ratemaking practices that: eliminate regional rate pancaking; manage 
congestion; internalize parallel path flows; deal effectively and 
fairly with transmission owning utilities that choose not to 
participate in RTOs; and provide incentives for transmission owning 
utilities to efficiently operate and invest in their systems. In 
particular, the Commission encourages RTOs to develop and propose 
innovative ratemaking practices, particularly with respect to 
efficiency incentives. We therefore devote a significant portion of the 
discussion in this section of the Final Rule to performance-based 
regulation (PBR) and other RTO transmission ratemaking reforms.
    In addition to the guidance offered here, we have added regulatory 
text (section 35.34(e)) with regard to PBR and other RTO transmission 
ratemaking reforms,\611\ which now identifies a select list of 
innovative transmission rate treatments. The Commission will consider 
such innovative rate treatments for entities that file proposals under 
the new section 35.34 and that meet the minimum characteristics and 
functions required in the Final Rule. The Applicant must explain how 
the proposed rate treatment would help achieve the goals of RTOs, 
including efficient use of and investment in the transmission system 
and reliability benefits to consumers; provide a cost-benefit analysis, 
including rate impacts; and explain why the proposed rate treatment is 
appropriate for the RTO proposed by the Applicant. This means that 
filings under section 35.34(e) must be complete and fully explained; 
must demonstrate that the resulting rates are just, reasonable, and not 
unduly discriminatory or preferential; must identify how the rate 
treatment promotes efficiency and what benefits result; and must 
demonstrate that the rate treatment does not impede the RTO from 
meeting the minimum characteristics and functions required under this 
Final Rule. The Commission encourages properly developed transmission 
pricing proposals from RTOs that comply with the guidance set forth 
below and the amended regulatory text.
---------------------------------------------------------------------------

    \611\ We have adopted and expanded the regulatory text proposed 
by Edison Electric Institute in its comments (see EEI, Appendix E).
---------------------------------------------------------------------------

    We agree with those commenters that urge the Commission to reform 
its transmission pricing policies to reflect new realities of the 
industry. For example, a number of commenters point to the unbundling 
requirements of Order Nos. 888 and 889, the vertical de-integration of 
generation and transmission for some utilities, the advent of wholesale 
and retail competition in energy markets, entry into markets of a range 
of new players, including independent generators and marketers, and 
other developments as a signal that the Commission's traditional cost-
of-service ratemaking practices for transmission assets should be 
reevaluated. Some commenters suggest that the advent of competitive 
power markets necessitates a more robust transmission network as well 
as enhanced operating capabilities of the network, compared to the 
previous era of vertically integrated utilities providing service in 
monopoly franchise areas. They argue that the Commission's traditional 
transmission ratemaking practices are unlikely to support such a robust 
transmission network and enhanced operating capabilities.

[[Page 914]]

    To put our concerns about transmission pricing in perspective, the 
NOPR said that ``the Commission expects RTOs to reform transmission 
pricing, and in return we propose to allow RTOs greater flexibility in 
designing pricing proposals.'' \612\ The NOPR also said that our 
willingness to provide flexibility in reviewing pricing proposals dates 
back to the Transmission Pricing Policy Statement, issued by the 
Commission in 1994. In the Policy Statement, we identified five 
principles that transmission pricing proposals should conform to, 
including the principle that pricing proposals should meet the 
traditional revenue requirement. In order that this principle not 
undermine innovative pricing proposals, the Policy Statement noted that 
non-conforming pricing proposals would be considered, but that such 
proposals would have to satisfy additional factors, i.e., promote 
competitive markets and produce greater overall consumer benefits. In 
the five years since the Policy Statement was issued, we have approved 
five ISOs with innovative transmission pricing, but otherwise have 
received few innovative transmission pricing proposals. We believe 
that, as a general matter, sensible pricing reform that could promote 
competition and efficiency in other contexts will achieve maximum 
benefits only when applied on a regional, rather than a single-system 
basis. This is true because of the inability of single systems to 
capture such efficiencies, but sensible pricing reform is one of the 
efficiencies that will likely flow from RTOs. And while we do not think 
the Policy Statement has been an impediment to transmission pricing 
innovation, we now believe, based on the myriad comments we received, 
that the Commission should now provide greater specificity on 
appropriate transmission pricing reforms by RTOs.
---------------------------------------------------------------------------

    \612\ FERC Stats. & Regs. para. 32,541 at 33,754.
---------------------------------------------------------------------------

    The rationale for providing greater specificity on transmission 
pricing for RTOs and amending the regulatory text at this time is 
three-fold. First, we recognize that transmission pricing issues are 
some of the most complex issues facing the industry. Second, a 
potential barrier to the development of RTOs, at least RTOs that span 
multiple transmission systems, is the difficulty that stakeholders have 
had reaching consensus on transmission pricing. This is not surprising, 
given that transmission pricing reform to accommodate regional needs 
and usage patterns can affect what customers pay for transmission 
service and how transmission revenues are allocated among multiple 
owners of transmission within a region. Third, we are concerned that as 
we move to greater reliance on market forces, the incentives that 
market participants have to make efficient operating and investment 
decisions for both generation and transmission facilities are based in 
part on the price signals that flow from transmission pricing. That is, 
transmission pricing is a key determinant of the efficient operation of 
energy, ancillary service and balancing markets, and congestion 
management.
    At the outset, we want to make clear that, contrary to the 
apprehensions of some commenters, the Commission is not proposing to 
``bribe'' transmission-owning utilities to join an RTO. Rather, the 
Commission stated in the NOPR that it would consider innovative pricing 
proposals because we believed then, and now believe more strongly, that 
a reassessment of transmission pricing policy is warranted, given the 
fundamental changes in industry structure that have already occurred as 
well as those which may flow from the RTO Final Rule. In addition, as 
pointed out by Professor Joskow, delays in RTO formation occasion costs 
because of more limited competition in generation markets, and these 
costs may be avoided to the extent that the Commission considers 
transmission pricing reforms. Furthermore, as discussed below, since 
the costs of transmission are a small portion of total electric costs, 
getting transmission pricing right means that the industry will be able 
to capture significant net benefits from promoting competitive 
generation markets.
    While the NOPR did not propose specific rules on transmission 
pricing reform, we believe it is now critical to provide further 
specificity to the industry. We recognize the need to establish clear 
and specific requirements for RTO development, provide certainty and 
clarity about our willingness to entertain transmission pricing reforms 
that are appropriate for RTOs, and assure utilities that they will not 
be penalized for RTO participation. To the extent consistent with 
ensuring that transmission rates are just, reasonable, and not unduly 
discriminatory, we believe transmission pricing disincentives to 
joining an RTO should be eliminated so that transmission-owning 
utilities will find RTO participation to be a dynamic business 
opportunity. Utilities that join RTOs should be accorded transmission 
pricing that reflects the financial risks of turning facilities over to 
an RTO and that reflects other changes in the structure of the 
industry. Those risks may increase or decrease in particular instances. 
At the same time, we wish to make clear that the Commission is very 
concerned about potential impacts of market restructuring on the 
customers in ``low-cost'' states, and the Commission therefore intends 
to monitor the effects of RTO formation on such customers, specifically 
the potential for cost-shifting effects of RTO pricing proposals.
    Traditional transmission pricing approaches reflect the industry 
structure as it existed when Order No. 888 was issued: a vertically 
integrated industry where transmission systems were designed primarily 
to meet the needs of local loads. Our primary focus, both in terms of 
access and pricing was comparability; that is, all transmission users 
should receive access under rates, terms and conditions comparable to 
those the transmitting utility applies to itself to serve its own 
customers. RTOs reflect a somewhat different approach, in which the 
transmission system must also be designed and operated to meet the 
needs of regional markets. It is not unreasonable to expect that, as 
the transmission system is restructured to meet these changing needs, 
significant pricing reform may be needed as well. Indeed, since a 
properly developed RTO will be designing methods to support regional 
congestion management and regional expansion, transmission pricing 
reform is inevitable.
    We caution that we do not view transmission pricing reform as a 
program designed for the sole purpose of enhancing the revenues of 
transmission owners at the expense of transmission customers. Nor are 
we abandoning the fundamental underpinnings of our traditional 
transmission pricing policies, i.e., that transmission prices must 
reflect the costs of providing the service.\613\ While many aspects of 
transmission pricing reform are labeled incentive pricing, many are 
aimed at eliminating disincentives to the efficient use and expansion 
of regional transmission grids to support emerging competition in 
generating markets.
---------------------------------------------------------------------------

    \613\ See, e.g., Federal Power Commission v. Hope Natural Gas 
Co., 320 U.S. 591 (1944); Bluefield Water Works & Improvement Co. v. 
Public Service Commission of West Virginia, 262 U.S. 679 (1923).
---------------------------------------------------------------------------

    We view transmission pricing reform, not only as an important 
component of how stand-alone transmission companies can become viable 
and efficient network businesses, but also as an important means for 
transmission-owning utilities which maintain ownership but cede control 
of their transmission assets to an RTO to capture

[[Page 915]]

the benefits of more efficient system operation and additional grid 
investment. We believe that the opportunities for pricing reform 
identified in this Rule should have no effect on an RTO's decision 
about how it will be structured. All RTOs, regardless of ownership 
structure, are therefore eligible to propose transmission pricing 
reforms that suit their strategic and economic objectives to the extent 
consistent with this Final Rule.
    We also believe that the potential for any increase in 
transmission-related revenues available to transmission providers that 
are efficient and responsive in meeting the needs of their customers 
must be balanced by the potential for a decrease in profits if the 
transmission provider does not meet those needs. Moreover, a properly 
developed RTO can be expected to produce significant efficiencies, and 
we would expect that transmission owners, transmission customers and 
generation market participants will share in the economic benefits 
resulting from the efficient design and operation of the RTO.
    As the industry begins the collaborative process of establishing 
RTOs, it is important that the Commission provide some certainty and 
specificity about the preferred types of transmission pricing reforms, 
and some certainty and specificity about the types of proposed 
transmission pricing reforms that appear more problematic. Accordingly, 
the remainder of this section discusses eight specific transmission 
ratemaking topics: pancaked rates; reciprocal waiving of access charges 
between RTOs; use of single system access charges; congestion pricing; 
service to transmission-owning utilities that do not participate in an 
RTO; performance-based regulation; other RTO transmission ratemaking 
reforms; and additional ratemaking issues.
1. Pancaked Rates
    As described in the NOPR, the elimination of rate pancaking for 
large regions is a central goal of the Commission's RTO policy, and has 
been a feature of all five ISOs the Commission had approved. Rate 
pancaking occurs when a transmission customer is charged separate 
access charges for each utility service territory the customer's 
contract path crosses. The NOPR proposed that RTO tariffs not result in 
transmission customers paying multiple access charges to recover 
capital costs over facilities that it controls. The NOPR sought 
comments on the impact of the non-pancaked rate requirement on 
voluntary RTO formation because of abrupt rate changes. It also sought 
comments on how the regional configuration may relate to these 
potential rate changes.
    Comments. The overwhelming majority of the comments favor the 
proposed prohibition on pancaked rates,\614\ although some commenters 
express concern over cost shifting. Some commenters, such as Minnesota 
Power, suggest that the cost shifting effect of non-pancaked rates 
would discourage voluntary RTO formation.
---------------------------------------------------------------------------

    \614\ See, e.g., NASUCA, PJM, LG&E, Industrial Consumers and 
WEPCO.
---------------------------------------------------------------------------

    Some commenters suggest alternative approaches to the strict non-
pancaked rate described in the NOPR. For example, WPSC advocates the 
use of flow-based, distance-sensitive rates as a replacement for 
pancaked rates. Allegheny argues that removing rate pancaking can cause 
disruptive shifts in rates and revenue requirements which are solved 
only temporarily with transitional rates. Allegheny proposes its form 
of locational marginal pricing method to solve this problem. NSP favors 
non-pancaked rates but notes that rates for the high-voltage system 
that differ from those for the low-voltage system may be an effective 
long-term rate strategy. MidAmerican recommends that the prohibition 
against rate pancaking be changed to allow transmission owners to 
charge a home-zone rate based on local cost determination and a wide-
area charge outside the home area. MidAmerican argues that this 
approach would minimize cost shifting. The pancaked rate prohibition 
would change to: ``promote wide-area transmission rates with due 
consideration to shifting of costs among transmission service providers 
and between state and federal delivery rates. Finally, Williams 
recommends that the Commission also consider other pricing methods such 
as those based on mileage or network usage and market-based rates, 
where possible, because it considers cost of service rates inefficient 
and unresponsive to the market.
    A few commenters question an absolute prohibition against pancaked 
rates. AEP and Florida Power Corp. warn that a strict prohibition 
against pancaked rates may, at times, work against efficient solutions. 
There should not be a strict prohibition without regard to size or 
locational factors. Florida Power Corp. argues that this approach is 
consistent with the Commission's Transmission Pricing Policy Statement. 
Customers of both AEP and Florida Power Corp. dispute this view.\615\ 
Southern Company notes that an absolute prohibition against pancaked 
rates may hurt retail customers whose rates are supported by 
transmission revenue. Transmission owners should be assured in the 
final rule that they will be able to recover their full revenue 
requirement in the face of any pancaked rate prohibition. The 
Commission should, according to Southern Company, also clarify that a 
prohibition against pancaked rates does not prevent the use of zonal or 
other distance-sensitive rates. Desert STAR argues that a single 
region-wide rate may not be appropriate in a large region with 
legitimate cost differences among companies, and suggests that license 
plate rates may mitigate cost shifting but will not always eliminate 
it.
---------------------------------------------------------------------------

    \615\ See New Smyrna Beach and Coalition of Alliance Users.
---------------------------------------------------------------------------

    Commission Conclusion. In the NOPR, we described the elimination of 
rate pancaking as a central goal of our RTO policy. After receiving 
comments on the subject, mostly in favor of the proposed prohibition, 
we affirm that the RTO tariff must not result in transmission customers 
paying multiple access charges to recover capital costs.\616\
---------------------------------------------------------------------------

    \616\ Section 35.34(k)(1)(ii). However, see the discussion below 
regarding service to transmission-owning utilities that do not 
participate in an RTO.
---------------------------------------------------------------------------

    Except for transactions within the ISOs now in place, transmission 
customers are faced with additional access charges for every utility 
border they cross. The distances need not be great to be assessed two, 
three or more access charges for a single transaction. This duplication 
can severely restrict the area in which generation can economically be 
secured. A main reason that an RTO can expand the marketplace for 
generation to a large region is that an RTO can implement non-pancaked 
rates for each transaction. A wider area served by a single rate means 
more generation is economically available to any customer which means 
greater competition for energy.
    Some commenters warn that a blind adherence to non-pancaked rates 
can produce inefficiencies in some circumstances. Some argue that large 
distances and special conditions can add to transmission costs in a way 
not reflected in single system rates. They would leave open the option 
for distance-sensitive rates or completely new rate innovations that 
may not fit the strict definition of a non-pancaked rate. We are 
sensitive to some of these concerns, but we do not view a policy 
requiring non-pancaked rates as posing the problems that some 
commenters

[[Page 916]]

describe. We take this opportunity to reaffirm that we will continue to 
be receptive to distance-sensitive rates and other rate features that 
can be supported.
2. Reciprocal Waiving of Access Charges Between RTOs
    The elimination of pancaked rates within an RTO was intended to 
increase the efficiency of trade in that region. The NOPR furthered 
that concept by encouraging RTOs to agree among themselves to waive 
access charges on a reciprocal basis for transactions that cross RTO 
borders. If accomplished, this would have the effect of increasing 
effective trading areas. The NOPR sought comments on how the Commission 
could facilitate reciprocal waivers of access charges, and whether 
there are other impediments to inter-regional trade.
    Comments. A majority of the commenters support the concept of a 
reciprocal waiver of access charges to encourage inter-regional 
trade.\617\ Of those who support waivers, some, including Duke and SRP, 
specifically recommend that waivers be voluntary. Some supporters of 
waiving access charges note that it is not just the pancaked charges 
that inhibit inter-regional trade but also variations in business 
practices and procedures between RTOs. These commenters \618\ recommend 
that the Commission ensure that such incompatibilities not be allowed 
to hamper trade between RTO regions.
---------------------------------------------------------------------------

    \617\ See, e.g., Sithe, WPSC, Minnesota Power, Ohio Commission, 
and Midwest ISO Participants.
    \618\ See, e.g., Ontario Power and Oregon Office.
---------------------------------------------------------------------------

    Several commenters, both supporting and opposed to waiver of access 
charges, warn that the waivers proposed in the NOPR can cause cost 
shifting. Duke argues that cost shifting can be remedied by the 
structure of the rate. DOE and First Energy also express concerns about 
cost shifting. Southern Company generally opposes waivers of access 
charges unless transmission owners' revenues are protected.
    Some commenters oppose waiving access charges between RTOs for 
reasons other than cost shifting concerns. South Carolina Authority 
claims that reciprocal agreements between RTOs waiving access charges 
are discriminatory and that independent monitoring groups would be 
needed to prevent gaming of reciprocity agreements. CP&L argues that 
waivers create a bias to sell outside of the RTO. Tri-State proposes 
the use of distance-sensitive export pricing mechanisms instead of 
waivers.
    PP&L Companies claim that inter-regional trade solutions should be 
arrived at through a collaborative effort of stakeholders. NECPUC and 
Desert STAR argue that the Commission should grant deference to 
participants' solutions for inter-regional trade. Florida Commission 
argues that the Commission should wait until intra-regional trade 
barriers are dismantled before dealing with inter-regional trade.
    Commission Conclusion. We asked in the NOPR for comments on the 
policy of allowing RTOs to reach reciprocal agreements to waive access 
charges for transmission that crosses an RTO border. Most commenters 
supported the approval of such waivers and some asked the Commission to 
further support inter-regional trade by requiring uniform practices and 
procedures among RTOs. Some commenters maintain that incompatible or 
varying procedures between RTOs can be as dampening to inter-regional 
trade as multiple rates.
    We will continue to encourage reciprocal waivers of access charges 
between RTOs as long as they are reasonable in terms of cost recovery, 
cost shifting, efficiency, and discrimination. We also encourage terms 
and procedures that are compatible from region to region to the extent 
appropriate. Accordingly, we have added an RTO function to integrate 
reliability and market interface practices with other regions, as 
discussed above.
3. Uniform Access Charges
    Each ISO approved by the Commission has struggled with the problem 
of cost shifting among the various individual transmission owners that 
make up the ISO. A single access rate would mean that the customers of 
low-cost transmission providers would see a rate increase and high-cost 
transmission providers would be concerned about not meeting their 
revenue requirements. The potential for cost shifting has been a 
stumbling block for several regions seeking to establish regional 
transmission organizations.
    The Commission has allowed a flexible approach to this problem, and 
in each ISO approved by the Commission to date the solution has been to 
adopt a ``license plate'' rate for a transitional period of five to ten 
years before moving to a single uniform access charge. A license plate 
rate provides access to the regional transmission system at a single 
rate although that rate may vary based on where the customer is 
located.\619\ The NOPR proposed to continue to employ a flexible 
approach, including the use of license plate rates. The NOPR requested 
comments on whether the license plate approach is appropriate for the 
long term.\620\
---------------------------------------------------------------------------

    \619\ Consider that registering a car in one state, paying that 
state's fees, and obtaining a license plate from that state, allows 
that car to be driven on the roads and highways of all other states.
    \620\ FERC Stats. & Regs. para. 32,541 at 33,754.
---------------------------------------------------------------------------

    Comments. A clear majority of commenters favors the use of license 
plate rates in general, with a nearly even split between those that 
would allow license plate rates only for a transitional period \621\ 
and those that would allow them as a permanent feature.\622\ Of the 
approximately 64 commenters who addressed this subject, only about nine 
were clearly opposed to license plate rates for either the long term or 
for a transitional period. And several commenters advocate the use of 
license plate rates as a general concept but did not address directly 
the NOPR's question concerning their long-term use.\623\
---------------------------------------------------------------------------

    \621\ See, e.g., Montana Commission, Oglethorpe, Tri-State, 
FirstEnergy, Alliance Companies, AEP and DOE.
    \622\ See, e.g., Allegheny, Industrial Consumers, Northwest 
Council, APS, Desert STAR and SPP.
    \623\ See, e.g., Kentucky Commission, Gainesville, Big Rivers, 
Puget and Ontario Power.
---------------------------------------------------------------------------

    Several commenters argued that the use of license plate rates 
should be for a transition period roughly coincident with the phase-in 
of retail competition. For example, Duke argues that license plate 
rates avoid cost-shifting, and will therefore make it easier for 
companies to collect their retail revenue requirements in jurisdictions 
without retail competition, where state regulators may disallow higher 
transmission rates.
    Commenters that support license plate rates as a long-term solution 
argue that license plate rates are an aid to RTO formation.\624\ SoCal 
Edison claims that license plate rates avoid cost shifts, are 
administratively more efficient, provide a basis for efficient 
transmission operation, and provide incentives for system expansion. 
SoCal Edison favors their use in the long term.
---------------------------------------------------------------------------

    \624\ See eg., East Kentucky and PJM.
---------------------------------------------------------------------------

    Of those opposed to license plate rates in general, some suggest a 
different pricing methodology. CMUA prefers an integrated, two-part 
rate. The first part of the rate reflects the revenue requirement of 
the overall RTO (principally above 200 kV) and the second part reflects 
the local systems to the extent used. CMUA argues that license plate 
rates do not follow the rules of cost causation, do not promote needed 
enhancements and do not promote comparability in rates. Minnesota Power 
recommends a two-part rate with a demand component to

[[Page 917]]

collect fixed costs and a variable component for losses. WPSC advocates 
the use of flow-based, distance-sensitive rates rather than license 
plate rates. APPA claims that license plate rates do not go far enough. 
A four part approach is suggested in their place: assure recovery of 
revenue requirement; honor existing contracts and phase in regional 
rates; sub-functionalize the grid by voltage; and, once trusted RTOs 
are in place, allow congestion rates above embedded costs and non-
congestion rates below, all subject to a revenue requirement true-up. 
RECA recommends that zones for transmission access charges be formed 
based on cost and other differences, not on existing service areas. 
SMUD claims that Cal ISO's license plate rate encourages inefficient 
operation.
    Some commenters provide more general reactions to the cost shifting 
problem. Wyoming Commission recommends that the Commission not codify a 
specific approach to license plate rates and other measures with cost-
shifting ramifications but rather defer to regional and state processes 
to establish guidelines within a region. PSNM is concerned about the 
impact of the loss of existing contracts on its license plate rate 
calculation. Manitoba Board is concerned about shifting costs to low-
cost, transmission-dependent areas. Platte River does not want its low 
costs averaged with higher cost systems. United Illuminating encourages 
the Commission to continue its flexibility in permitting different 
approaches in the recovery of sunk costs. Aluminum Companies argues 
that the Commission needs to offer more guidance on cost shifting and 
that rate increases due to cost shifting should be constrained to the 
benefits involved. Further, cost shifts should not be allowed unless 
competition is fostered.
    Commission Conclusion. We conclude that the Commission should 
continue to provide flexibility with respect to RTO proposals for 
allocation of fixed transmission cost recovery. The Commission will 
permit RTO proposals to use license plate rates, as defined above, for 
several reasons. First, commenters overwhelmingly support the use of 
license plate rates, and demonstrated convincingly that problems 
associated with cost-shifting are not easily resolved by means other 
than the use of license plate rates. Second, the Commission is 
concerned that the potential for cost-shifting could act as an 
impediment to RTO formation, thereby denying all stakeholders the 
benefits that come from RTO membership.
    Moreover, although license plate rates are not necessarily an ideal 
method for fixed cost recovery, we note that all ISOs have sought 
approval from the Commission for license plate rates, at least during 
their startup phase. No commenter has provided convincing evidence that 
the use of license plate rates by existing ISOs produces significant 
harms, although several commenters suggest various rate designs, 
including multi-part rates, as alternatives to license plate rates.
    Although commenters overwhelmingly support the use of license plate 
rates, they are split on whether such rates should be used only for a 
transitional period, or whether the Commission should allow them as a 
permanent feature. This is a difficult issue. On the one hand, we are 
reluctant to require RTOs to suspend use of license plate rates after 
some arbitrary date certain at which time they will be required to 
transition to single system access rates; on the other hand, we are 
reluctant to announce generically that license plate rates may be a 
permanent feature of an RTO. Furthermore, the use of license plate 
rates could depend on idiosyncratic facts, e.g., the geographic makeup 
of the RTO, or the transmission cost differences in various subregions 
of the RTO.
    We therefore believe that it is appropriate to allow RTOs to 
propose the use of license plate rates for a fixed term of the RTO's 
choosing. However, RTOs that propose the use of license plate rates 
must make clear how transmission expansion will be priced, that is, 
whether license plate rates or some other mechanism will be applied to 
the cost of new transmission facilities, and how such pricing affects 
incentives for efficient expansion. In addition, we will require that 
before the end of the fixed term, the RTO must complete an evaluation 
of fixed cost recovery policies based on the factual situation of the 
particular RTO, and file with the Commission its recommendations on any 
changes that should be instituted. We emphasize that we are not 
requiring that the RTO continue or abandon the use of license plate 
rates at that time, but we will require the RTO to justify its choice 
to continue or discontinue using license plate rates, or otherwise 
change the method for fixed cost recovery. We believe that this 
approach provides participants in RTOs significant flexibility, and is 
consistent with the principles articulated in the open architecture 
requirement for RTOs.
4. Congestion Pricing
    Congestion pricing and congestion management are closely related. 
Comments on these issues have been treated jointly, and are summarized 
above in the discussion of congestion management.
    Commission Conclusion. With respect to congestion pricing, the 
Commission emphasized that it intends to be flexible in reviewing 
pricing innovations, and sought comments on what specific requirements, 
if any, best suited the Commission's RTO goals. A number of commenters 
agreed with the Commission's conclusion in the NOPR that ``markets that 
are based on locational marginal pricing and financial rights for 
transmission provide a sound framework for efficient congestion 
management.'' \625\
---------------------------------------------------------------------------

    \625\ FERC Stats. and Regs. para. 32,541 at 33,742.
---------------------------------------------------------------------------

    We reemphasize the basic principles for congestion pricing 
articulated in the NOPR, i.e., that proposals should ``ensure that the 
generators that are dispatched in the presence of transmission 
constraints must be those that can serve system loads at least cost, 
and limited transmission capacity should be used by market participants 
that value that use most highly.'' \626\
---------------------------------------------------------------------------

    \626\ Id. at 33,754-55.
---------------------------------------------------------------------------

    We recognize that congestion pricing, especially when complex 
problems associated with parallel path flows are addressed, is in its 
infancy. Rather than prescribe a specific method, we encourage 
experimentation with reasonable congestion management techniques. We 
would expect that such experiments be consistent with the open 
architecture requirements of the rule, and that information from such 
experiments be made widely available to all interested parties, so that 
other RTOs can learn from each others' experience.
5. Service to Transmission-Owning Utilities That Do Not Participate in 
an RTO
    The Commission asked commenters to discuss the treatment by an RTO 
of a non-participating transmission owner in a region if the 
transmission owner does not participate in its region's RTO.\627\ For 
example, we asked whether it would be appropriate to allow RTO members 
to provide transmission service at individual system rates to non-
participating transmission owners located in the RTO region thereby 
denying non-participants the benefits of non-pancaked transmission 
rates.
---------------------------------------------------------------------------

    \627\ Id. at 33,759.
---------------------------------------------------------------------------

    Comments. Of those commenters that generally support the proposed 
strategy,

[[Page 918]]

most argue that non-participants should not enjoy the benefits of non-
pancaked rates.\628\ PG&E submits that the reasoning the Commission 
applied in Order No. 888 applies here (i.e., in Order No. 888, the 
Commission rejected the claim that a reciprocity requirement required 
explicit Commission jurisdiction over the transmission customer finding 
that, as a matter of fairness, a public utility providing open access 
through a non-discriminatory tariff deserved the right to obtain 
comparable access over the transmission systems of its customers). 
Empire District is particularly concerned that utilities on the border 
of an RTO may receive many advantages of the RTO without accepting any 
of the burdens of participation, yet at the same time make it more 
difficult for competitors to service its load by staying out of the 
RTO.
---------------------------------------------------------------------------

    \628\ Montana-Dakota, Allegheny, PG&E, Tri-State, PNGC and 
Empire District.
---------------------------------------------------------------------------

    Other commenters are conditional in their support. For example, 
Oneok wants the Commission to draw a hard line on non-participation and 
be willing to employ negative incentives; however, Oneok points out 
that denial of non-pancaked rates will be more costly to marketers and 
consumers. South Carolina Authority suggests that the Commission 
consider the extent to which the transmission owner is actually able to 
participate in an RTO before permitting denial of RTO service under 
non-pancaked rates. In the case of publicly owned utilities, there may 
be restrictions in the enabling act or charter, the applicable state 
constitution or the utility's bond covenant that effectively prohibit 
it from participating in a particular RTO. This would also apply if the 
RTO is not the product of the ``region's RTO'' involving all 
stakeholders in the designated region but is a business entity designed 
to advance the financial objectives of particular sponsors. Similarly, 
SPRA argues that, in the event that it is unable to immediately join an 
RTO, the RTO should recognize that SPRA has an OATT that provides for 
comparable treatment to the RTO. And New Smyrna Beach states that, 
although denial of non-pancaked rates to nonparticipants has merit, it 
may be a moot issue in Florida where FP&L's transmission is so 
extensive that pancaked rates would be a more costly alternative for 
marketers and consumers of electricity.
    Other commenters believe the proposal is a flawed concept or 
otherwise oppose it. Avista and PPC argue that it is not appropriate to 
allow an RTO to provide transmission service at individual system rates 
to non-participating transmission owners as such a policy would deny 
them the benefits of non-pancaked rates and defeat the central goal of 
its proposal. Metropolitan concurs that non-participating transmission 
owners should share in the benefits of non-pancaked rates. Southern 
Company and CP&L claim that the Commission cannot punish utilities that 
find it in the best interests of their stakeholders not to join an RTO. 
SMUD believes that RTOs must provide nondiscriminatory access to 
transmission it controls at cost-based rates to all customers, since 
they contribute to the RTO's cost recovery. SMUD argues that the 
Commission, through its NOPR has, in essence, found that pancaked rates 
are not just and reasonable and that they should be corrected; thus, 
the Commission cannot allow an RTO to charge pancaked rates in 
violation of the FPA section 205 prohibition on unjust or unreasonable 
rates.
    Snohomish, Turlock, Big Rivers and Dairyland all make similar 
arguments--charging higher pancaked rates to utilities that do not 
participate in the RTO is patently unfair, violates the Commission's 
duty to eliminate discriminatory rates, and would penalize consumers of 
customer-owned utilities who have no practicable choice about whether 
to participate in the RTO. Dairyland says that this could open the door 
to creation of RTOs that purposely do not accommodate non-public 
utilities. SRP posits that imposition of pancaked rates on non-
participants in an RTO would effectively turn the Commission's stated 
policy goal of voluntary participation into an RTO mandate inviting 
years of litigation.
    Two state commissions question the effectiveness of pancaked rate 
sanctions against non-participants. Indiana Commission contends that a 
recalcitrant utility may not perceive pancaked rates as detrimental and 
may not feel compelled to join an RTO. Illinois Commission feels that 
imposition of penalties involving restricted access to RTO transmission 
rates would either be self-defeating for the Commission or detrimental 
to the electricity consumers of the affected utility. In its view, the 
solution to this conundrum is for the Commission to abandon its 
unworkable voluntary approach to RTO participation, and utilize its 
authority under FPA sections 205 and 206 and examine its authority 
under FPA sections 202(a), 211 and 212 to mandate participation. 
However, Nevada Commission submits that the Commission must ensure that 
a transmission-owning utility that refuses to join an RTO should not be 
allowed to derive any economic benefit from the existence of RTOs.
    ISO commenters have diverse views on this issue. Desert STAR argues 
that a blanket ban on prohibiting a party that does not join an RTO 
from deriving any benefit from the RTO whatsoever may be too broad an 
approach. NYPP, citing Associated Gas Distributors v. FERC \629\ and 
Richmond Power & Light v. FERC \630\ for the proposition that the 
Commission cannot achieve indirectly what it cannot do directly, submit 
that the Commission cannot impose any coercive measure on or deny 
benefits to utilities that do not participate in an RTO. In addition, 
NY ISO argues that previously approved ISO's transmission-owning 
members should be eligible for whatever RTO participation incentives 
and benefits are ultimately adopted in this proceeding. On the other 
hand, PJM/NEPOOL Customers support denial of non-pancaked transmission 
rates to nonparticipants.
---------------------------------------------------------------------------

    \629\ 824 F.2d 981, 1024 (D.C. Cir. 1987).
    \630\ 574 F.2d 610, 620 (D.C. Cir. 1978).
---------------------------------------------------------------------------

    Canadian entities generally oppose imposition of pancaked rates 
against non-participants. Canada DNR contends that a decision not to 
participate in an international RTO by a Canadian jurisdiction should 
not place entities in that jurisdiction engaged in trade with the U.S. 
at a disadvantage relative to U.S. RTO participants. BC Hydro concurs 
that the decision to join an RTO should not be made a prerequisite for 
participation of Canadian provincial utilities or their affiliates to 
participate in the U.S. electricity market. CEA observes, however, that 
Canadian utilities see access to the U.S. market as a significant 
business opportunity that requires a transparent and open bulk 
transmission system operating in both directions. Grand Council et al. 
submits, however, that applying no penalties or incentives to Canadian 
utilities, while giving them unfettered access to U.S. markets without 
being subject to corresponding obligations, is inconsistent with the 
RTO concept. And H.Q. Energy Services submits that, if the Commission 
decides not to require RTO participation, it should strongly encourage 
voluntary participation by denying certain benefits such as the use of 
the system-wide tariff to nonparticipants.
    Commission Conclusion. Regarding the question raised in the NOPR 
about whether a non-participating transmission owner in an RTO region 
should receive all the benefits of the RTO in its region, we share the 
concerns

[[Page 919]]

of most commenters that transmitting utilities may receive the benefits 
of an RTO in its region without accepting any of the burdens of 
participation in the RTO. Accordingly, 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.
    We do not intend that every such proposal will necessarily be 
accepted by the Commission. Each RTO must justify any proposal on a 
case-by-case basis. The proposal should recognize the various 
situations of non-participating transmission owners. As pointed out by 
commenters, some transmission owners may face legal obstacles to 
participation that may need to be taken into account in the proposal.
    It is not our intent to permit an RTO to apply such a proposal to a 
non-participating transmission owner in another region. As discussed 
above, Empire District expressed concern about whether this provision 
would apply to a non-participating owner ``on the border'' of an RTO. 
We would permit an RTO to argue that the non-participant should be part 
of its RTO region based on engineering or other objective criteria.
    An RTO will provide several benefits for parties in the region, 
including elimination of individual system rates. We asked in the NOPR 
whether it would ``be appropriate to allow RTO members to provide 
transmission service at individual system rates to non-participating 
transmission owners located in the RTO region.'' (emphasis added) \631\ 
SMUD argues that the Commission in its NOPR has found, in effect, that 
individual system rates are not just and reasonable and so cannot allow 
transmission-owning utilities in an RTO to charge individual system 
rates.
---------------------------------------------------------------------------

    \631\ FERC Stats. & Regs. para. 32,541 at 33,759.
---------------------------------------------------------------------------

    SMUD is incorrect. We have not made a generic determination that 
individual system rates are not just and reasonable in an RTO region. A 
non-participating public utility transmission owner in an RTO region 
may itself file a single company rate and argue that it is just and 
reasonable for use by its neighbors who join the RTO.
    Instead of making a generic determination about these matters, we 
will permit an RTO and its transmission-owning public utility members 
to make the case that it is just and reasonable to charge individual 
system rates to a transmission customer who is a non-participating 
transmission owner in its RTO region. We will decide each RTO proposal 
on its merits.
6. Performance-Based Rate Regulation
    The NOPR suggested that, once RTOs are formed, performance based 
regulation (PBR) can facilitate good grid operation.\632\ We noted that 
PBR can incorporate price/revenue caps, price incentives, or 
performance standards. The NOPR sought comments on how PBR should be 
applied to an RTO and whether it should be voluntary.
---------------------------------------------------------------------------

    \632\ Id., at 33,755.
---------------------------------------------------------------------------

    Comments. The vast majority of commenters favor PBR of some form to 
promote efficient operations by RTOs.\633\ And most commenters that 
favor PBR specifically state that PBR should be voluntary for RTO 
participants.\634\
---------------------------------------------------------------------------

    \633\ See, e.g.,  EPSA, PJM, Los Angeles, Georgia Transmission, 
Illinois Commission, Pacific Corp and Desert STAR.
    \634\ See, e.g., Florida Power Corp., MidAmerican, Tri-State, 
FirstEnergy, Alliance Companies, Duke and PGE.
---------------------------------------------------------------------------

    Professor Joskow recommends that the Commission promote the view 
that PBR will eventually be required. He suggests that there is 
sufficient experience with PBR, such as in England and Wales. He argues 
that PBR should be based on a standard price cap that focuses not only 
on direct transmission service costs, but also focuses on the cost of 
congestion management, losses, ancillary services, reactive power, and 
connection of new generators. EEI notes that a price cap, based on a 
reasonable ROE revenue requirement, is the most widely used method. EEI 
argues that price caps reduce rate cases, give an incentive to improve 
productivity, and share productivity savings with customers. Brattle 
Group does not propose a specific PBR scheme but says that, at this 
point, approval should be case-by-case. Care should be taken that a PBR 
is not based on a single element, causing distortions elsewhere.
    Other supporters have specific comments regarding the 
implementation of PBR. Entergy recommends that the Commission provide 
more specific guidance on the use of PBR. DOE warns that PBR should not 
be allowed to prevent a PMA that is a part of an RTO to under-recover 
its revenue requirement. New Smyrna Beach and Oneok only support PBR if 
there is a downside as well as an upside potential associated with 
transmission performance. Allegheny states that the Commission must 
settle on a definition of performance, the performance criterion should 
be economic reliability, the owner must have an opportunity to recover 
investment, the Commission should recognize that some aspects of 
performance will be outside of the control of the RTO, and the 
particular PBR rate calculation should be considered on a case-by-case 
basis.
    A number of commenters recommend that PBR not be instituted 
immediately upon the formation of the RTO. California Board, Trans-
Elect, and WPSC maintain that time is needed to establish base year 
benchmarks. PG&E and APPA say that PBR should be set aside until the 
RTO is up and functioning and Arkansas Consumers and Wyoming Commission 
argue that the RTO should first demonstrate that it can and will 
provide reliable and non-discriminatory service before PBR is 
established.
    At least eight commenters were opposed to PBR for RTOs as a 
Commission policy. Industrial Consumers, Williams, and CMUA do not 
think that PBR can be effective in promoting efficiency in the 
operation of RTOs. Salomon Smith Barney and East Texas Cooperatives 
believe that RTOs will be able to game the system and take advantage of 
PBR. PJM/NEPOOL Customers, Lincoln, and NASUCA argue that PBR should 
not be allowed for RTOs because they are unnecessary. NASUCA is also 
skeptical of PBR for RTOs because some areas where performance is 
important are not under the RTO's control. NJBUS argues that PBR will 
not put a stop to transmission discrimination.
    NEPCO et al. disagree with those commenters who oppose PBR.\635\ 
PBR is effective, as shown in the United Kingdom, and they are not 
``bribes'' given freely to transmission owners. Enron/APX/Coral Power 
does not agree with NASUCA and California Board that there is not 
enough experience on which to base PBR. According to Enron/APX/Coral 
Power, there is a large amount of experience in regulating transmission 
plus a lot of experience with the ramifications of EPAct.
---------------------------------------------------------------------------

    \635\ See, e.g., APPA, Minnesota Power and CMUA.
---------------------------------------------------------------------------

    A few additional commenters neither strongly support nor oppose 
PBR, but offer specific comments about PBR use. Project Groups 
recommends that the Commission construct a way to de-couple revenues 
from transmission rates so that efficient transmission service rather 
than total throughput determines revenue. Florida Commission states 
that questions as to the advisability and particulars of a PBR 
mechanism should be left to regional solutions that have the 
endorsement of the state regulatory

[[Page 920]]

bodies. Big Rivers states that PBR is inappropriate for cooperatives 
and public power utilities. WEPCO believes that RTOs should be not-for-
profit and that PBR should be available only to the for-profit 
transmission owner. Metropolitan is concerned that PBR might cause RTOs 
to neglect needed expansions and upgrades and jeopardize reliability.
    Commission Conclusion. At the outset, we think it is important to 
emphasize that PBR is far from a new concept. Over the last 10 to 20 
years, a significant amount of research, primarily by economists, has 
been done regarding the conceptual basis of, and efficient designs for, 
PBR.\636\ This research addresses its use in the electric utility 
industry as well as other regulated industries. It is also important to 
note that the Commission has been receptive to PBR proposals, at least 
since issuance of the Policy Statement on Incentive Regulation in 
October 1992. In that Policy Statement, we provided guidance to public 
utilities as well as natural gas and oil pipelines considering 
proposing some form of PBR.\637\ Although the Policy Statement invited 
public utilities to develop and file incentive regulation proposals, 
the Commission has not received any proposals from public 
utilities.\638\
---------------------------------------------------------------------------

    \636\ See, e.g., Paul Joskow and Richard Schmalensee, Incentive 
Regulation for Electric Utilities, Yale Journal of Regulation, Vol. 
4 at 1-49 (1986); Sanford Berg and Rajiv Sharma, Techniques for 
Assessing Firm Efficiency, University of Florida Public Utilities 
Research Center Working Paper (June 1999); Peter Navarro, Seven 
Basic Rules for the PBR Regulator, Electricity Journal at 24-30 
(April 1996); G. Alan Comnes, Steven Stoft, et al., Six Useful 
Observations for Designers of PBR Plans, Electricity Journal at 16-
23 (April 1996); Lorenzo Brown and Ingo Vogelsang, Incentive 
Regulation: a Research Report, Federal Energy Regulatory Commission, 
Office of Economic Policy, Technical Report 89-3 (1989); and Jean-
Jacques Laffont and Jean Tirole, A Theory of Incentives in 
Procurement and Regulation, MIT Press (1993).
    \637\ The Policy Statement articulated five regulatory 
standards: (1) incentive ratemaking must be prospective; (2) 
participation must be voluntary; (3) incentive mechanisms must be 
understood by all parties; (4) benefits to consumers must be 
quantifiable; and (5) quality of service must be maintained.
    \638\ We note that PBR mechanisms have been widely used by state 
regulators and the FCC as applied to the U.S. telecommunications 
industry. See, e.g., John Kwoka, Implementing Price Caps in 
Telecommunications, Journal of Policy Analysis and Management, Vol 
12, No 4 at 726-52 (1993).
---------------------------------------------------------------------------

    The Commission's current interest in PBR stems from the proposition 
that PBR will allow the Commission to rely on market-like forces, to 
the maximum extent possible, to create incentives for RTOs to 
efficiently operate and invest in the transmission system. This does 
not mean that we expect that transmission services will be provided in 
competitive markets any time soon, or at all. We recognize that 
transmission service will retain most or perhaps all of the 
characteristics of a natural monopoly for the foreseeable future, and 
that some type of explicit price regulation will therefore be required 
to prevent monopoly abuse. But we believe that PBR, especially if 
accompanied by explicit and well-designed incentives, may provide 
significant benefits over traditional forms of cost-of-service 
regulation. We believe this view of PBR is entirely consistent with 
other initiatives taken by the Commission, such as Order Nos. 888 and 
889, to promote competitive power markets, and given the impracticality 
of competitive transmission markets, to rely on market-like forces to 
the maximum extent possible.
    Before providing further specificity on PBR, it is useful to 
restate the overarching concerns of commenters. A large number of 
commenters support the use of PBR, and many of them, as discussed 
above, believe that PBR and other forms of incentive regulation will 
significantly enhance the incentives RTOs have to make efficient 
operating and investment decisions. For example, Professor Joskow 
notes:

    It is very important for the Commission to adopt regulatory 
mechanisms that provide transmission owners and operators with 
powerful economic incentives to operate transmission networks 
efficiently and to invest the resources necessary to expand their 
capabilities efficiently. These incentives should be an integral 
component of a performance-based regulatory (PBR) framework for the 
regulation of transmission rates that rewards transmission owners 
for achieving these objectives and penalizes them for failing to do 
so.\639\
---------------------------------------------------------------------------

    \639\ Professor Joskow at ES-iv.

    On the other hand, a somewhat smaller group of commenters, mostly 
transmission customers, oppose the use of PBR. They express doubts 
about whether PBR will provide good incentives for RTOs to operate and 
invest efficiently. They are also concerned that PBR design is so 
difficult that RTOs will easily game the system, which will likely 
result in higher revenues for RTOs and therefore higher prices for 
transmission services for all transmission customers.
    Commenters describe a wide array of PBR mechanisms, including some 
relatively unsophisticated proposals and others which are analytically 
complex. For example, a number of commenters have proposed that the 
Commission entertain transmission rate moratoriums, e.g., where 
transmission rates are locked into their current levels for a limited 
period of years. To the extent the transmission provider can achieve 
any transmission costs savings, these would be retained by the 
transmission provider. In this sense, it falls within the concept of 
PBR.
    It is argued that this rate treatment may promote the establishment 
of independent transmission companies because it provides the certain 
revenue stream that is needed to obtain financing for the purchase of 
transmission systems from existing owners. It is also argued that this 
approach is analogous to a hold harmless commitment for existing 
customers which may simplify the efforts of those state regulators who 
value transmission rate certainty during their conversion to retail 
choice. This approach would also reduce litigation at the Commission 
during the moratorium.
    Finally, if the rate level selected takes into account the existing 
transmission component of bundled retail power rates, it addresses the 
concern expressed by many that one deterrent to participation in RTOs 
is the fear and uncertainty that transferring retail transmission 
services from state to Commission jurisdiction leads to reduced 
revenues.
    Other commenters suggest that the essence of PBR is to set cost and 
performance benchmarks and then reward or penalize an RTO based on 
performance relative to those targets. Clearly, such an approach 
presents significant analytical challenges. Ideally, an RTO's cost and 
operating performance can be compared with other, similar entities. One 
benefit of setting such targets is that it overcomes the asymmetric 
information problem, i.e., a transmission service provider will usually 
have better knowledge of the potential efficiency gains than will 
regulators. Benchmarking performance helps reduce the information 
imbalance.\640\
---------------------------------------------------------------------------

    \640\ We note that there have been some early attempts to 
compare the relative cost and performance of ISOs in the U.S. See, 
e.g., California ISO, ``A Comparative Analysis of Operating ISOs in 
the United States'' (Oct. 15, 1998).
---------------------------------------------------------------------------

    We have carefully considered all of the comments about PBR. We 
conclude that the Commission should encourage RTOs to consider use of 
PBR, although we recognize the difficult analytical challenges that 
RTOs will face. To facilitate such consideration, we are providing 
additional specificity on PBR. We address several threshold procedural 
issues, and articulate additional design principles that should provide 
a framework for RTO consideration of PBR.

[[Page 921]]

    A first threshold issue is whether the Commission should require 
that RTOs use PBR or whether it should be voluntary. There is almost no 
support for making PBR mandatory, and we therefore will not require RTO 
filings to include PBR proposals, although we encourage such proposals.
    A second threshold issue is what types of RTOs are eligible for 
PBR. As discussed above, some commenters argue that PBR is not 
appropriate for cooperatively-owned and publicly-owned transmission 
owning utilities. Similarly, other commenters argue that PBR is 
appropriate only for profit-making RTOs. We conclude that, although the 
application of PBR may vary according to the type of RTO, there is no 
reason to limit the applicability of PBR to certain members or types of 
RTOs. The Commission welcomes RTO filings with PBR proposals from any 
source. For example, in the context of an ISO or a tiered ISO/transco 
that has been described by some commenters, the activities that 
contribute to performance may be shared between the RTO and the 
transmission owners. This does not invalidate the use of PBRs; however, 
the RTO design would simply ensure that the rewards and penalties 
associated with activities performed by transmission owners flow 
through to the owners to achieve the desired result.\641\ In addition, 
we see no impediment to the use of PBR to provide incentives for 
efficient behavior by non-profit RTOs. We note that some existing ISOs 
have in place performance incentives for some of their managers, and 
such an incentive scheme may have application for RTOs which do not own 
the transmission assets they control.
---------------------------------------------------------------------------

    \641\ For example, PJM states that it can facilitate the 
application of PBRs to its transmission owners by using the 
stakeholder process to set the performance parameters and, once the 
parameters are in place, to independently evaluate the transmission 
owners' performance and apply the PBR.
---------------------------------------------------------------------------

    A third threshold issue is how PBR proposals will be formulated and 
when they will be filed. The Commission recognizes that PBR design 
involves highly complicated issues, and that there is the possibility 
that a bad PBR proposal can result in lower quality transmission 
service, at higher costs, compared with service that might prevail 
under traditional ratemaking practices. One key element in the process 
of designing a PBR proposal would be to ensure adequate input from all 
stakeholders. We believe that the best PBR designs will emerge when all 
stakeholders have an opportunity for input, even if a filed PBR design 
does not represent full consensus. We therefore conclude that RTOs that 
wish to implement PBR need not necessarily file the PBR proposal at the 
time the RTO makes its compliance filing if more time is needed to 
negotiate among stakeholders the details of a well-designed PBR. Some 
commenters suggest that an additional consideration in allowing delayed 
filings of PBR is the need to evaluate operating experience of the RTO 
before appropriate benchmark measures for PBR can be developed.
    The Commission also believes it is appropriate to provide 
additional specificity on what constitutes good PBR design. We continue 
to endorse the regulatory standards included in the Incentive 
Regulation Policy Statement, described above. And we note that in some 
regions, certain types of PBR mechanisms may be better suited than 
others. For example, where there are already state-imposed rate 
moratoriums, continuation of such programs after RTO formation may be 
an appropriate PBR approach. Alternatively, a transmission rate 
moratorium based on the existing rate level may be appropriate for a 
transitional period during RTO formation.\642\ Similarly, in an area 
that has experience with a particular performance-based mechanism, 
extension and perhaps refinement of such a program after RTO formation 
may be the most appropriate policy.
---------------------------------------------------------------------------

    \642\ As noted infra, this is one of the pricing reforms that 
will be available for a defined transition period during which RTOs 
are being established.
---------------------------------------------------------------------------

    We encourage RTOs to file fully documented PBR proposals that are 
consistent with the amended regulatory text. PBR proposals should 
include a detailed explanation of how the PBR mechanism will work, as 
well as all of the information necessary for the Commission and all 
market participants to evaluate the benefits and costs of implementing 
the PBR mechanism.
    Based on the comments we received in this docket, as well as our 
understanding of international \643\ and state experience with 
incentive regulation, we expand on the considerations for PBR addressed 
in the amended regulatory text by offering the following additional 
principles for RTOs to consider in designing PBR proposals.
---------------------------------------------------------------------------

    \643\ We note that a PBR system that uses a variant of price cap 
regulation of the National Grid Company has been in use for nine 
years in England and Wales. More recently, the price cap has been 
combined with a separate incentive mechanism that focused on 
reducing congestion on the grid. Since this is the longest-running 
PBR targeted to grid operations, we encourage any RTO that intends 
to propose PBR to examine the strengths and weaknesses of the 
British approach.
---------------------------------------------------------------------------

    PBR should not be applied piecemeal. To the extent possible, PBR 
programs should focus on the entire operation of the RTO, rather than 
smaller parts of the operation. Commenters caution that PBR programs 
that focus narrowly, e.g., only on the cost aspects of RTO operations, 
may result in inattention by the RTO to the quality of service offered. 
Similarly, a focus on only one aspect of costs, e.g., short-run costs, 
may result in reduced costs for that single aspect, but higher total 
costs for the RTO.
    PBR should encompass both rewards and penalties. Although some PBR 
designs employ either rewards or penalties, but not both, most 
commenters suggest, and the Commission agrees, that the most effective 
and most fair designs will likely encompass both. One rationale for 
this is that it is not always clear what incentives an RTO will respond 
to, and therefore the prospect of higher revenues as well as the threat 
of lower revenues may induce an RTO to provide the best possible 
performance. An additional rationale is that under the FPA, the 
Commission is required to set rates for transmission service at just 
and reasonable levels. To the extent that rates may vary within a 
range--both up and down--as a function of RTO performance, this 
statutory requirement may be better satisfied.
    PBR rewards and penalties should create incentives for an RTO to 
make efficient operating and investment decisions, and should not 
compromise system reliability. A significant concern in any PBR 
application is the possibility that incentives will distort RTO 
decisionmaking. For example, commenters caution that an RTO may manage 
congestion through a combination of generation redispatch and 
investment in transmission infrastructure, and that poorly designed PBR 
mechanisms could distort RTO decisionmaking toward the most profitable, 
rather than the least-cost, solution, or toward an approach that 
inappropriately reduces system reliability. An additional concern is 
that PBR mechanisms may create bias with respect to the trade-off 
between investment in generation and transmission, or in siting 
generation and transmission facilities in the most efficient places on 
the grid.
    The benefits of PBR should be shared between the RTO and its 
customers. The Commission believes that as a matter of fairness, the 
efficiency gains occasioned by PBR should be shared. This will involve 
difficult analytical issues, including identifying efficiency gains,

[[Page 922]]

measuring them, and determining the effect of sharing such gains on the 
strength of the incentives faced by the RTO. The Commission does not 
believe it would be appropriate to specify the exact distribution of 
such gains, as such a decision is better left to negotiation by all 
stakeholders.
    To the extent possible, the rewards and penalties should be 
prescribed in advance based on known and measurable benchmarks. PBR 
designs involve an inevitable trade-off between simplicity and 
administrative ease on the one hand, and the potential benefits of the 
program. Although relatively simple designs such as rate freezes 
provide significant incentives for an RTO to reduce its costs, they 
produce relatively limited incentives to maintain reliability, promote 
service quality, or manage congestion. PBR mechanisms that benchmark an 
RTO's performance, either to its own historical performance, to 
industry performance indices, to some normative goal, or to a 
combination of these, may be designed to provide incentives for more 
efficient operation and investment decisionmaking. The Commission 
recognizes that designing sophisticated PBR mechanisms will be a 
significant challenge for RTOs already grappling with other development 
issues. The Commission, therefore, will make its staff available 
through our pre-filing process to work with RTOs to help identify and 
resolve issues on an informal basis prior to their filing a PBR 
proposal.\644\
---------------------------------------------------------------------------

    \644\ Alternatively, the RTO could seek guidance in a more 
formal proceeding, e.g., if an RTO files a petition for a 
declaratory order seeking approval of its PBR proposal.
---------------------------------------------------------------------------

7. Other RTO Transmission Ratemaking Reforms
    The Commission proposed in the NOPR to consider innovative pricing 
proposals for transmission owners who turn over control of their 
transmission facilities to an RTO.\645\ The types of pricing that the 
Commission proposed to consider include: a higher ROE on transmission 
plant; allowing the transmission owner to retain the benefits of cost 
saving attributable to RTO formation; acceleration of transmission cost 
recovery in rates; non-traditional valuation of transmission assets 
such as an estimate of replacement costs for assets purchased at higher 
than net original cost; and liberalized allowance of levelized or non-
levelized rate methods. The Commission proposed that transmission 
owners meet all of the requirements to become an RTO before an 
innovative pricing proposal is accepted.\646\
---------------------------------------------------------------------------

    \645\ FERC Stats. and Regs. para. 32,541 at 33,755.
    \646\ Id. at 33,756.
---------------------------------------------------------------------------

    Comments. A large number of commenters addressed the Commission's 
proposals to consider transmission pricing reforms for RTOs. About 30 
commenters expressed support, and about 30 commenters expressed 
opposition. There were also a number of comments which did not 
explicitly support or oppose this aspect of the NOPR.
    Supporting Innovative Pricing.\647\ Of the commenters that support 
innovative pricing, a common theme is that if RTO formation is to be 
voluntary, incentives are required to encourage participation.\648\ For 
example, Justice Department recommends that the positive and negative 
incentives be designed to secure universal compliance rather than have 
some utilities not participate because the advantage of continuing 
outside of the RTO is greater than the incentive to join. EEI supports 
incentives since RTO formation will probably not generate increased 
earnings for transmission owners since most of the efficiencies will be 
a benefit to others. EEI suggests that an application for RTO formation 
and incentives should include some assessment of the benefits from 
which the incentives are generated but a precise calculation of 
benefits should not be required because of the extreme difficulty in 
making such an estimate. PacifiCorp is in favor of incentives but is 
concerned that a ``case by case'' consideration of incentives may 
jeopardize their realization because customers will call for lower 
transmission rates in the short term once the RTO has been formed. 
PacifiCorp argues that a more detailed uniform policy on incentives 
``up front'' is preferred.
---------------------------------------------------------------------------

    \647\ While we used the term incentive pricing in the NOPR, this 
term is an imprecise description of the various transmission pricing 
reforms that will be addressed in this Rule, and we now describe 
these pricing reforms as innovative rate proposals. However, the 
comments sections that follow continue to use the term incentive 
because the parties used this term in their comments.
    \648\ See, e.g., Avista, TEP, Duquesne, APS, NEPCO et al., 
Florida Power Corp.
---------------------------------------------------------------------------

    On the other hand, several commenters suggest that the Commission 
should consider incentives only on a case-by-case basis. Desert STAR 
says that different RTOs may need different sets of incentives as will 
public power transmission owners. MidAmerican supports case-by-case 
consideration of incentives to join an RTO, and favors a higher ROE 
reflecting the fact that transmission is not limited to selling to a 
captive customer base in a bundled context but is serving a wholesale 
marketplace at greater risk. Duke is in favor of incentives for 
transmission expansion, but cautions that incentives should not bias 
investment and other decisions, should be considered on a case-by-case 
basis, and may not be very effective where operation is separated from 
ownership. Oregon Office is in favor of incentives for meeting all of 
the RTO characteristics and functions faster than the industry average, 
but not for average speed in accomplishing RTO formation.
    A number of commenters favor offering incentives to public 
utilities that are already members of an ISO as well as to provide 
incentives for public utilities to join an RTO. For example, PJM says 
that incentive rates should be offered to new and existing RTO members 
to reflect the benefits generated and to prevent inefficient 
consequences such as transmission owners moving from an existing ISO to 
a new RTO to receive incentive rates. PSE&G favors a correspondingly 
higher ROE and faster depreciation of transmission assets for 
transmission owners who participate in RTOs, including those who have 
already joined an existing organization. LG&E says that incentive plans 
can be useful in promoting RTO participation and that existing members 
of RTOs should be allowed to propose incentive rates as well. LG&E 
stresses that it is just as important not to enact policies on rates 
that might jeopardize revenue requirement recovery and thus act as a 
disincentive. An additional consideration is offered by PP&L Companies 
which argues that existing participants in RTOs should be allowed the 
same incentive rates as those which are just forming because the 
benefits of an existing RTO are greater than those of a start-up RTO 
not yet in operation.
    The proposed incentive addressed most frequently by commenters is 
allowing a higher rate of return on transmission assets. Georgia 
Transmission believes that higher ROEs as an incentive to voluntarily 
join an RTO is appropriate because of the benefits that participation 
would bring. NSP and others argue that ROE must be sufficient to 
attract capital and compensate utilities for the risks involved. 
Conectiv and EEI argue that the current rate of return policy should be 
modified, arguing that the DCF method gives results that are too low to 
provide adequate returns to transmission owners causing a reduction in 
building at a time when more transmission is critically needed. 
According to Conectiv, the DCF method should be abandoned or its 
application

[[Page 923]]

should be modified to account for the current industry situation and be 
more reflective of conditions in the general economy and reflect 
reasonable transmission asset lives. Cinergy, in reply comments 
contends that the record in this proceeding is sufficient to establish 
a presumption of reasonableness for higher ROEs.
    SoCal Edison does not believe that pure incentives in the form of 
ROE ``awards'' are necessary for encouraging participation in RTO but 
it does argue that higher returns may be justified on transmission 
assets controlled by an RTO because the original owner no longer has 
control over planning and expansion decisions. In addition, distributed 
generation and bypass may be found to increase risk. SoCal Edison says 
that it is very important to prevent the move to RTO control from being 
a financial loss due to Commission rate setting or because of greater 
risk and higher costs. SoCal Edison does agree with the proposal to 
allow accelerated depreciation of transmission assets to encourage 
participation.
    TXU Electric is in favor of consideration of higher ROEs for RTO 
participants and thinks it is more important to take a more global look 
at transmission ROEs in a new and uncertain industry environment where 
transmission investment is important. TXU Electric warns that it would 
be inappropriate to penalize RTO participation with reduced earning 
potential because unbundled transmission ROEs are lower than ROEs 
allowed in bundled rates. Conlon suggests that the Commission could 
allow a higher return on assets of a transco or ISO to serve as an 
incentive for IOUs to transfer ownership. Southern Company explains 
that there are major tax consequences to the sale of transmission 
assets to form a transco and recommends that the Commission find ways 
to accommodate such a transition. As to rate incentives, Southern 
Company advocates a change in the Commission's ratemaking policy in 
order to increase returns to be more commensurate with non-regulated 
businesses. Southern claims that recent court rulings support higher 
returns on transmission service.
    A number of commenters argue that participation in an RTO increases 
financial risk, and that incentives are therefore required to encourage 
RTO participation. For example, Empire District says that turning over 
control of transmission assets to an RTO increases the risk because 
someone else will control their operation, justifying higher ROEs for 
participation. PSE&G argues that a stand-alone transmission company or 
an RTO is more risky than an integrated electric utility where 
transmission was a strategic asset. FirstEnergy justifies higher ROEs 
by noting a number of sources of risk, including emergence of 
distributed generation, vulnerability of firms that are less 
diversified than integrated utilities, and quicker phase out of older 
generation plants which may result in stranding some transmission 
plants. Midwest ISO argues that RTO membership may cause a loss in 
earnings due to reduced transmission revenues, higher costs, and 
operational risks. United Illuminating believes that risk for 
transmission investment is higher for assets controlled by an RTO and 
that accelerated depreciation is warranted because transmission 
companies can no longer count on captive customers, and industry 
changes have the possibility to abandon transmission plant before its 
physical life is over. WPSC is in favor of higher ROEs for transmission 
owners who join RTOs but not as a pure incentive. WPSC's justification 
for higher ROEs would be the greater risk due to removal of pancaked 
rates, new generation options, loss of higher state returns, and new 
technologies. WPSC supports the other rate incentives as long as the 
benefits exceed the costs based on careful examination.
    Some commenters address the broad range of proposed incentives. For 
example:
     Trans-Elect argues in favor of incentives to include: 
acquisition premiums, hypothetical capital structures, higher ROE, 
accelerated recovery of costs, rate moratoriums, and expedited FPA 
section 205 and 203 approvals. Trans-Elect would limit incentives to 
those that do not harm transmission customers. It notes that PBRs would 
allow transmission owners to share in cost savings but some operating 
history may be needed before they are put in place. It argues that 
acquisition premiums may assist in the formation of independent 
transcos, and suggests that if there is a rate moratorium in place, 
RTOs should be allowed to recover acquisition premiums after the 
moratorium.
     FirstEnergy advocates flow through of cost savings to 
owners, non-traditional valuation of assets, flexibility in the use of 
levelized rate methodology, retention of hourly non-firm revenues, 
deference to management in dispute resolution, elimination of codes of 
conduct where there is structural separation, and simplification of 
filing requirements. Some of these measures should be offered on a 
limited basis to RTOs not yet meeting all of the characteristics and 
functions. Incentive plans should weigh costs versus benefits. Cal DWR 
goes further, saying that incentives should not be allowed until 
benefits are actually proven.
     Los Angeles recommends that the Commission consider 
several options for the valuation of assets transferred to an RTO in 
order to reflect the true value of the assets to native load customers. 
Selected options to explore include: an up-front acquisition premium 
used to moderate rates to native load customers, provide native load 
customers a congestion premium, or grant native load customers an 
exemption to congestion charges.
     NYPP is in favor of sufficient ROE to provide for 
expansion and accelerated depreciation to compensate for increased 
risks as opposed to a ``bonus'' type incentive to join an RTO. Its 
members contend that this type of incentive should be available to all 
transmission owners, not just the ones who meet the NOPR's 
characteristics and functions.
    A number of commenters note that incentives are needed to 
facilitate efficient expansion of transmission assets.\649\ 
Transmission ISO Participants view the incentive needed to induce new 
transmission construction as more important than incentives to 
encourage RTO formation. IPCF suggests that FERC should offer 
transmission owners incentives to expand their networks without meeting 
all of the requirements of becoming an RTO in order to reverse the 
trend against building caused by Order No. 888. Williams says that 
decisions to expand transmission facilities must be made by for-profit 
entities, must be driven by economic considerations, and the returns 
allowed must be commensurate with the greater risks today, Williams 
cautions that returns for RTO participants certainly should not be at a 
rate that results in a penalty.
---------------------------------------------------------------------------

    \649\ See, e.g., AEP, United Illuminating, PP&L Companies, NU, 
Otter Tail, NYPP, FirstEnergy, Transmission ISO Participants, 
Allegheny and Salomon Smith Barney.
---------------------------------------------------------------------------

    Opposing Innovative Pricing. Many commenters oppose the use of 
incentives for many different reasons. One common theme is that 
incentives are inappropriate because RTO participation should be 
mandatory.\650\ PJM/NEPOOL Customers argues that the Commission should 
mandate RTO formation because of the transmission owners' duty to 
operate in an efficient manner, and because transmission customers will 
likely pay the costs of the incentives. Ohio Commission

[[Page 924]]

prefers mandatory participation and questions whether the proposed 
incentives will be effective. If incentives are used, Ohio Commission 
recommends that the Commission consider evaluating which incentives 
will be effective, balancing incentives with disincentives, and 
recognize regional differences especially in arriving at a solution for 
the Midwest.
---------------------------------------------------------------------------

    \650\ PJM/NEPOOL Customers, Lincoln, TDU Systems, APPA, WEPCO.
---------------------------------------------------------------------------

    Another common theme is that the costs of incentives may well 
outweigh the benefits of RTO participation. Illinois Commission argues 
that if the Commission finds that there are benefits in RTO creation, 
they should be mandatory. According to Illinois Commission, the 
examples of incentives proposed in the NOPR, i.e., ROE enhancement, 
revaluation of transmission facilities at replacement cost, accelerated 
depreciation, and flexibility in use of levelized cost, would consist 
of money transfers to transmission owners without contributing to cost 
control or efficiency. South Carolina Authority is opposed to 
incentives or disincentives to promote RTO participation unless a 
factual determination is made that they are absolutely necessary. 
Similarly, RECA is generally opposed to incentives but would recommend 
their consideration if savings to the public are well established. RECA 
finds the rate freeze proposal the least objectionable.
    APPA advocates mandatory participation in RTOs and strongly objects 
to the use of incentives to achieve participation. It argues incentives 
would be ineffective because of the small proportion that Commission-
regulated transmission makes up of the total utility revenue compared 
to the value of transmission in maximizing generation and merchant 
revenue. To be effective, APPA argues that the cost would be so large 
that it would not be offset by the benefits of the RTO. Also, APPA 
raises the participation issue of whether to give incentives to 
existing ISO members. Seattle warns against transmission owners 
``dumping'' transmission facilities into an RTO to receive incentives 
when those particular facilities are of no benefit to the RTO being 
formed.
    Some commenters argue that it is inappropriate for the Commission 
to provide incentives for the provision of a monopoly service. 
Metropolitan argues that incentives should not be offered because many 
of the customers who pay for the incentives are the same customers who 
paid for the original transmission facilities. TDU Systems argues that 
ROEs for transmission service in an RTO is less risky because of the 
concentration of monopoly business and the lack of any regulatory gap 
since all transmission under an RTO will be regulated by the 
Commission. TDU Systems notes that transmission entities, since they 
are monopolies, should not earn the same return as firms in other 
industries. TDU Systems argues that other NOPR proposals, including 
rate freezes, accelerated recovery of costs and investment, and 
revaluation of assets, are also an inappropriate enrichment of 
transmission owners and are unneeded to attract investors. And TDU 
Systems argues that the proposal for an acquisition premium is 
troublesome because customers have already been paying for these assets 
for years. TDU Systems also suggests it will be difficult to calculate 
what level of incentives would be required to persuade a transmission 
owner to participate in an RTO and the likelihood of offering a greater 
incentive than is needed.
    Some commenters suggest that providing incentives would violate the 
Commission's statutory requirement to set rates at just and reasonable 
levels. NRECA believes that transmission owners should not be rewarded 
for unjust conduct with incentives and that the Commission should rely 
on standard cost-of-service based rates. TAPS, which favors mandatory 
RTO formation, argues that incentives are unnecessary and could nullify 
the benefits of electric industry restructuring. TAPS argues that 
incentive rates, including each of the examples suggested in the NOPR, 
would violate FPA's requirement for just and reasonable rates because 
they do not reflect the cost of providing transmission service. TAPS 
does recommend that the Commission remedy unintended disincentives such 
as utilities' fear of the unknown. UAMPS also favors mandatory 
participation, and argues that incentives would unfairly raise 
transmission costs to the benefit of monopoly transmission owners. 
UAMPS also argues that it is not feasible to divide the benefit of RTO 
participation before these benefits are even known. In response to the 
comments of several IOUs, UAMPS argues that the claim that stand-alone 
transmission companies are more risky is unsubstantiated and should be 
heard in another proceeding. NASUCA argues that EEI and others are 
incorrect in saying that the DCF method does not produce reasonable 
results. According to NASUCA, the DCF method takes explicit account of 
the transmission owners' risk and the realities of the current 
regulatory climate.
    Some commenters suggest that incentives will not necessarily 
increase RTO participation, or will not necessarily produce the 
benefits which the NOPR describes. For example, ICUA notes that 
incentives cannot be relied upon to achieve participation by all 
necessary utilities. WPPI opposes incentives to participate in RTOs 
citing the RTO activity that has already taken place without incentives 
and the contention that the Commission should designate boundaries and 
require participation within one year.
    Wyoming Commission does not agree that increasing the ROE will be 
sufficient to encourage more transmission building. According to 
Wyoming Commission, low building activity may be attributable to 
difficulty in meeting siting requirements, uncertainty related to 
retail access and native load, and competition for more localized 
generation. Wyoming Commission does not think that the Commission 
should rush too quickly into some innovative ratemaking before the 
industry has committed to making RTOs work as planned. And the Wyoming 
Commission suggests that a higher ROE for transmission investment may 
discourage a balanced consideration of options.
    A number of commenters generally opposed incentives, believing that 
sanctions or penalties against public utilities which do not join RTOs 
is superior to providing incentives. NASUCA argues that mandates or 
disincentives for not joining at the time of merger or market-based 
rate requests should be used rather than incentives. Incentives would 
not be cost based and would therefore make rates unjust and 
unreasonable. As to specific incentive proposals, NASUCA says that 
using replacement cost for transferred assets would allow higher rates 
than necessary as an incentive and would charge customers for assets 
they have already paid for. Such incentives could set off a 
transmission sell-off in anticipation of an adjustment and some 
companies may refuse to form transcos until they were granted the same 
adjustment as any other company. NASUCA is opposed to accelerated 
depreciation of assets for similar reasons. NASUCA also states that 
incentive rates could harm electric competition by increasing 
transmission costs. And Big Rivers states that the incentives proposed 
in the NOPR are inappropriate for rural electric cooperatives.
    Other Comments. A few commenters did not take an explicit position 
on the use of incentives, but made general comments on the Commission's 
proposals. For example:
     Cal ISO is more concerned that there not be disincentives 
to RTO

[[Page 925]]

participation than offering incentives. In particular, Cal ISO points 
out the disincentive created by the Commission's annual fee policy, 
from which temporary relief was granted \651\ but a permanent solution 
is needed.
---------------------------------------------------------------------------

    \651\ PJM Interconnection L.L.C., 88 FERC para.61,109 (1999).
---------------------------------------------------------------------------

     New Century recommends against the use of ``remedial 
measures'' to encourage participation such as the suspension of market-
based rate authority, denial of merger authority, and denial of non-
pancaked rate access to RTO facilities.
     Entergy says that the NOPR's statements on incentives are 
vague and would cause too much regulatory uncertainty. Entergy asks the 
Commission to provide more explicit provisions as to what incentives 
would be approved.
     Canada DNR is concerned that Canadian transmission owners 
not be placed at a disadvantage for non-participation in an RTO in 
terms of incentives and disincentive.
     SRP supports incentives as long as they are applied to 
both public power entities and investor owned companies equitably.
     Metropolitan contends that it would not receive much 
benefit from any incentives offered to RTOs because it is a public 
entity and because its asset base is so heavily depreciated. However, 
replacement cost methodology could be of use in mitigating cost shifts 
from rolling in higher costs of other utilities.
    Commission Conclusion. As noted earlier, the NOPR and the comments 
use the term incentive pricing as a label for the transmission pricing 
reforms that we raised for discussion. Certainly, good pricing affects 
behavior. But good pricing also achieves a valuable goal, in terms of 
competition, system expansion, or efficient practices that benefit more 
than the transmission owners or the RTO. In this section we provide 
greater specificity with respect to certain transmission pricing 
mechanisms that may be appropriate for RTOs. These mechanisms were 
described in the NOPR or otherwise proposed by commenters, and are 
included in the amended regulatory text.\652\ We emphasize that we do 
not intend this policy guidance to be interpreted as a Commission 
regulatory requirement for a specific transmission pricing method, nor 
should it be interpreted as a guarantee that the Commission will 
approve any particular innovative pricing proposal. We emphasize that 
all innovative pricing proposals filed by RTOs must be fully and 
adequately supported in accordance with this Final Rule and the 
regulatory text. We believe that we are providing sufficient guidance 
for RTOs to make critical decisions with respect to transmission 
pricing policies. If industry participants believe that further 
guidance from the Commission is needed to resolve transmission pricing 
issues, they may request such guidance through requests for declaratory 
orders or further rulemakings.
---------------------------------------------------------------------------

    \652\ Note that these mechanisms are discussed below on a 
thematic basis, although the regulatory text lists them on an 
individual basis.
---------------------------------------------------------------------------

    As discussed earlier, transmission pricing reform is needed as a 
result of the rapid restructuring of the industry that is underway, 
particularly with respect to changes in the ownership and control of 
transmission assets, and changes in the transmission services being 
provided in competitive generating markets. As a result of these 
changes, and consistent with a number of commenters' arguments, we have 
concluded that the Commission, at a minimum, needs to mitigate various 
``disincentives'' that may prevent transmission owners from efficiently 
operating their systems. Commenters cite to the potential that 
transmission owners will earn lower returns for providing unbundled 
transmission service than they earned for providing bundled service, 
even though risks associated with transmission ownership have 
increased. Commenters suggest a number of sources of increased risk. 
One source is the potential for bypass of transmission assets due to 
distributed generation and the phasing out of older generators from 
service. Other sources are directly related to RTO formation. For 
example, some commenters assert that stand-alone transmission companies 
(e.g., transcos) are riskier because they have a less-diversified 
portfolio of assets than a vertically integrated utility. Other 
commenters argue that participation in an RTO that is an ISO is 
inherently riskier, suggesting that increased risk comes from ownership 
of transmission assets that are ceded for purposes of operational 
control to another, non-affiliated entity.
    Other commenters argue that a reevaluation of transmission pricing 
is needed because it is absolutely critical that the transmission grid 
support competitive generating markets, and the only way that the 
Commission can ensure this will happen is to pursue pricing policies 
that encourage it. Some commenters suggest that because the 
contribution of transmission to total costs of energy is relatively 
small\653\ overinvestment in transmission will not significantly affect 
delivered electricity prices. Further, the Commission should be much 
more concerned about underinvestment, not overinvestment, in the 
transmission grid.\654\ Stated another way, an efficient transmission 
grid is a prerequisite to achieving competitive generating markets, and 
the potential benefits for consumers far exceed any limited 
overinvestment that may occur on transmission service. A related 
argument is that efficiency benefits of improved transmission service 
will be captured by producers and customers of generation, not 
transmission providers; therefore, greater incentives for RTOs to 
provide good transmission operations and efficient investments in the 
grid are warranted.
---------------------------------------------------------------------------

    \653\ For example, Salomon Smith Barney, citing to an article by 
Leonard Hyman notes that the direct, total osts of transmission 
service represents about six to seven percent of the average 
customer's bill, and raising transmission prices even as high as 25 
percent in order to attract capital adds only two percent to the 
overall electric bill.
    \254\ Professor Joskow points out that the external factors, 
such as licensing requirements, the need for rights of way, and 
NIMBY (i.e., ``not in my backyard'') opposition to transmission 
expansion already places significant constraints on overinvestment 
in major new transmission projects.
---------------------------------------------------------------------------

    The NOPR sought comments on several procedural issues related to 
transmission pricing reform and incentives. One issue was whether these 
pricing reforms should be available to participants of existing ISOs, 
or be available only to transmission owners that join RTOs as a result 
of the Commission's RTO initiative. We have concluded that members of 
an existing ISO organization that satisfy the minimum RTO requirements 
in the regulatory text should be allowed to seek transmission pricing 
reform as newly formed RTOs, so that they can avail themselves of the 
same incentives for efficient operation of and investment in the 
transmission grid. Furthermore, we believe that the Commission's 
approach to evaluating innovative transmission reforms should be 
neutral with respect to the organizational structure of the Applicant, 
so that RTOs that own transmission assets as well as RTOs that do not 
own transmission assets would be equally eligible for such ratemaking 
treatments.
    Another issue is whether the Commission would prescribe which 
transmission pricing reforms it would accept and which it would not 
accept, or whether the Commission would consider such proposals on a 
case-by-case basis. We conclude that a case-by-case evaluation of 
transmission pricing

[[Page 926]]

reform proposals is appropriate, given that such proposals are not 
generic in nature, and a proposal may be appropriate in some RTO 
circumstances but not in others. However, the Commission believes some 
further specificity on transmission pricing reform is warranted to 
provide industry participants with the Commission's evolving views, as 
RTOs consider the appropriateness of various reform measures.
    Therefore, we provide greater specificity on three transmission 
pricing reform measures: (1) ROE; (2) levelized rates; and (3) 
accelerated depreciation and incremental pricing for new transmission 
investments. We note that some of these measures may be useful only as 
transitional devices that may be necessary to spur the prompt creation 
of RTOs and, therefore, we intend to offer these pricing options only 
for a defined period of time, as detailed later in this Final Rule. On 
the other hand, other pricing reforms may be useful as permanent 
features, and will not be limited only to the period during which RTOs 
are forming. Finally, while certain of these innovative pricing 
proposals may be more helpful to one RTO structure than another (e.g., 
ISO vs transco), we do not believe that any of these pricing proposals 
would be incompatible with any particular structure adopted by RTOs.
    a. Return on Equity (ROE). More commenters focused on ROE-based 
proposals than any other type of transmission pricing reform. These 
commenters make two main points. One argument is that higher ROEs will 
be demanded by the market as a matter of course as the industry 
restructures and the risk of transmission business increases, and the 
Commission must allow higher ROE to reflect participation in RTOs. A 
second argument is that joining an RTO adds another level of risk that 
warrants a specific adjustment to ROE (e.g., going to the high end in 
the range of reasonable ROE, or a specific basis point 
adjustment).\655\
---------------------------------------------------------------------------

    \655\ Some commenters recommend abandoning the DCF method of 
calculating ROE entirely. We are not adopting that recommendation.
---------------------------------------------------------------------------

    As discussed above, commenters urge the Commission to provide 
flexibility in allowing ROE-based programs for RTOs. Many of these 
commenters specifically urge the Commission to ensure that there are 
sufficient incentives for an RTO to make needed investments in 
transmission infrastructure. On the other hand, a number of commenters 
oppose ROE-based programs on the grounds that they constitute a 
``bribe'' for utilities to provide service that they are statutorily 
required to provide.
    We believe that there are a number of issues surrounding ROE that 
must be addressed by the Commission. For example, we believe that 
allowing an RTO to propose a formula rate for determining return on 
equity is consistent with our view that risks and rewards for 
transmission owners should reflect market-like forces to the extent 
possible. Allowing a formula rate of return would decouple a 
transmission owner's earnings from its own equity valuation, and would 
tie it more to external standards such as industry-wide performance. 
Such an approach is also consistent with the benchmarking that may 
occur under PBR.
    We also agree that the risk profile of the transmission business is 
changing as the industry restructures, and that it may vary as a 
function of the structure each transmission company elects. For 
example, the risk associated with owning facilities that are leased for 
a sum certain to another entity operating an RTO may be different from 
the risk associated with operating a stand-alone transco that is facing 
a significant expansion program. We therefore conclude that ROE-based 
initiatives--as well as other ratemaking reforms discussed below--may 
be applicable to all types of RTOs, without regard to organizational 
structure.
    We further recognize that historical data typically used to 
evaluate ROEs may not be reliable since it reflects a different 
industry structure from the one that exists recently. And we believe 
that as patterns of transmission ownership and control evolve, new 
approaches to compensating transmission owners for different capital 
structure mixes may be warranted, including allowing a transmission 
owner to seek a return on invested capital, independent of its exact 
capital mix.\656\ As noted above, we are willing to consider 
moratoriums tied to the rates the transmission provider earns on 
transmission assets with respect to bundled retail power sales, and the 
moratorium option may be tied to the existing transmission rate level, 
or to the existing return on equity.\657\
---------------------------------------------------------------------------

    \656\ As noted infra, this is one of the pricing reforms that 
will be available only for a defined transition period during which 
RTOs are being established.
    \657\ As noted infra, moratoriums are among the pricing reforms 
that will be available for a defined transition period during which 
TROs are being established.
---------------------------------------------------------------------------

    Finally, we agree that the uncertainty associated with the 
transition of the industry, and in particular participation in RTOs, 
may increase risks in the short-run. Certainly, our goals have not 
changed, which are to ensure that customers have access to 
nondiscriminatory service at just and reasonable rates, and that 
transmission owners have an opportunity to earn a reasonable rate of 
return on their investment. We recognize that in this era of rapid 
change, new approaches to setting ROE may be needed to implement that 
standard. We therefore invite RTOs to submit proposals for ROE-based 
programs that are in conformance with these new approaches.
    We note that pricing reforms involving ROE would clearly be 
compatible with all types of RTO structures that involve a 
determination of return on equity on transmission rate base, e.g., 
transcos, ISOs, or tiered organizational structures.
    b. Levelized Rates. A number of commenters argue that the 
Commission should allow RTOs to adopt levelized rates. A levelized rate 
is designed to recover all capital costs through a uniform, nonvarying 
payment over the life of the asset, just as a traditional home mortgage 
payment does. The Commission, has held in a number of recent 
proceedings that both levelized and nonlevelized rates can produce 
reasonable results, depending on the circumstances.\658\ The Commission 
stated in these cases that where a utility proposes to switch from a 
nonlevelized net plant rate design method, ``[i]n supporting such a 
switch, a utility must prove that its proposed method is reasonable in 
light of its past recovery of capital costs using a different method.'' 
\659\
---------------------------------------------------------------------------

    \658\ See, e.g., American Electric Power Service Corp., Opinion 
440, 88 FERC para. 61,141 at 61,441-42 (1999) (AEP); Allegheny Power 
Service Corp., Opinion 433, 85 FERC para. 61,275 at 62,117 (1998); 
Kentucky Utilities Co., Opinion 432, 85 FERC para. 61,274 at 62,100-
03 (1998) (KU).
    \659\ See AEP, 88 FERC at 61,441-42.
---------------------------------------------------------------------------

    The Commission believes that levelized rates are preferable in an 
RTO environment because all customers, regardless of when they take 
service, face the same price. Also, given a depreciated investment 
base, levelized rates based on existing investments will be higher than 
non-levelized rates and will address concerns that RTO formation will 
decrease revenues.
    The principal objection to allowing levelized rates for RTOs is 
that it may raise RTO transmission rates in the short-run. The 
Commission has been reluctant outside the RTO context to approve 
switches from or to levelized rates proposed by public utilities under 
traditional cost-of-service ratemaking because of the opportunities 
that switching may provide for utilities to

[[Page 927]]

over recover transmission costs. However, consistent with our 
discussion above of how market restructuring may require innovation in 
transmission pricing, we believe that levelized rates may be 
appropriate in circumstances, as here, where an RTO reflects a fresh 
start with respect to the provision of transmission services, and 
potentially the customers for those services. This is especially true 
in cases where RTO formation occurs coincident with market 
restructuring, such that the transmission customers of the RTO may be 
significantly different than the traditional, captive customers, that 
formerly took transmission service. We therefore conclude that the 
Commission should allow increased flexibility for RTO proposals that 
include ratemaking practices based on levelized rates. Clearly, this 
pricing reform, which relates to the method used to compute the 
transmission revenue requirement in the first instance, is compatible 
with any type of RTO structure, e.g., transco, ISO, or tiered 
structure.
    c. Accelerated Depreciation and Incremental Pricing for New 
Transmission Investments. While a number of commenters have suggested 
accelerated depreciation as a transmission pricing reform that should 
be considered, these arguments are premised on the possibility that 
transmission costs will be stranded by changes in the industry, such as 
bypass of portions of the transmission system. We think that these 
concerns are speculative at this point in the industry's restructuring. 
For example, we are not convinced that the problem of stranded 
transmission assets is anywhere near the level of concern that stranded 
generating assets represents.\660\ In any event, should certain limited 
transmission facilities become stranded, nothing prevents proposals to 
recover prudent costs under traditional ratemaking policies.
---------------------------------------------------------------------------

    \660\ See Order No. 888, wherein the Commission allows recovery 
of stranded costs (primarily generation related) only when they are 
unrecoverable from customers that depart the system, and only upon a 
definitive showing that the utility had a reasonable expectation of 
continuing to serve the customer after the customer's departure.
---------------------------------------------------------------------------

    We will, however, make a distinction between accelerated 
depreciation for existing transmission assets, and accelerated 
depreciation for new transmission facilities. While we will not bar 
proposals of this type for existing assets, we cannot give any 
encouragement to them in the Final Rule. On the other hand, we believe 
that it is appropriate for the Commission to provide those willing to 
make new transmission investments with the flexibility to propose that 
such assets follow non-traditional depreciation schedules. The purpose 
of providing such flexibility is to remove disincentives for the 
construction of new facilities. We think such flexibility is warranted 
because the fundamental nature of transmission investment may be 
changing with respect to the entities that will make investments in the 
transmission system in the future and who pays for the new transmission 
facilities. Furthermore, given the rapid changes in market structure 
and dynamics that have occurred and will likely continue, we are not 
certain that traditional determinations of the economic life of new 
transmission facilities remain appropriate.
    In addition, we believe it is appropriate for the Commission to 
provide flexibility for pricing of new facilities, such that proposals 
for pricing of new facilities that combine elements of incremental 
prices with embedded-cost access fees will be considered. Although we 
are concerned that such ratemaking practices have the potential to lead 
to higher prices for new transmission services, and also potential to 
lead to overinvestment in transmission facilities, e.g., where 
generation redispatch could accomplish the same objective at lower 
cost, we believe that such practices, if carefully constructed, will 
create appropriate incentives for efficient investment in new 
transmission facilities. We also believe that this pricing reform will 
be attractive to all types of RTO structure, e.g., transcos, ISOs, or 
tiered structures. It may also be used by any RTO that chooses to rely 
on third parties to construct new facilities.
    d. Acquisition Adjustments. A number of commenters suggest that the 
Commission adopt new policies for acquisition adjustments that would 
provide assurances to purchasers of transmission facilities that 
acquisition premiums would be recoverable through transmission rates. 
We do not adopt this suggestion in this Final Rule.\661\
---------------------------------------------------------------------------

    \661\ See Minnesota Power & Light Company and Northern States 
Power Company, 43 FERC para. 61,104 at 61,342 (1988), for a 
discussion of the Commission's existing policies with respect to the 
ratemaking treatment for acquisition premiums. See also Duke Energy 
Moss Landing LLC, et al. 83 FERC para. 61,318 (1998).
---------------------------------------------------------------------------

8. Additional Ratemaking Issues
    A number of comments on ratemaking issues address topics not 
specifically enumerated in the NOPR.
Comments
     Williams, CSU, Alliance Companies and WPSC encourage the 
Commission to consider rate designs based on mileage or network usage.
     Great River, NCPA and IMPA raise the concern that 
cooperatives and public power entities need assurance that they will 
receive full customer credit and compensation as was explicitly stated 
in Order No. 888. SoCal Edison claims that full compensation will be 
forthcoming and will not be a problem.
     Ohio Commission recommends that a tariff for border 
transactions (between RTOs) be implemented that makes the market over 
the combined regions seamless to persuade some regional organizations 
to combine.
     PPC notes that IndeGO ran into a problem with developing 
rates for combined systems with very different levels of quality and 
cost, and that systems at a position of lower quality should be 
required to meet combined system standards at their own cost.
     Puget argues that RTO rates must provide for the 
collection of stranded costs.
     PSNM sees a problem with load-side generation customers 
who do not have to pay their fair share of total system transmission 
costs.
     Powerex objects to the proposal to segment companies' 
service areas into sub-zones for pricing purposes.
     Alliance Companies and AEP favor the flexibility in RTO 
rate filings that would allow companies to make proposals that reflect 
market forces.
     Alliant Energy is concerned that RTO structures promote 
workable markets and that transmission rates be permitted to include a 
fair accounting of RTO start-up costs.
     East Texas Cooperatives recommends that RTO pricing 
structures adequately compensate small transmission owners who join the 
RTO, creating an incentive to join and be a more equitable system.
     Georgia Transmission says that ratemaking for RUS 
borrowers must take into account the requirements of any RUS loans. In 
addition, Georgia Transmission recommends that the cost of RTO 
formation be allowed in RTO rates.
     Metropolitan, Cal DWR, and SoCal Cities favor the use of 
time-of-use pricing or off-peak rates for transmission.
     Oregon Office recommends load-based fees for transmission 
rather than volume based charges.
     IMEA argues that the RTO start-up and administrative costs 
should be

[[Page 928]]

allocated to all customers including bundled native retail load. In 
contrast, LG&E notes that if native load is assigned RTO administrative 
costs there may be under recovery because of retail rate freezes.
     Industrial Customers argue that assets used for remote 
generation should be excluded from the RTO.
     Merrill Energy says that the incremental pricing of new 
transmission upgrades prevents expansion because customers are 
unwilling to pay.
     NERC is concerned about the recovery of costs related to 
reliability-related generators.
     NRECA is concerned about compensation by an RTO for low-
use transmission facilities owned by cooperatives, because large 
transmission owners are opposed to revenue sharing. NRECA notes that if 
a cooperative joins an RTO, transactions for all will increase and 
there is more to share. Also, there should be protection for joint use 
agreement income.
     Project Groups says that pricing must facilitate entry and 
usage by efficient, environmentally benign resources. Grid access 
barriers to these resources need to be eliminated. NMA/WFA/CEED respond 
by saying that the policies that Project Group objects to are equitable 
overall.
     Seattle argues that hub and spoke pricing should be used 
and discrete inter-regional tariffs are needed.
     NWCC notes that the characteristics of wind-produced power 
presents problems fitting into an RTO pricing arrangement and says that 
wind power works best with energy-based pricing systems.
     Detroit Edison advocates a two-part pricing structure 
similar to that proposed by the Alliance RTO. It includes a local rate 
and a regional rate. To encourage participation, Detroit Edison 
proposes that the Commission allow RTOs to develop market-based 
transmission pricing methodologies.
    Commission Conclusion. Commenters raise a number of important 
ratemaking issues that must be considered in the establishment of RTOs. 
We clarify that the reasonable costs of developing an RTO may be 
included in transmission rates. Other issues are at a level of detail 
and specificity that we do not believe should be resolved in this Final 
Rule. Therefore, these issues will be considered as they apply to 
individual RTO proposals on a case-by-case basis.
9. Filing Procedures for Innovative Rate Proposals
    We shall 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. We shall also require 
applicants to 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, 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. Thus, if the Commission 
approves an RTO rate proposal involving, e.g., a rate moratorium, 
unless otherwise ordered, the moratorium would end on or before January 
1, 2005. We are limiting these rate proposals for a defined period 
during the formative stage of RTOs because, while either may be 
appropriate as transitional rate mechanisms, they do not promote long-
term efficiency through rate design. In addition, the limited duration 
for these rate treatments will encourage the earliest possible filings, 
while at the same time giving some flexibility to those filings that 
may be delayed.

H. Other Issues

1. Public Power and Cooperative Participation in RTOs
    In the NOPR, the Commission stated its objective of encouraging all 
transmission owning entities including transmission owned or controlled 
by public power entities and cooperatives, including Federal Power 
Marketing Agencies (PMAs), Tennessee Valley Authority (TVA), and other 
state and local entities to place their transmission facilities under 
the control of an RTO.\662\ To this end, we expressed an expectation 
that public power entities would fully participate in the collaborative 
process for forming RTOs.\663\ In addition, we noted that some public 
power entities filed open access tariffs with the Commission and others 
are participating in ISOs and other regional institutions. The 
Commission, however, is aware and concerned that public power entities 
face several difficult issues regarding RTO formation and 
participation.\664\
---------------------------------------------------------------------------

    \662\ FERC Stats. and Regs. para. 32,541 at 33,756-57.
    \663\ Id. at 33,757.
    \664\ See id.
---------------------------------------------------------------------------

    The first issue is the Internal Revenue Service (IRS) Code 
``private use'' restrictions on the transmission facilities of public 
power entities financed by tax-exempt bonds. We noted that IRS 
temporary regulations may allow facilities financed by outstanding tax-
exempt bonds to be used to wheel power in accordance with Order No. 
888, but that these temporary regulations may not allow the issuance of 
additional tax-exempt bonds for expanded transmission or permit 
transfer of operational control of existing transmission facilities 
financed by tax-exempt bonds to a for-profit transco.\665\ The 
Commission asked for comments on the extent to which IRS Code 
restrictions may limit the transfer of operational control or other 
forms of control, or ownership of public power transmission facilities 
to a for-profit transco or other forms of an RTO.
---------------------------------------------------------------------------

    \665\ Id.
---------------------------------------------------------------------------

    The Commission also requested comments on state and local charter 
limitations, prohibitions on participating in stock-owning entities, 
the current policies of various local regulatory entities that affect 
or impede full public power participation in RTOs and legal 
restrictions or other considerations regarding PMAs that prevent their 
participation in RTOs. We questioned whether the Commission should 
consider some forms of associate membership or participation and other 
special accommodations in order for public power entities to overcome 
obstacles to RTO participation.\666\
---------------------------------------------------------------------------

    \666\See id.
---------------------------------------------------------------------------

    Comments. Most commenters support the Commission's position that a 
properly formed RTO should include all transmission owners, including 
cooperatives and public power, in a specific region.\667\ As EEI notes, 
public power participation will enhance the reliability and economic 
benefits of an RTO. Furthermore, some commenters argue that in some 
areas of the country, especially in the Northwest and Southeast, RTO 
formation may be impractical without public power participation.\668\ 
Virtually all commenters recognize that regulatory and legal 
restrictions exist that may impede public power and cooperative 
participation in RTOs. EEI, SERC and Metropolitan argue that the best 
way to

[[Page 929]]

facilitate non-jurisdictional utility participation in RTOs is for the 
Commission to avoid a ``one-size-fits-all approach'' and to provide 
flexible rules in order to accommodate the unique needs of public power 
entities.
---------------------------------------------------------------------------

    \667\ See, e.g., Oglethorpe, Allegheny, Montana Power, CREDA, 
Tallahassee, Arkansas Cities, PPC, California Board, Industrial 
Customers, Entergy, BC Hyrdo, Powerex, Aluminum Companies, MEAG, 
Arizona Commission, Nevada Commission, East Texas Cooperatives, 
Lincoln, NPPD, Wyoming Commission, Georgia Transmission, WPSC, PGE, 
Montana Commission, SMUD, Cal ISO, MLGW, Loveland Customers, NASUCA, 
Duke, LG&E, CP&L, South Carolina Authority, STDUG, NCPA, PP&L 
Companies, Desert STAR, PG&E and EEI.
    \668\ See, e.g., EEI, Snohomish, MLGW, Loveland Customers, 
Montana Commission, Wyoming Commission, Aluminum Companies, 
Industrial Customers and Powerex.
---------------------------------------------------------------------------

    Section 141 of the IRS code imposes limitations on the use of non-
governmental entities of public power facilities financed with tax 
exempt bonds. These private use limitations restrain the form and 
extent of participation by public power systems in RTOs. The key 
private use limitation that is material to RTO participation is a bar 
on the sale of the output of facilities financed with tax exempt debt 
to non-governmental entities on terms not available to the general 
public. Commenters note that in January 1998, the IRS issued temporary 
regulations relating to the application of the private use rules to 
public power entities that provide some relief for transmission 
facilities. These temporary regulations permit issuers of outstanding 
tax exempt bonds to offer open access transmission services and 
competitive access to distribution systems, and to join RTOs, provided 
that certain conditions are met, particularly that the facilities 
continue to be owned by the municipal entity. The temporary 
regulations, however, do not provide the same relief to issuers of new 
tax exempt bonds. Many commenters assert that the temporary regulations 
will expire in January 2001 and that these regulations are incomplete 
and not permanent.\669\ LPPC notes that the ability of issuers to 
continue to rely on the temporary regulations after expiration is 
unclear and therefore, issuers taking actions permitted under the 
temporary regulations risk having tainted the tax-exempt status of 
their bonds on the expiration of the regulations.
---------------------------------------------------------------------------

    \669\ E.g., Los Angeles, SoCal Cities, LPPC, APPA, Tacoma, NCPA, 
SRP, TAPS, EEI, NPPD and East Texas Cooperatives.
---------------------------------------------------------------------------

    Commenters offer varying solutions to the ``private use'' 
restriction problem. Many commenters urge the Commission to actively 
attempt to influence the IRS and Congress to remove and/or mitigate the 
tax impediment.\670\ SRP also recommends that the Commission require 
all RTOs to demonstrate that they have made a good faith effort to 
reduce barriers to participation and to accommodate legal restrictions 
faced by potential participants. Arkansas Cities proposes a 
transitional grandfathering of existing tax-exempt bonds. Arkansas 
Cities notes that such legislation is pending in Congress and is 
identified as the Bond Fairness and Protection Act (BFPA). Arkansas 
Cities states ``that if enacted, the BFPA would clarify tax laws and 
regulations governing tax exempt bonds so that publicly owned utilities 
would be able to participate in the development of competitive electric 
utility markets.'' \671\ Duke asserts that the leasing of transmission 
facilities to an RTO is a viable option. Moreover, LPPC states that 
public power entities have to be allowed to participate in a way that 
permits them to retain sufficient operational control of their 
transmission systems to stay within the private use limitations. In 
addition, LPPC, Snohomish, Arkansas Cities and East Texas Cooperatives 
argue that public power entities need an opt-out provision if their tax 
exempt status is threatened. TEP recommends that the final rule contain 
a template for addressing how transactions can be administered if they 
involve the use of tax exempt facilities. TEP proposes that (1) an RTO 
should operate in a manner that either preserves the tax exempt status 
of such facilities or provides compensation to the facilities' owner to 
the extent it incurs economic harm; and (2) that an RTO should develop 
specific rules governing the operation and administration of tax-
exempted financed facilities.
---------------------------------------------------------------------------

    \670\ See, e.g., EEI, TAPS, SRP, Georgia Transmission, Arkansas 
Cities, Nevada Commission, PP&L Companies, TANC, Desert STAR, NCPA, 
Montana-Dakota Enron/APX/Coral Power and Tallahassee.
    \671\ See Reply Comments of Arkansas Cities at 6.
---------------------------------------------------------------------------

    NRECA details the obstacles confronting cooperatives including the 
requirement that in order to maintain tax exempt status under Section 
501(c)(12) of the IRS Code, at least 85 percent of a cooperative's 
income must come from the cooperative's members. If such member-derived 
revenue does not equal at least 85 percent of total revenue, then a 
cooperative would lose its tax-exempt status. Georgia Transmission 
argues that there is a real risk that participation in an RTO could 
result in a cooperative losing its tax exempt status if the revenue 
received from the RTO (assuming the RTO is not a member of a 
cooperative) exceeds 15 percent of the cooperative's total income. The 
revenue received from the RTO would stem from revenue attributed to use 
of the cooperative's transmission facilities controlled by the RTO.
    One remedy to this problem, suggested by AEPCO and Wolverine 
Cooperative, is to increase an RTO's compensation to the cooperative to 
include a gross-up of net margins to cover the income tax expense. 
Under this approach, the RTO would pay the cooperative the full revenue 
requirement for the transmission facilities, including any other taxes. 
East Kentucky proposes that a conduit or a pass-through relationship 
between the RTO and the cooperative would satisfy the IRS restrictions 
and allow a cooperative to maintain its member-derived character. 
According to East Kentucky, the RTO would act as an agent for the 
cooperative by collecting the transmission revenues and holding these 
revenues in a trust on behalf of the cooperative. Furthermore, Georgia 
Transmission suggests that the Commission allow a cooperative to leave 
an RTO if it appears that it may lose its tax exempt status because of 
the level of RTO and other non-member revenue it expects to receive in 
a given year.
    Another impediment to public power participation in RTOs is 
mortgage restrictions. AEPCO notes that under the terms of a typical 
RUS mortgage, either transfer of control of transmission assets to an 
RTO or a sale, unless authorized by RUS, would be an event of default. 
East Texas Cooperatives argues that the Commission should require all 
RTOs to accommodate mortgage restrictions by allowing cooperatives to 
retain control of their facilities until the mortgage restriction is 
lifted or a creditor or RUS approves the transfer. In its comments, RUS 
recognizes that development of RTOs may offer considerable benefits to 
RUS borrowers, and RUS states that it is exploring means to facilitate 
borrower participation consistent with the Rural Electrification Act 
and RUS's fiduciary duties to the U.S. Treasury and taxpayers.
    According to several commenters,\672\ many public power entities 
operate under explicit state constitutional restraints with respect to 
their ability to participate in the ownership of a privately-owned 
RTO.\673\ Further, some state constitutions include restrictions on the 
use of public funds.\674\ Several states, however, expressly authorize 
public power entities to join with other

[[Page 930]]

public entities in the ownership and operation of electric transmission 
facilities.\675\ In addition, state and local laws impose additional 
restrictions on the activities and operations of public power entities 
that could affect the operations of any RTO in which they hold an 
ownership interest. For example, some laws prohibit the sale or lease 
of transmission facilities to a for-profit entity.\676\
---------------------------------------------------------------------------

    \672\ See, e.g., LPPC, NPRB, Snohomish, Clarksdale, MEAG and 
CAMU.
    \673\ For example, the Nebraska Constitution provides: ``No 
city, county, town, precinct, municipality or other sub-division of 
the state, shall ever become a subscriber to the capital stock, or 
owner of such stock, or any portion or interest therein of any * * * 
private corporation or association.''
    \674\ For example, the Colorado Constitution states: ``Neither 
the state, nor any county, city, town, or township shall lend or 
pledge credit or faith thereof, directly or indirectly, in any 
manner to, or in aid of, any person, company or corporation, public 
or private, for any amount, or for any purpose whatever; or become 
responsible for any debt, contract or liability of any person, 
company or corporation, public or private, in or out of the state.''
    \675\ For example, Washington law provides: ``Any two or more 
[Washington] cities or public utility districts or combinations 
thereof may form an operating agency * * * for the purpose of 
acquiring, constructing, operating, and owning plants, systems and 
other facilities and extensions thereof, for the generation and 
transmission of electric energy and power.''
    \676\ Nebraska law provides that: ``[T]he plant, property, or 
equipment of a public power district shall never * * * by outright 
sale, or lease, become the property or come under the control of any 
private person, firm, or corporation engaged in the business of 
generating, transmitting, or distributing electricity for profit.'' 
Nebraska Rev. Stat. Sec. 70-646.01.
---------------------------------------------------------------------------

    In states in which laws allow a public utility district to sell or 
lease its transmission facilities to an RTO, the laws impose 
requirements on such sale or lease. For instance, Washington law would 
require the property to be offered in a competitive bidding process, 
and no sale could occur without voter approval.\677\ Furthermore, LPPC 
notes that state and local laws in California, Florida, Nebraska, and 
Texas would require the approval of the City Council, the public 
utility commission, the governing board, or other governmental 
authority before a transfer of facilities could occur. CAMU and NPPD 
also state that many municipals and power authorities have statutory 
authority to condemn property and that it is unlikely that this eminent 
domain authority can be delegated to an RTO.
---------------------------------------------------------------------------

    \677\ See LPPC at 17.
---------------------------------------------------------------------------

    Enron/APX/Coral Power notes that an unwillingness to participate in 
an RTO for commercial reasons should render non-jurisdictional 
transmission owners ineligible for RTO services and savings. Moreover, 
Duke argues that public power must take the lead in resolving these 
issues for themselves. Duke notes that investor-owned utilities have 
overcome numerous obstacles to become RTO participants. Furthermore, 
Enron/APX/Coral Power argues that public power and other non-
jurisdictional transmission owners that elect to share in the benefits 
of an RTO must be held to the same characteristics and functions as 
jurisdictional transmission owners. Cinergy suggests that the 
Commission commence regional technical conferences to address legal 
obstacles to public power entities' participation in RTOs and to 
explore possible alternatives to operational and functional integration 
of public power systems into RTOs.
    Commenters also address issues relating specifically to PMAs. Many 
commenters support the expansion of the FPA to give the Commission 
jurisdiction over all transmission owners.\678\ CREDA points out that 
PMAs are restricted by: (1) enabling statutes; (2) congressional 
appropriations; (3) the inability to grant indemnification without 
congressional approval; (4) the sovereign immunity doctrine; and (5) 
their load serving responsibilities. MLGW notes that other PMA 
restrictions include the TVA ``fence restriction,'' whereby, TVA's 
organic statute prohibits TVA from performing any transmission service 
that would result in the delivery of power generated by TVA outside the 
specified TVA service area. MLGW further notes that existing long-term 
contracts between TVA and its distributors are another barrier to RTO 
participation by PMAs. To remedy these problems, TVA and others \679\ 
argue that the Final Rule should provide enough flexibility to ensure 
that public power obstacles can be addressed and mitigated.
---------------------------------------------------------------------------

    \678\ See, e.g., LG&E, Otter Tail, WPSC, Alabama Commission, 
Montana Commission, and DOE.
    \679\ See, e.g., CAMU, CMUA, STDUG, CREDA, NY ISO, Powerex, PP&L 
Companies, Desert STAR, CP&L, LPPC, MEAG and Tennessee Authority.
---------------------------------------------------------------------------

    On the issue of whether the Commission should consider special 
accommodation, commenters disagree over whether the Commission should 
provide incentives to public power entities in order to make RTO 
membership financially attractive. EEI and APPA urge the Commission to 
adopt an RTO policy that makes membership attractive to public power 
entities in terms of efficiency and benefits.
    SoCal Edison is strongly opposed to the Commission providing 
incentives in the form of uniform grid-wide rates or transmission 
credits. SoCal Edison argues that these incentives are nothing more 
than inequitable cost shifts to retail ratepayers. Likewise, Duke 
argues that public power entities should not be provided with 
competitive advantages in order to encourage voluntary RTO 
participation.
    In contrast, IMPA and SoCal Cities urge the adoption of a final 
rule that provides proper credits or compensation for facilities 
contributed to an RTO, including customer-owned facilities. 
Furthermore, East Kentucky states that return on equity can be 
mitigated by allowing cooperatives to earn a rate of return similar to 
investor-owned utilities. Vernon argues that the entitlement for 
transmission facilities contributed to the RTO grid and the appropriate 
level of compensation are matters that should not be determined 
nationally on a generic basis, but rather, should be decided in the 
context of each RTO. SRP supports PBRs and other incentives as long as 
they are applied to both public power entities and investor owned 
companies equitably. Metropolitan contends that it would not receive 
much benefit from any ROE incentives offered to RTOs because it is a 
public entity and because its asset base is so heavily depreciated. 
However, a replacement cost methodology could be of use in mitigating 
cost shifts for Metropolitan due to rolling in higher costs of other 
utilities. Oregon Office recommends that public power entities be 
eligible for the same incentives as offered others to the extent that 
the Commission regulates their rates.
    A few commenters discuss issues relating to public power and the 
filing requirements. South Carolina Authority states that any RTO 
proposal should contain a detailed description of the efforts made by 
petitioners to accommodate the transmission facilities of publicly 
owned utilities. Similarly, SRP, APPA and LPPC recommend that the 
Commission require each RTO proposal to demonstrate: (1) how a good 
faith effort was made to accommodate public power participants, 
particularly deciding ownership structure; and (2) where public power 
entities are not included, why there are no reasonable terms and 
conditions under which the RTO could accommodate its participation. 
Lincoln and Cinergy essentially concur.
    Commission Conclusion. We reaffirm our preliminary determination 
that a properly formed RTO should include all transmission owners in a 
specific region, including municipals, cooperatives, Federal Power 
Marketing Agencies (PMAs), Tennessee Valley Authority and other state 
and local entities. As noted by some commenters, public power and 
cooperative participation in RTOs will enhance the reliability and 
economic benefits of an RTO. Furthermore, participation by public power 
entities and cooperatives is vital to ensure that each RTO is 
appropriate in size and scope.
    Virtually all commenters note that public power entities and 
cooperatives face numerous regulatory and legal obstacles regarding RTO 
participation. Commenters assert that these obstructions include: (1) 
IRS ``private use'' restrictions and the temporary regulations enacted 
to mitigate the ``private use'' restrictions; (2) the

[[Page 931]]

requirement that at least 85 percent of a cooperative's income must 
come from the cooperative's members (IRS Code Section 501(c)(12)); (3) 
RUS mortgage restrictions; (4) state constitutional restraints; (5) 
state and local laws; and (6) specific legal restrictions applicable to 
PMAs. In addition, commenters offer a variety of solutions to mitigate 
or eliminate these obstacles to public power participation in RTO 
formation and operation.
    We acknowledge that public power entities face several difficult 
issues regarding RTO participation and we appreciate the potential 
solutions offered by numerous commenters. At this time, however, we 
will not analyze each of the specific resolutions proposed by the 
various commenters. Instead, on an RTO-by-RTO basis, we will examine 
submitted proposals that provide public power and cooperatives with the 
flexibility to join an RTO without jeopardizing their tax or mortgage 
status. We note, however, that the offered solutions must be consistent 
with the minimum functions and characteristics outlined in the Final 
Rule.
    We are aware that some public power entities and cooperatives have 
found ways to participate in existing ISOs. For example, we approved 
the formation of the NY ISO contingent upon a ruling of the Internal 
Revenue Service that the formation and operation of the NY ISO would 
not jeopardize the tax-exempt status of the New York Power 
Authority.\680\ Furthermore, we are encouraged by the recent efforts of 
the Member Systems of the New York Power Pool (NYPP) to include and 
accommodate the participation of Long Island Power Authority (LIPA) in 
the NY ISO. NYPP proposed language in their OATT that provides LIPA 
will not be required to provide transmission service where the 
provision of such service would result in the loss of its tax-exempt 
status for its bonds. NYPP also proposed additional scheduling 
protocols and procedures to ensure the continued tax-exempt status of 
LIPA. The Commission accepted the proposed language as described 
above.\681\ We also note that there are two cooperatives Hoosier Energy 
Rural Electric Cooperative, Inc. and Wabash Valley Power Association 
that are members of the Midwest ISO.\682\ We are hopeful that similar 
agreements between RTOs and public power entities and cooperatives can 
be reached to provide flexibility and achieve broad regional RTO 
participation by all entities.
---------------------------------------------------------------------------

    \680\ See Central Hudson Gas & Electric Corp., et al., 83 FERC 
para. 61,352 at 62,405 (1998).
    \681\ See Central Hudson Gas & Electric Corp., et al., 88 FERC 
para. 61,138 at 61,402-03 (1999).
    \682\ See Midwest Independent Transmission System Operator, 
Inc., et al., 84 FERC para. 61,231 (1998).
---------------------------------------------------------------------------

    We expect public power entities and cooperatives to participate 
fully in the collaborative process for forming RTOs. During the 
collaborative process, the Commission hopes that the parties will 
explore, in detail, the impediments and various solutions to public 
power and cooperative participation in RTOs. As discussed below with 
respect to the collaborative process, we will make staff resources 
available to assist in facilitating communication between all entities 
and in designing regional solutions to full RTO formation and 
participation. Moreover, in all filings under this Rule, we require a 
description of efforts made to accommodate participation by public 
power entities and cooperatives in RTOs.
    We recognize that there is uncertainty regarding what may happen 
after the IRS temporary ``private use'' regulations expire on January 
22, 2001. Accordingly, we intend to continue to support efforts to 
mitigate the ``private use'' and other tax restrictions. Furthermore, 
in its comments, RUS recognizes that the development of RTOs may offer 
considerable benefits to RUS borrowers. RUS states that it is exploring 
means to facilitate borrower participation in RTOs. The Commission 
welcomes the efforts of RUS to facilitate borrower participation in 
RTOs, and also encourages RTOs to seek ways to accommodate mortgage 
restrictions. It would be unfortunate if public power entities and 
cooperatives were not able to participate in RTOs and share in the 
benefits available in a regional organization because of tax rules and 
other government restrictions.
2. Participation by Canadian and Mexican Entities
    In the NOPR, the Commission noted that currently, electricity 
trading regions exist across national borders and therefore, Mexican 
and Canadian involvement in RTO formation would be beneficial to both 
countries, as well as to the United States.\683\ The Commission 
asserted that regional institutions should include all market 
participants in order to provide direct access to information and the 
benefits of non-pancaked rates. The NOPR also proposed that in order to 
prevent wasteful duplication of grid facilities, reliability standards 
implemented by RTOs must be acceptable to the affected nations.\684\ 
The Commission also emphasized that Canadian and Mexican authorities 
would be responsible for approving prices and other terms and 
conditions of transmission service provided over any RTO transmission 
facilities located in their country.\685\
---------------------------------------------------------------------------

    \683\ FERC Stats. and Regs. para. 32,541 at 33,758.
    \684\ Id. at 33,758-59.
    \685\ Id. at 33,759.
---------------------------------------------------------------------------

    Comments. The U.S. entities that submitted comments on this issue 
support the efforts by the Commission to encourage participation in 
RTOs by Canadian and Mexican entities.\686\ For example, PG&E states 
that given the high degree of operational interconnection between our 
national grid and components of their systems, participation by these 
entities is beneficial.
---------------------------------------------------------------------------

    \686\ See PG&E, Desert STAR, Michigan Commission and Industrial 
Consumers.
---------------------------------------------------------------------------

    Similarly, some Canadian entities believe that significant benefits 
can be achieved by trading over ``natural'' or ``appropriate'' 
transmission regions that do not necessarily stop at the border.\687\ 
Other Canadian entities welcome the opportunity to participate in the 
RTO proceedings and support the Commission's efforts to encourage 
international collaboration.\688\
---------------------------------------------------------------------------

    \687\ See, e.g., Ontario Power, H.Q. Energy Services, BC Hydro 
and Canada DNR.
    \688\ See, e.g., Powerex, CEA, Manitoba Board, British Columbia 
Ministry, Alberta, Canada DNR, BC Hydro and Ontario IMO.
---------------------------------------------------------------------------

    Canadian entities are concerned with sovereignty issues and urge 
the Commission to adopt flexible RTO rules that allow voluntary 
participation by Canadian utilities.\689\ According to the Manitoba 
Board and Ontario IMO, one option in this regard would be to allow 
members of an RTO the freedom to conduct transactions--through a 
contractual relationship--at the international border with foreign 
utilities that do not join a cross-border RTO. Furthermore, Canada DNR 
asserts that a decision not to participate in an international RTO by a 
Canadian jurisdiction should not place entities in Canada engaged in 
trade with United States at a disadvantage. Grand Council et al. 
proposes that the Commission sever the Canadian issues from this 
proceeding and open a separate docket to examine the international 
issues raised by the restructuring of electricity markets. Grand 
Council et al. urges the Commission to cooperate with Canada and Mexico 
to establish a genuine tri-national consultative process in order to 
resolve international issues based on an adequate record. Alberta notes 
that each

[[Page 932]]

individual Province has jurisdictional responsibility for the 
development of the electrical industry within each Providence and 
accordingly, only the Province has the jurisdiction to pass legislation 
to develop a competitive electricity market.
---------------------------------------------------------------------------

    \689\ E.g., Manitoba Board, British Columbia Ministry, BC Hydro, 
Canada DNR, CEA and Ontario Power.
---------------------------------------------------------------------------

    Commission Conclusion. After reviewing the comments, we continue to 
believe that Canadian and Mexican involvement in RTO formation and 
operation would be beneficial to both countries, as well as to the 
United States. As we stated in the NOPR, expansion of electricity trade 
in the North American bulk power market requires that regional 
institutions include all market participants so that everyone may enjoy 
direct access to market information and the benefits of non-pancaked 
transmission rates. Commenters from the United States and Canada agree 
that significant benefits can be achieved by trading over ``natural'' 
or ``appropriate'' transmission regions that do not necessarily stop at 
the border.
    We note first that we are pleased with the level of participation 
in our proceedings by Canadian parties, and we encourage their 
continued participation as RTO formation progresses. We especially 
appreciate the RTO Consultation Conference sponsored by Natural 
Resources Canada in Ottawa in November 1999.
    In response to Canadian comments, we point out that the Final Rule 
makes participation in an RTO voluntary for U.S. transmission owners, 
and participation is certainly voluntary for Canadian transmission 
owners. Further, we emphasize that our RTO Rule does not in any way 
require competition in retail electricity markets, whether they are 
located in the United States under state regulation or in Canada under 
provincial regulation. For those Canadian entities that want to join an 
RTO, the Final Rule is flexible: they may propose a cross-border RTO or 
a Canadian-only RTO that is compatible with the Rule. The Final Rule is 
not exclusionary: Canadian entities are not precluded from joining a 
cross-border RTO.
    Several parties were concerned that a cross-border RTO would have 
its rates, terms, and conditions subject to the rate jurisdiction of at 
least two regulators. If a cross-border RTO forms, we will be open to 
proposals for innovative approaches for jointly overseeing a cross-
border RTO with domestic and foreign utilities. For example, one 
approach might be for the cross-border RTO to try to develop a proposal 
acceptable to both regulators, with the understanding that any 
regulatory difficulty would normally be referred back to the RTO for 
resolution and resubmission to both regulators. Another approach might 
be to have different but complementary rate designs in the two 
countries.
    In the case of a Canada-only RTO, some Canadian transmission 
providers believe that having contractual and other agreements for 
coordination between separate RTOs aross the border is better than 
having a cross-border RTO. However, some Canadian transmission 
customers are concerned that this would maintain a lack of 
standardization of market rules across the border. The RTO Rule is 
intended to permit a U.S. RTO on the Canadian border to develop 
contractual and other agreements for coordination with its Canadian RTO 
neighbor. Further, we have added a new minimum RTO function that an RTO 
must ensure the integration of reliability practices with other regions 
in the same interconnection and market interface practices with other 
regions. We clarify here that this provision applies to integration 
with interconnected regions in Canada and Mexico.
    For either a cross-border or a Canada-only RTO, we acknowledge the 
sovereign authority of Canadian governments over Canadian entities and 
transactions that take place in Canada. Moreover, we re-emphasize that 
our Rule does not affect the authorities of Canadian government 
entities to approve prices and other terms and conditions of 
transmission service provided over any transmission facilities located 
in Canada. These conclusions apply equally to Mexico.
    We encourage Canadian and Mexican entities to participate in 
continued RTO consultations and, if appropriate, formation and filings 
for cross-border RTOs. In particular, we urge Canadian and Mexican 
entities to attend the appropriate regional workshops to be held in the 
spring of 2000. These workshops will provide a forum for initial 
discussion of the issues associated with a cross-border RTOs.
    Regarding the suggestion to establish a tri-national consultative 
process with Canadian and Mexican authorities to resolve international 
electric industry issues, we note that there are existing institutions 
and processes for resolving international disputes. The RTO process is 
just getting underway, and it is not clear that significant 
international disputes will develop or, if they should develop, that 
they would require a non-traditional method of resolution. Indeed, the 
RTO itself through its dispute resolution process may provide a new and 
quicker way to resolve some disputes.
3. Existing Transmission Contracts
    In the NOPR, the Commission asked for comments addressing what the 
appropriate treatment should be for existing transmission agreements 
when an RTO is formed. We noted that in Order Nos. 888 and 888-A, the 
Commission specifically chose not to abrogate existing requirements 
contracts and transmission contracts when the utility filed an open 
access transmission tariff.\690\ We stated, however, that an RTO 
represents an entirely different context. In the NOPR, the Commission 
recognized the importance of balancing a uniform approach for 
transmission pricing with the equities inherent in existing 
transmission contracts.\691\ Furthermore, we noted that the potential 
financial impact of giving up an advantageous transmission arrangement 
may serve as a disincentive to joining an RTO. In the NOPR, we proposed 
to address the issue of existing transmission contracts on an RTO-by-
RTO basis, rather than resolve the issue generically.\692\
---------------------------------------------------------------------------

    \690\ FERC Stats. & Regs. ] 32,541 at 33,757.
    \691\ See id. at 33,757-58.
    \692\ Id. at 33,758.
---------------------------------------------------------------------------

    Comments. Many commenters argue that the Commission should preserve 
and protect existing transmission contracts.\693\ These commenters note 
that existing contracts represent negotiated rights and obligations 
achieved through mutual negotiation. SRP believes that the Commission 
should grandfather existing transmission contracts in order to protect 
customers from cost shifts and prevent uncertainty in the marketplace. 
Turlock argues that the preservation of existing contracts, while 
cumbersome, is the bedrock of predictability and reliability and a key 
element of contract law. NPRB states that existing contracts should be 
honored until the contract expires or until the parties come to a new 
agreement. STDUG asserts that in order to be properly inclusive, an RTO 
must take members as it finds them, existing contracts, warts, and all. 
In contrast, CP&L asserts that the elimination of grandfathered 
agreements to the greatest extent possible ensures the most level 
playing field for all market participants.
---------------------------------------------------------------------------

    \693\ E.g., TANC, Turlock, UAMPS, Desert STAR, CMUA, Sithe, 
Georgia Transmission, Lincoln, PG&E, NPRB, NCPA, Great River, NRECA, 
Loveland Customers, San Francisco, Platte River, Florida Commission, 
Nevada Commission, DOE, Wolverine Cooperative, Tri-State, CREDA, 
EPSA, Big Rivers, SPP, SoCal Cities, TEP, PJM/NEPOOL Customers, 
Metropolitan, STDUG and PacifiCorp.

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

[[Page 933]]

    A few commenters propose a reasonable transition period to allow 
parties to existing contracts to conform their arrangements to an RTO 
tariff.\694\ EPSA notes that the transition period should be of 
sufficient length to reduce the financial and other burdens on the 
customer and on the original transmission provider. PSNM argues that at 
a minimum, a transition period of as long as ten years is needed to 
move the existing transmission contracts to RTO service. Furthermore, 
TAPS proposes that the Commission provide entities with an open season 
for transmission customers to choose to terminate or switch service 
under the terms of an RTO tariff. Alternatively, TAPS suggests that the 
Commission apply a just and reasonable standard to all transmission 
customers who seek contract modifications. Regarding contract 
modification, Southern Company asserts that in order to promote 
fairness, both parties to a contract must have an equal opportunity to 
modify the existing agreement. In addition, Entergy argues that the 
Commission should encourage all entities to re-negotiate existing 
contracts.
---------------------------------------------------------------------------

    \694\ See, e.g., Williams, EPSA, First Energy, Duke, PSNM, LG&E, 
PGE and MidAmerican.
---------------------------------------------------------------------------

    Several commenters support the Commission's preference that issues 
relating to the continued validity of existing transmission contracts 
be addressed on an RTO-by-RTO basis.\695\ WPSC argues that treatment of 
existing transmission contracts within a particular RTO should be 
consistent. Turlock urges the Commission to proceed with caution when 
addressing existing contracts. On the other hand, PSE&G asserts that 
the Commission should not address the treatment of existing contracts 
on a case-by-case basis because this leads to arbitrary and 
inconsistent results. Instead, PSE&G and Dalton Utilities argue that 
the Commission should address the issue of existing transmission 
contracts on a generic basis consistent with Order No. 888 and the 
Mobile-Sierra doctrine (recognizing the need to preserve the sanctity 
of contracts where possible).\696\ Sithe and NRECA concur that a 
generic policy is appropriate.
---------------------------------------------------------------------------

    \695\ See, e.g., WPSC, Great River, DOE, ICUA, Entergy, TDU 
Systems, TEP, South Carolina Authority, MidAmerican, SNWA, UAMPS and 
TAPS.
    \696\ See United Gas Pipe Line Co. v. Mobile Gas Serv. Corp., 
350 U.S. 332, 338 (1956); FPC v. Sierra Pacific Power Co., 350 U.S. 
348, 353 (1956).
---------------------------------------------------------------------------

    Cal ISO argues that the Commission's policies on existing contracts 
deserve revisiting, at a minimum for the limited purpose of conforming 
scheduling and metering rules to those of the RTO/control area 
operator. Cal ISO states that it has experienced the challenges of 
workability when the ISO was required to honor existing contracts, but 
not permitted to interpret them or conform their scheduling rules to 
those of the regional organization. Cal ISO notes that it has 
experienced the most significant market inefficiencies associated with 
existing contracts in the area of scheduling and information gathering.
    A few commenters note that not honoring existing contracts would 
create disincentives for both transmission customers and owners to join 
an RTO.\697\ For example, CMUA and Georgia Transmission argue that the 
financial impact of giving up an advantageous transmission arrangement 
would be a significant disincentive to RTO membership.
---------------------------------------------------------------------------

    \697\ E.g., CMUA, Desert STAR, Georgia Transmission, Wolverine 
Cooperative, Cal ISO, Entergy, Tri-State, SNWA, Metropolitan and 
TEP.
---------------------------------------------------------------------------

    Commission Conclusion. At this time, we continue to believe that it 
is not appropriate to order generic abrogation of existing transmission 
contracts. We recognize that existing contracts represent negotiated 
rights and obligations achieved through mutual negotiation. However, in 
PJM \698\ and the Midwest ISO \699\ we adopted the rationale that it 
was unreasonable and discriminatory to maintain the pancaked rates in 
existing contracts for others when transmission-owning utilities had 
designed a non-pancaked rate approach for their own transactions. In 
our examination of existing contracts, we intend to balance the 
preference for preservation of existing contracts with the importance 
of consistency in transmission pricing and the elimination of pancaked 
rates.
---------------------------------------------------------------------------

    \698\ See PJM, 81 FERC para. 61,257 at 62,280-81 (1997).
    \699\ See Midwest Independent Transmission System Operator, 
Inc., et al., 84 FERC para. 61,231 at 62,169-70, order on reh'g, 85 
FERC para. 61,372 at 62,418-20 (1998).
---------------------------------------------------------------------------

    As the above comments demonstrate, there is no consensus on how the 
Commission should manage the transition from existing transmission 
contacts to RTO service. In fact, parties offer diverse and conflicting 
views as to what the Commission should do regarding existing 
transmission contracts. Some commenters would have us let all contracts 
run their course with no opportunity to modify or terminate. Others 
advocate an elimination of existing agreements to the greatest extent 
possible. Yet others argue for a transition period ranging in duration 
for up to ten years to move existing transmission contracts to RTO 
service.
    Rather than adopting one extreme position or the other, we will 
take a measured approach with regard to the treatment of existing 
transmission contracts. We intend to address the issue of existing 
transmission contracts on an RTO-by-RTO basis, rather than resolve the 
issue generically. Accordingly, each RTO can propose whatever contract 
reform is necessary, including the limited changes suggested by the Cal 
ISO for the limited purpose of conforming scheduling, information 
gathering, and metering rules to those of the RTO. To this end, we 
encourage each RTO to address how and when it might convert existing 
contracts and submit a contract transition plan that contains specific 
details about the procedures to be utilized involving the conversion 
from existing contracts to RTO service. Again, our 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.
4. Power Exchanges (PXs)
    The NOPR described the apparent advantages and disadvantages of 
having a power exchange coincident with an RTO. As further described in 
the NOPR, supporters state that PXs can reduce price volatility by 
providing price transparency, reduce the impact of defaults by 
spreading transaction risks among all participants through credit 
standards and reserve fund requirements, facilitate risk hedging by 
providing a basis for a futures market, and help facilitate retail 
access programs. Detractors argue that the principal functions of a PX 
are not natural monopoly functions. They contend that PXs, compared 
with bilateral markets, force participants to buy and sell electricity 
using standardized contracts, which may not suit their particular 
needs. They further argue that competition within the electricity 
market and its full benefits can only be achieved if there is 
competition for the PX market.
    The NOPR left it to each region to determine whether there is a 
need for a power exchange and whether the RTO should operate it.\700\ 
The NOPR said that the Commission will accept any RTO proposal that 
includes a power exchange in its design as long as its operation of the 
power exchange does not compromise its independence as a

[[Page 934]]

transmission service provider. The Commission sought comments on a 
number of questions related to power exchanges, including whether 
regional flexibility is appropriate and how RTOs should deal with an 
independent power exchange.
---------------------------------------------------------------------------

    \700\ FERC Stats. and Regs. para. 32,541 at 33,760.
---------------------------------------------------------------------------

    Comments. Commenters' views on power exchanges are mixed. The 
largest group of commenters basically agree with the NOPR.\701\ A 
smaller group of commenters recommend that the Commission require that 
RTO applications include provisions for a power exchange,\702\ with 
some recommending that the power exchange be internal to the RTO \703\ 
and some recommending that the PX be independent of the RTO.\704\ CalPX 
argues strongly that a power exchange should be separate from the RTO, 
given the continuing need to separate market and transmission 
functions; the need for market transparency to facilitate determination 
of whether congestion is being exploited; the need to provide a 
credible reference price for new retail choice market entrants; and the 
potential need for the RTO and power exchange to serve differing 
geographic areas. CalPX also submits that there is no concrete evidence 
that an RTO-operated power exchange will be more efficient and 
economical than an unrelated power exchange. NYMEX agrees that an RTO 
should be permitted to operate a power exchange, as long as a proper 
code of conduct is in place. PJM points to its success with a combined 
ISO/power exchange.
---------------------------------------------------------------------------

    \701\ See, e.g., Entergy, NJBUS, NY ISO, TDU Systems, Wisconsin 
Commission and UtilitCorp.
    \702\ See, e.g., Pennsylvania Commission, Duke and California 
Board.
    \703\ See, e.g., PJM, ISO-NE and TAPS.
    \704\ See, e.g., EPSA and MidAmerican.
---------------------------------------------------------------------------

    Another group of commenters argue that power exchanges should not 
be included in RTOs, but should be allowed to occur naturally as 
needed.\705\ Elaborating on this point of view, Salomon Smith Barney 
advises that the power exchange should not be in the RTO because it 
could throttle innovation and that the Commission should let the market 
decide. If there are really advantages to be gained, as some claim, 
from the operation of a single power exchange associated with the RTO, 
then such a power exchange will naturally develop. Florida Power Corp. 
argues that, while a region may prefer that its RTO closely coordinate 
with the power exchange, the two should not be part of the same 
organization because there is a fundamental difference in the business 
objectives of the two . Similarly, EPSA contends that the Commission's 
vision of an RTO being an entity independent from all generation and 
power marketing interests is fundamentally incompatible with an RTO-run 
power exchange. Nevada Commission offers that a power exchange is not 
necessary to the formation of an RTO. And while PG&E sees every region 
needing a real-time balancing market regardless of whether it is run 
in-house by the RTO, PG&E also prefers that markets should otherwise be 
left to develop on their own accord.
---------------------------------------------------------------------------

    \705\ See, e.g., APX, SMUD, Southern Company, Tri-State and 
Lincoln.
---------------------------------------------------------------------------

    Comments were received on additional aspects of the power exchange 
concept. PG&E argues that an RTO should not be allowed to use control 
of a power exchange to alter or cap prices set by the market. LG&E 
submits that the RTO should be required to be the provider of last 
resort for ancillary services, although market participants should not 
be required to purchase from the RTO. NASUCA notes that the NOPR does 
not cover some important power exchange issues such as exactly which 
markets would be included. NASUCA recommends that a NOI on power 
exchanges and related power market issues be initiated soon after the 
final rule.
    Several commenters state that multiple power exchanges in a region 
should have equal standing before the RTO.\706\ FTC, however, 
recommends that the Commission assess whether competition is feasible 
in power exchange services. Similarly, CalPX notes that multiple power 
exchanges may hurt the market's function because each power exchange 
would be small, and therefore would not offer high levels of depth, 
liquidity and efficiency. NYMEX counters that there should be no 
credence given to the idea that one power exchange should enjoy any 
form of artificial franchise vis-a-vis others.
---------------------------------------------------------------------------

    \706\ See, e.g., Duke, Florida Power Corp. and Desert STAR.
---------------------------------------------------------------------------

    Commission Conclusion. The NOPR proposed leaving it to each region 
to determine whether there is a need for a power exchange and whether 
the RTO should operate the power exchange. We have Decided to adopt the 
NOPR proposal. As the commenters have pointed out, there are advantages 
and disadvantages to the inclusion of a PX in the RTO structure. We do 
not believe that including a PX as part of the RTO structure would 
necessarily preclude the market benefits associated with bilateral 
transactions. We believe an RTO can accommodate both a bilateral market 
and a PX market. As the individual structures of the various RTOs 
supported by the regions are likely to be quite varied, we think that 
it is best to let market preferences dictate the form of any one or 
more regional power exchanges and whether the RTO should operate a 
power exchange.
5. Effect on Retail Markets and Retail Access
    The NOPR addressed the impact of RTOs and any associated PXs on 
retail competition and the states' jurisdiction over retail 
competition. For example, the Commission found that RTOs will enhance 
the effectiveness of retail competition:

    We believe that the likelihood of success for existing and 
planned retail choice initiatives is significantly enhanced if the 
Commission can ensure fair and efficient access to a regional market 
without pancaked transmission access charges, and that we need to 
take steps beyond Order No. 888 to accomplish this.\707\
---------------------------------------------------------------------------

    \707\ FERC Stats. and Regs. para. 32,541 at 33,704.

    In addition, the Commission found that an RTO does nothing to 
interfere with the state's authority to decide retail access policy, 
but asked whether a PX is necessary for successful retail competition.
    Comments. Several commenters state that RTOs were either essential 
or of great benefit in the implementation of retail competition.\708\ 
Mid-Atlantic Commissions notes that PJM has worked closely with the 
Pennsylvania, New Jersey and Delaware Commissions to assist with the 
implementation of their retail choice legislation in an organized 
fashion, while maintaining that the grid will be operated in a reliable 
fashion without any major economic or operational changes. According to 
Mid-Atlantic Commissions, this has also further provided those states 
in the region that have not implemented retail choice with a stable 
organization that continues to maintain reliability.
---------------------------------------------------------------------------

    \708\ See, e.g., TXU Electric, DOE, First Rochdale, Illinois 
Commission and Williams.
---------------------------------------------------------------------------

    A few commenters express concern that the Commission's RTO policy 
could threaten the states' ability to control the pace of retail access 
and retail competition.\709\ South Carolina Commission counsels that 
the Commission should try to avoid affecting retail restructuring 
through its efforts to establish an RTO process. Central Maine raises 
the concern that retail choice programs already developed in concert 
with existing ISOs may be adversely impacted by any changes to such 
ISOs that are found to be necessary for them to conform to the RTO 
requirements (e.g., energy service

[[Page 935]]

company and other load serving entity contracts entered into in 
reliance upon the existing ISO market structures).
---------------------------------------------------------------------------

    \709\ See, e.g., Iowa Board and Puget.
---------------------------------------------------------------------------

    Puget views allowing RTOs to make FPA section 205 filings that 
unilaterally propose changes to the RTO tariff as conflicting with the 
Commission's commitment to respect the retail access efforts of the 
individual states. Puget argues that a unilateral decision by an RTO to 
provide transmission service to a retail customer and make that 
customer an eligible customer under the pro forma tariff would force 
states without retail access to accept such access as a fait accompli. 
Puget also fears that the term ``market participant'' as ultimately 
defined may include any entity that buys or sells electric energy in 
the RTO's region or in any neighboring region that might be affected by 
the RTO's actions. If so, since market participants must also have the 
option of self-supplying or acquiring ancillary services from third 
parties, this further suggests that retail customers may have the 
ability to acquire transmission service regardless of whether the 
affected state has yet decided retail choice and stranded cost recovery 
issues. Industrial Customers, however, question the legal basis for 
Puget's apparent suggestion that utilities be allowed to decide which 
retail customers may access RTO transmission.
    EPSA contends that, while states tout each state's rights to 
protect its retail native load customers, some actions taken under this 
banner to limit exports of power actually disadvantage adjoining 
state's retail customers or participants in the bulk power markets. 
Therefore, the Commission should move forward with a rulemaking to 
assure full transmission comparability for retail customers of all 
states, and to prevent individual states from continuing to 
disadvantage each other and to prevent individual utilities from 
continuing to disadvantage other market participants. New York 
Commission also submits that this proceeding is not the place to 
address the issue of preemption of state jurisdiction over bundled 
retail electric sales.
    TAPS raises the question of jurisdictional conflict as to which 
facilities need to be regulated at the federal or state level, and 
whether the policies of the Commission toward open access will be 
undercut by transmission owners using the seven factor transmission/
distribution classification test to place new generation at a 
disadvantage relative to existing generation owned by the transmission 
provider. TAPS contends that the Commission must take steps to ensure 
that RTOs contain the appropriate facilities and that 
refunctionalization of transmission to distribution does not interfere 
with competition by creating RTOs that control little or no 
transmission.
    Another concern expressed is that RTOs may cause cost shifting to 
retail customers that could interfere with restructuring.\710\ As to 
the impact of the power exchange on retail competition, both CalPX and 
MidAmerican argue that power exchanges assist in the effectiveness of 
retail competition programs by providing transparent and credible 
reference prices.
---------------------------------------------------------------------------

    \710\ See, e.g., LG&E and Southern Company.
---------------------------------------------------------------------------

    Commission Conclusion. We continue to be persuaded that RTOs can 
positively affect each state's implementation of its retail choice 
program, without interfering with those states that have not yet 
adopted such programs. As noted by commenters, existing ISOs have 
already successfully facilitated retail choice programs in areas where 
only some of the states have adopted such programs, and the ISOs were 
able to do so without clashing with or frustrating the other states 
that have not undertaken such programs. We do not believe that an RTO 
could interfere with a state's decisions on whether or how fast to 
implement retail choice within its borders, either through the RTO's 
Section 205 filing authority or otherwise through the RTO's 
jurisdictional obligation to provide non-discriminatory and non-
preferential transmission service.
    Commenters pointed to potentially extensive reclassification of 
transmission facilities to local distribution as part of the unbundling 
of retail rate schedules to implement retail choice programs, and how 
this might lead to RTOs that are ``empty vessels'' with little 
significant transmission under their control. We agree that RTOs must 
control all transmission facilities that are necessary to support 
competitive wholesale power markets. For this reason, we specified the 
scope, configuration and operational control requirements adopted in 
this Final Rule. We will judge any proposed reclassification on a case-
by-case basis. We note that any reclassification of transmission 
facilities to local distribution will require Commission approval and 
will not remove from the Commission's jurisdiction any facilities used 
to deliver power to wholesale customers. Furthermore, under the 
principle of open architecture (discussed supra in section III.F), the 
Commission expects RTOs to remain flexible such that, if over time 
circumstances should change and certain facilities need to be 
reclassified as transmission, procedures will be in place to do so.
    With regard to RTO pricing causing transmission cost shifting that 
adversely affects retail choice customers, this issue is discussed in 
the Transmission Ratemaking section of this Final Rule.\711\ The 
Commission will continue to review transmission rate proposals to 
ensure that they are just and reasonable, and not unduly 
discriminatory.
---------------------------------------------------------------------------

    \711\ See supra section III.G.
---------------------------------------------------------------------------

    Finally, on the matter of whether a power exchange is needed to 
facilitate states' retail choice programs, it is our view that, to the 
extent that a region forming an RTO chooses to voluntarily establish an 
RTO-affiliated power market, we anticipate that any such power exchange 
would provide retail choice customers with transparent and credible 
reference prices for power and other information that otherwise might 
not be available.\712\
---------------------------------------------------------------------------

    \712\ For a further discussion of PXs, see supra section 
III.H.4.
---------------------------------------------------------------------------

6. Effect on States with Low Cost Generation
    In the NOPR, we recognized that states with relatively low cost 
power are concerned that an RTO would result in local utilities selling 
their low cost power to other states.\713\ However, we noted that a 
state that is low cost today may not be low cost tomorrow without an 
RTO in its area.\714\ In addition, we stated that utilities that now 
have low cost generation will help assure access to future low cost 
generating plants by participating in an RTO and that new low cost 
generation plants are more likely to be attracted to regions with a 
well-functioning regional market governed by an RTO. We sought comment 
from state commissions regarding how an RTO in their state would affect 
power costs.
---------------------------------------------------------------------------

    \713\ FERC Stats. and Regs. para. 32,541 at 33,722.
    \714\ See id.
---------------------------------------------------------------------------

    Comments.--A number of commenters raise concerns about the effect 
of RTOs on states with low cost electricity. These concerns center 
around one issue--that the costs of creating an RTO may outweigh the 
benefits.
    South Carolina Commission argues that customers in South Carolina 
enjoy very high quality service and pay some of the lowest rates. Duke 
power concurs, noting that, it is not necessarily true that North 
Carolina and South Carolina will conclude that sufficient long-term 
benefits exist for these states to justify costs of RTO membership. 
Duke argues

[[Page 936]]

that any proposed RTO should be shown to provide tangible benefits to 
the relevant region.
    Alabama Commission believes that RTOs will cause states to lose the 
efficiency of integrated systems and lead to retail competition, 
whether it is in the interest of customers or not. Southern Company 
agrees, noting that due in large part to the low cost status of 
southeastern states, they are proceeding cautiously with retail 
competition and restructuring initiatives. This does not mean that 
these states are ignoring the potential benefits of restructuring. 
Indeed, Southern Company notes that states in its service territory are 
actively studying the potential advantages and disadvantages of retail 
competition but have not yet concluded that the potential benefits 
outweigh the costs and risks associated with changing the current 
industry structure.
    SMUD points out that it has not joined the Cal ISO over similar 
concerns. It indicates that its customers already enjoy low cost 
electricity and that participation in the Cal ISO could not ensure that 
SMUD's retail rates would be any lower, and on the contrary, the cost 
of participation would cause rate increases.
    Kentucky Commission indicates that inefficiencies may occur for a 
variety of reasons and examples of inefficiencies include: multiple 
RTOs in a small region; several layers of governance within one RTO; 
and too many tasks shifted from the RTO members to the RTO itself. 
Kentucky Commission argues that if the proposed transmission 
organizations are not operated at levels of maximum efficiencies and 
minimum reasonable costs, the Commission will have failed to promote 
one of its primary objectives, the growth and success of the wholesale 
power market. Kentucky Commission further argues that the Commission 
must be mindful of these costs in developing rules for the 
establishment of RTOs.
    Commission Conclusion. We are mindful of the potential costs of 
setting up and running an RTO, but we anticipate that the collaborative 
process will result in an RTO proposal that incorporates a design that, 
overall, increases the existing level of transmission system and market 
efficiency for each region. As we discuss more fully in the Scope, 
Implementation and Benefits sections of this Final Rule, we are taking 
a results-oriented, practical approach to establishment, organization, 
implementation and operation of RTOs. We do not expect that regions 
with no existing institutions will necessarily invest in new, high-cost 
RTO infrastructure. Instead, such a region may propose an RTO that 
relies on existing infrastructure to accomplish its mission. However, 
we expect the RTO to satisfy the minimum characteristics and functions 
and to improve the efficiency of regional transmission service.
    In response to the concern of low cost states that RTOs could 
result in exports of their low cost power to other states, we do not 
believe that an RTO will cause utilities to sell their lowest cost 
power out of state. While retail choice arguably might lead to low cost 
power being sold out of state because incumbent utilities no longer 
have an obligation to serve local in-state loads, this would occur with 
or without an RTO in the region. Where there is no retail choice, our 
Final Rule does not affect a state commission's authority to require a 
utility to sell its lowest cost power to native load, as it always has. 
We point out that, if the utility's transmission is operated by an RTO 
and its higher cost power can be sold more readily to new, more distant 
customers, this will lead to recovery of more capital costs and lower 
retail rates. In the long term, low cost states may benefit from an RTO 
that facilitates expanded access to wholesale electricity markets, 
increasing the choice of low cost resources available to utilities as 
they acquire new power resources.
7. States' Roles with Regard to RTOs
    In the NOPR, we noted that states want a role in the governance of 
any RTOs for their states, and we proposed to be flexible in 
accommodating the states' needs.\715\ The NOPR encouraged RTO design to 
accommodate appropriate state oversight, especially with regard to 
planning and siting new multi-state transmission facilities. We sought 
comments on the appropriate state role in RTOs on these and other RTO 
matters.
---------------------------------------------------------------------------

    \715\ FERC Stats. and Regs. para. 32,541 at 33,724.
---------------------------------------------------------------------------

    Comments. Comments on the states' roles in RTO development and 
governance were fairly extensive, with by far the greater percentage of 
comments supporting a strong and clearly defined state role. Comments 
can be grouped into four primary categories: (1) governance; (2) 
formation; (3) siting and planning authority; (4) regional regulation.
    Governance. Almost all commenters on this issue expressed support 
for a clear state role in governance; however, there were differences 
as to exactly what that role should be. Some commenters believe that 
states should be allowed to determine their own role in governance, 
either as members of advisory panels to the board of directors, as 
voting members of the board, as non-voting members of the board, or 
having authority to appoint board members. Some commenters, however, 
feel strongly that states should not be permitted to be voting members 
of boards.
    Commenters argue that the appropriate state role in an RTO is a 
matter of local control. For example, Northwest Council states that the 
Commission should not set restrictive rules on the type of state 
participation in RTO governance, but should allow the states to propose 
to the Commission the kind of roles they view as appropriate, e.g., 
voting members of a stakeholder board, ex officio status on an 
independent board, and so forth.
    The California Board suggested that state officials should be 
allowed as either voting or non-voting members. Los Angeles has no 
objection to state board membership, either voting or non-voting, if a 
state has determined that a government official can best represent that 
state's interests. The Washington Commission agrees that states should 
be able to define their own role. Mid-Atlantic Commissions note that 
they have a Memorandum of Understanding with the PJM ISO Board of 
Managers to facilitate communication and promote a cooperative 
relationship.
    Some commenters, however, think that state officials should not 
have voting membership on boards of directors since that could raise 
conflict of interest problems where the state official would have to 
approve decisions of the board while sitting as a regulator. For 
example, Minnesota Power believes that state cooperation will be 
enhanced if state officials participate as members of an RTO advisory 
board, but they should not participate as voting members of an RTO 
because the RTO process could be compromised by parochial state 
politics. ISO-NE agrees, pointing out that some states' conflict of 
interest laws may expressly prohibit such service, and that it might be 
difficult for an official from one state to make decisions as a board 
member that are good for residents of all states encompassed by the 
RTO.\716\ WEPCO believes the appropriate role of the states in RTO 
governance includes active participation in regional planning efforts 
and continued oversight of siting of new transmission facilities. In 
addition, many commenters supported

[[Page 937]]

an advisory role for state officials, through advisory boards.\717\
---------------------------------------------------------------------------

    \716\ See also MidAmerican, Montana-Dakota, PSNM, East Kentucky 
and NPRB.
    \717\ E.g., ISO-NE, PJM, Midwest ISO, MidAmerican, Project 
Groups, PSNM, Iowa Board, Arizona Commission and UAMPS.
---------------------------------------------------------------------------

    Formation. Numerous commenters supported a role for states in the 
formation of RTOs. ISO-NE points out that the states in its region had 
a significant role in the development of the ISO. In addition, the 
California Board argues that states should have a role in determining 
the structure of the RTO and any other market institutions that are 
formed to serve the citizens of their respective states. California 
Board further notes that mechanisms to ensure that states' interests 
are protected might include statutory or regulatory reliability 
criteria; independent market monitoring by the states or requiring 
market monitoring reports to be provided to the state; and 
accountability to the states to ensure adequacy of transmission and 
generation planning.
    The Michigan Commission notes that most states have ittle direct 
authority to order the development of an RTO, especially when the RTO 
encompasses several states. According to the Michigan Commission, at 
best state commissions should serve in an advisory role as the 
utilities develop the structure and guidelines of the RTO proposal. The 
Michigan Commission, however, joins a few other states in urging the 
Commission to defer to state recommendations once the basic RTO 
characteristic and functional guidelines have been met.
    NARUC comments extensively on the potential collaborative process 
and the importance of state participation in this process and other 
steps in the formation of RTOs. To achieve the public policy goal of 
assuring reliable service at an affordable cost, NARUC argues that 
states should fully participate in RTO development and formation, 
particularly in matters for end-use native load customers. NARUC notes 
that based on some states' retail choice or ISO experiences, state 
oversight can play a significant role in assuring a well-functioning 
ISO and competitive wholesale and retail markets.
    NARUC further suggests that once RTOs are formed, continuing 
interaction is necessary, and market development and evolution will be 
continuous. NARUC believes that RTO formation must continue to be a 
dynamic process requiring continuing dialogue between FERC and the 
states. NARUC further believes that once organizations are formed and 
approved, some type of formal reporting to FERC and the states by the 
organizations on an annual basis would be appropriate.
    Nine Commissions suggests that state commissions are well 
positioned to balance the competitive motivations of utilities in the 
RTO formation process with the interests of all other stakeholders in 
defining markets in their respective regions and conforming the RTO 
boundaries to those markets. According to Nine Commissions, the state 
commissions' continued cooperation with FERC will ensure that the 
mutual public interests of providing reliable electric service will be 
met, and that market participants in every region of the country will 
be treated comparably.
    Siting, Planning and Reliability. A number of commenters, many 
state commissions, and quite a few other parties, argue strongly that 
the Commission should be careful not to preempt traditional state 
regulatory authority in promulgating its rule. In particular, 
commenters suggest that the Commission should not usurp state 
authorities over siting, planning, and reliability of the transmission 
system. Some commenters proposed solutions to state/Federal 
jurisdiction issues in the RTO context, such as joint state/Federal 
review bodies. The Alabama Commission suggests that FERC should not 
take any action that would infringe on state jurisdiction.
    South Carolina Commission asserts that transmission siting should 
remain in the hands of the states and local governments. South Carolina 
Commission further asserts that states must continue to have a 
significant role with regard to matters of reliability for end-use 
native load customers. The Iowa Board concurs and suggests that the 
Commission's RTO policies cannot alter states' continued interest in 
local matters such as transmission and generation siting, local 
transmission and distribution interface issues, adequacy of generation 
and transmission, service quality, and retail rates.
    The Montana Commission notes that in roughly half the states with 
siting laws the function is not vested in the regulatory commission, 
but rather in a separate energy policy, environmental or commerce 
agency. They recommend that the Commission amend the language in the 
Final Rule to make it clear that the Commission does not intend to 
preempt state siting authority as part of this NOPR.
    UAMPS warns that RTOs may create a separation between generation 
planning and transmission planning that endangers reliability. UAMPS 
argues that states must be left with authority to assure reliability 
and that retail competition issues should also be left to the states. 
UAMPS suggests that because state cooperation and participation will be 
so critical to an RTO's effectiveness, in addition to the four minimum 
characteristics the Commission has proposed, RTOs should be required to 
provide specifically for significant state involvement in their 
development and operation. Allegheny, on the contrary, states that 
system operations in an RTO will be pursued for the good of the RTO 
service area, not of any one state. Allegheny notes that if that fact 
yields a dilution of state authority it must be the price paid for RTO 
benefits.
    Regional Regulation. A number of commenters propose or support 
regional regulatory cooperation or joint state/Federal sharing of 
jurisdiction. The Kentucky Commission proposes the creation of a 
Federal/state ``joint board,'' that is styled similarly to the 
Universal Service Joint Board currently used by the Federal 
Communications Commission, state utility commissions, and other 
parties. The Kentucky Commission suggests creating this voluntary Board 
to develop and review standards for transmission expansion. The Joint 
Board would include participation from FERC, state commissions, RTOs, 
and other interested parties. The Joint Board would also convene ad hoc 
committees to review specific transmission expansion proposals. These 
committees would include the participants described above, and would 
include representatives from regulatory commissions in states where the 
expansion is proposed. The RTO would present the ad hoc committee with 
a plan for transmission expansion with appropriate documentation for 
need, cost effectiveness, and alternatives. The committee would in turn 
pass on its recommendation or refusal of support for the plan to the 
specific state commissions for their official approval. The Kentucky 
Commission believes that such an arrangement could avoid Federal/state 
conflict while allowing both levels of government to exercise 
appropriate jurisdiction. In addition, ISO-NE points to existing 
regional regulatory groups such as NECPUC that could continue to 
provide valuable assistance to the Commission in the collaborative 
process to encourage RTO formation envisioned in the NOPR.
    Nine Commissions argues that an appropriate regional oversight 
venue will lead to more consistent treatment of issues and parties 
between state and Federal regulatory forums. With appropriate deference 
by both FERC and the states, such a regional venue could

[[Page 938]]

obviate the need for many parties to expend redundant resources to 
participate in multiple state and Federal regulatory processes for 
matters relating to transmission and RTOs.
    Nine Commissions notes that one possible mechanism to effectuate 
such a regional venue is interstate compacts, which are provided for in 
the Administration's proposed electric industry restructuring 
legislation. Nine Commissions argues that regional regulatory 
organizations have the advantage of being able to coordinate state 
interests for providing regional recommendations to FERC. State 
oversight functions (e.g. siting, local outages, customer complaints) 
would not change. According to Nine Commissions, such regional 
regulatory organizations would provide greater coordination among 
states within the region, allowing for ADR processes that could satisfy 
multiple state jurisdictional requirements, and such organizations 
would monitor markets that have evolved beyond state borders and 
facilitate joint FERC and multi-state facilities siting.
    Pennsylvania Commission prefers a joint Federal/state approach 
toward regulating RTO siting approvals, expansion, innovation and 
customer service. Pennsylvania Commission notes that a joint approach 
would resolve the vexing problem of Federal/state jurisdictional 
uncertainty and a joint Federal/state approach would avoid the 
potential for creative forum shopping by individual stakeholders, who 
will always seek to cast a dispute in jurisdictional terms so as to 
dictate a jurisdictional resolution to the perceived favorable outcome. 
A joint Federal/state approach has been used with success in other 
areas, such as the Susquehanna River Basin Commission, the Delaware 
River Basin Commission and the Joint Pipeline Office for the Trans-
Alaska Pipeline System. Likewise, the Virginia Commission believes that 
there is no conflict between state goals and Commission goals and that 
the two levels of government should be able to work together and avoid 
conflict as long as both parties recognize that the common goal is the 
public interest.
    Commission Conclusion. We continue to believe that states have 
important roles to play in RTO matters. For example, most states must 
approve a utility joining an RTO, and several states have required 
their utilities to turn over their transmission facilities to an 
independent transmission operator. Also, states must approve the siting 
of transmission facilities that are called for in an RTO expansion 
plan.
    We believe, however, that it is not appropriate to try to set out a 
full set of states' roles in this Rule. It is difficult, and not 
necessary, to reach generic conclusions about states' roles given the 
diversity of possible RTO forms and state authorities. For example, a 
state's role may be different for an ISO, transco, and other 
organizational form, and it may be different for a multistate RTO and a 
single-state RTO, if any. States differ regarding the authorities they 
have vested in their regulatory and siting agencies. Further, states 
differ regarding their jurisdiction over municipal and cooperative 
utility owners of transmission facilities.
    Regional interests forming an RTO should consult with the states 
about what state roles best fit the agencies' authorities and 
preferences and the organizational form of the RTO. This role could 
vary from state to state within an RTO. Therefore, this Rule takes a 
flexible approach that allows states to play appropriate roles in RTO 
matters, consistent with this Commission's exclusive responsibilities 
and authorities under the FPA.
    We note that we have discussed the role of states for particular 
RTO functions elsewhere in this Final Rule. Regarding RTO formation, 
the Background discussion above discusses the role that several states 
played in creating many of the existing ISOs. It also describes our 
initial consultations with state regulators on RTO formation and our 
roles in FPA section 202(a) implementation; in those consultations we 
offered to continue the RTO dialogue with states in the future. The 
form of consultation to be used should be decided based on the issues 
and the region so we will not endorse or reject here any particular 
form of collaboration. However, in the Collaborative Process discussion 
below, we set out our plans to invite states and others to work with us 
to foster RTO formation beginning early next year.
    In our discussion above of the Independence characteristic, we 
discuss the role of state agencies in governance, making the point that 
states will play a key role in RTO formation and development but 
declining to specify generically a state's role in governance. Also, in 
our discussion above of the RTO Planning and Expansion function we 
recognize the exclusive authority of state and local governments and 
regulatory agencies over the siting of transmission facilities, and we 
include in our regulations the standard that an RTO must accommodate 
efforts by state regulatory commissions to create multi-state 
agreements to review and approve new transmission facilities.
8. Accounting Issues
    Although not discussed in the NOPR, EEI commented on some 
accounting aspects of RTOs. It urges the Commission to address two 
primary accounting issues for RTOs: (1) The need to revise the Uniform 
System of Accounts (USofA) and related reports to reflect new RTO and 
other unbundled rate structures; and (2) the ability of RTOs to use 
regulatory accounting.
a. Revision of the Uniform System of Accounts
    Comments. EEI contends that because the Commission's USofA was 
developed when utilities' products were bundled and fully regulated, it 
needs to be revised to support the Commission's adopted policies and 
this proposed rule. EEI believes that with unbundling of rates, the 
USofA will need to be revised to reflect, among other things,\718\ cost 
functionalization (e.g., by generation, transmission, distribution, 
etc.). EEI also believes that the Commission should specifically 
address the accounting to be used for RTO reporting purposes, as the 
current USofA was not designed for use by RTOs. EEI states that it is 
very willing to work with the Commission's staff to address the 
specific changes that should be made to the USofA.
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    \718\ Another significant area cited is whether the Commission 
should modify its original cost accounting requirements for property 
acquisitions to conform with the evolving fair value requirements of 
the Financial Accounting Standards Board (FASB). See Appendix I to 
EEI Comments at 11.
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    Commission Conclusion. The Final Rule permits the various regions 
to select different organizational forms for RTOs. Our open 
architecture structure for RTOs permits applicants to select the 
business organization best suited to the needs of its members and RTO 
participants. It would therefore be difficult to prescribe in this 
proceeding specific changes to our existing USofA that would 
accommodate the needs of all RTOs.
    We believe a better course at this juncture would be to require 
RTOs to conform their accounting to our USofA (as have ISOs) and to 
submit questions of doubtful interpretation to the Commission for 
individual or generic rulings on particular transactions, events and 
circumstances.
    However, we agree with EEI's observation that unbundling of utility 
services, and other changes in the industry require the Commission to 
re-examine its existing accounting and related reporting requirements. 
This is true not only for the new types of utilities that have emerged 
in the industry such as ISOs, PXs and RTOs,

[[Page 939]]

but also for traditional public utilities. The Commission staff has 
been and will continue to meet with EEI and others, and will continue 
its efforts to address the specific changes that may be needed as the 
industry restructures.
b. Ability to Use Special Accounting
    Comments. EEI asks the Commission to consider the impact of its 
actions on the ability of RTOs to use the special accounting rules 
applicable to cost-based rate-regulated entities.\719\ EEI believes 
that the ability to use regulated accounting would be advantageous to 
RTOs and viewed favorably by the investment community.\720\ EEI urges 
the Commission to structure alternative ratemaking methods (e.g., price 
and revenue caps, incentive-based rates and price indexing) to allow 
RTOs to continue to use the special accounting of SFAS 71. In this 
regard, EEI believes that if the Commission decides it is advantageous 
to stimulate the establishment of RTOs by ensuring that all start-up 
costs are ultimately recovered through FERC jurisdictional rates, it 
could issue ratemaking orders that defer expense recognition of these 
costs, and allow for future ratemaking recovery. Similarly, EEI urges 
the Commission to address the time frame over which software 
development costs could be recovered through rates and to allow 
utilities to defer expense recognition of such costs. To enhance cash 
flows from operations, EEI suggests that the Commission accelerate the 
amortization of all capitalized software costs. These actions, 
according to EEI, would likely be viewed favorably by the investment 
community.
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    \719\ The special accounting rules are primarily contained in 
Statement of Financial Accounting Standards No. 71, Accounting for 
the Effects of Certain Types of Regulation (SFAS 71). One of the 
primary accounting differences is the ability to defer expense 
recognition of an incurred cost if it is probable that the utility 
will recover that cost in future cost-based regulated rates.
    \720\ Conversely, according to EEI, the inability of an entity 
to use SFAS 71 accounting could have an adverse effect on earnings, 
which may be viewed unfavorably by investors. According to EEI, one 
example would be where the Commission approves a rate levelization 
plan (e.g., under capital lease transactions) under which rate 
recovery of certain costs would be deferred until future years. If a 
utility could not defer expense recognition of such costs, earnings 
would be depressed in the early years of the levelization plan.
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    Commission Conclusion. RTOs may propose and we are willing to 
consider alternative ratemaking methods including proposals to delay 
rate recovery of certain expenses. We will not prescribe any specific 
requirements at this time but allow RTOs to propose those methods which 
are appropriate for each RTO's facts and circumstances. In this regard, 
we intend to take a flexible regulatory approach toward approving RTO 
rate design proposals and strive to include adequate information in our 
rate orders on the appropriate accounting treatments.
9. Market Design Lessons
    We expect that bid-based markets will be a central feature in many 
RTO proposals. To date, the Commission has analyzed and approved, with 
various modifications, bid-based market designs for four ISOs. The 
purpose of this section is to summarize the lessons learned from these 
real-world market experiments. The summary provided below is not 
intended to favor one market design over another, but is intended to 
assist RTOs in evaluating existing market designs and meeting the 
deadlines set forth in this rule.\721\
---------------------------------------------------------------------------

    \721\ The Commission has already given considerable guidance on 
numerous market design issues in a number of orders. See 
Pennsylvania-New Jersey-Maryland Interconnection, L.L.C., 81 FERC 
para. 61,257 (1997); Central Hudson Gas & Electric Corp., et al. 86 
FERC para. 61,062 (1999); New England Power Pool, et al. 87 FERC 
para. 61,045 (1999); AES Redondo Beach, et al., 87 FERC ] 61,208 
(1999).
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    Cal ISO, PJM and ISO-NE have had operational experience with their 
respective market designs. For the most part the markets operated by 
these ISOs have functioned well, and they have not experienced many of 
the problems encountered in the bilateral markets in the Midwest and 
the Southeast.\722\ However, each of the operational ISOs has 
encountered some market design problems that have resulted in 
unexpected or undesirable market outcomes.\723\ These outcomes have led 
some ISOs to file many market design changes and requests for temporary 
remedies or protections until permanent design changes can be 
implemented.\724\
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    \722\ See Staff Report to the Federal Energy Regulatory 
Commission on the Causes of Wholesale Electric Pricing Abnormalities 
in the Midwest During June 1998 (September 28, 1998).
    \723\ The NY ISO has had little operational experience with the 
particulars of its markets design.
    \724\ See New England Power Pool, et al., 87 FERC para. 61,055 
(1999); AES Redondo Beach, et al., 87 FERC 61,208 (1999); New York 
Independent System Operator, Inc. et al., 88 FERC para. 61,228 
(1999).
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a. Multiple Product Markets
    The bid-based markets that we have approved to date are premised on 
the assumption that acceptance of voluntary supply and demand bids 
which maximize overall net benefits will also maximize efficiency. Each 
approved ISO design employs some bid-based mechanism to ramp resources 
up and down to balance the system, manage congestion, and to supply 
some ancillary services. Employing bids that indicate a generator's 
willingness to be ramped down, ramped up, or placed in reserve is an 
economic way to balance the system, manage congestion and maintain 
appropriate reserves, both in real time and in any day-ahead markets. 
However, if more than one product is being sold in the same temporal 
market,\725\ efficiency is maximized when arbitrage opportunities 
reflected in the bids are exhausted (i.e., after the RTO's markets have 
cleared, no technically qualified market participant would have 
preferred to be in another of the RTO's markets). In addition, 
efficient bid-based markets elicit prices that are consistent with 
technical and cost requirements.\726\ For example, a situation where 
generating units are paid more for not generating than for generating 
as has happened in ISO-NE and the Cal ISO may be an indication of an 
inefficient market.\727\
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    \725\ For example, energy and operating reserve products may be 
offered in real-time.
    \726\ One would expect that services with more stringent 
technical requirements ordinarily have higher costs for providing 
those services. The prices of these services should reflect the 
costs. For example, spinning reserves have more stringent 
requirements and would be expected to command a higher price than 
non-spinning reserves.
    \727\ See Report of the Market Surveillance Committee of the 
California Independent System Operator, October 18, 1999 (MSC 
October Report). Both ISOs have seen prices for services such as 
non-spinning reserve products, which do not require a unit to be 
running, higher than the energy price. Also, according to the Market 
Surveillance Committee (MSC) of the Cal ISO, market participants 
have an incentive to submit schedules that will cause congestion so 
that their units can be called upon to relieve the congestion and 
receive payments for not generating that are greater than payments 
received for generating.
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b. Physical Feasibility
    Proper design of the market clearing procedures ensures that prices 
balance the supply and demand for energy, and all transactions, in the 
aggregate, are physically feasible with appropriate levels of reserves. 
Some market designs have allowed ISOs to accept schedules that have not 
been physically feasible (e.g., Cal ISO), while other ISO market 
designs include mechanisms to ensure the physical feasibility of 
transactions (e.g., the NY ISO and PJM). Some ISOs have encountered 
instances where transmission constraints have prevented the use of 
needed reserves,\728\ and this is inconsistent with the operator's 
obligation to make certain that reserve requirements are met and that 
reserves, along with necessary transmission, are available to respond 
appropriately to contingencies.
---------------------------------------------------------------------------

    \728\ See MSC October Report, at 67, 74-75.

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[[Page 940]]

c. Access to Real-Time Balancing Market
    Real-time balancing refers to the moment-to-moment matching of 
loads and generation on a system-wide basis. Real-time balancing is 
usually achieved through the direct control of select generators (and, 
in some cases, loads) that increase or decrease their output (or 
consumption in the case of loads) in response to instructions from the 
system operator. Over the last several years, the Commission has seen 
an increasing use by system operators of market mechanisms that rely on 
bids from generators to achieve, overall, real-time balancing. In order 
to maintain system balance, the operator also manages congestion while 
maintaining the appropriate level of reserves. It is expected that any 
RTO balancing markets will be available to all grid users, i.e., 
including individual grid users that engage in bilateral transactions. 
The fact that the overall system must be in balance moment-to-moment 
does not mean that there must be a moment-to-moment balance between the 
specific load and resources involved in individual bilateral 
transactions. Making a real-time balancing market available to all grid 
users ensures that all users are treated equally for purposes of 
settling their individual imbalances. The four operating ISOs approved 
by the Commission already operate such markets.
d. Market Participation
    Markets are most efficient when generators and loads, whether 
internal or external to the RTO, are allowed full and flexible 
participation in the markets. While generators and loads have the 
option to choose between participating in any RTO-facilitated markets 
or other markets, the RTO must have generation and ancillary service 
quantity information, and any necessary technical information, from 
self-schedulers in order to balance the system and ensure reliability. 
This allows bilateral and forward financial markets and independent PX 
markets to co-exist and complement RTO physical markets. Participants 
that self-schedule would be expected to pay for the costs that they 
impose on the physical system at market prices and be paid for the 
benefits that they supply to the physical system at market prices.\729\
---------------------------------------------------------------------------

    \729\ Costs and benefits associated with self-schedules are 
congestion costs created by the transaction or congestion relief 
that the transaction makes possible.
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    Unnecessary constraints on the imports of services can lead to 
increases in price volatility due to thin markets.\730\ Allowing 
exports will give generators flexibility to take advantage of 
opportunities outside of the RTO boundaries, while allowing load 
serving entities external to the RTO a chance to purchase services. 
Broadening market participation deepens the market and enhances overall 
efficiency.
---------------------------------------------------------------------------

    \730\ Thin markets refers to a situation in which the amount bid 
into the market is either not enough to match demand, or just enough 
to match demand.
---------------------------------------------------------------------------

e. Demand-Side Bidding
    Existing ISO markets offer generators flexible participation, but 
they often do not offer customers demand-side bidding options. Demand-
side bidding is desirable to the extent it is technically feasible, 
because without it, demand response decreases and market power is 
easier to exercise.\731\ The availability of price responsive demand 
also reduces price volatility in the markets.
---------------------------------------------------------------------------

    \731\ The flexibility of demand-side bidding may be limited 
unless real-time meters are installed. Otherwise, demand-side 
bidding can simply take the form of interruptible load.
---------------------------------------------------------------------------

f. Bidding Rules
    A market that provides the flexibility for all generators to bid a 
reasonable approximation of the costs they incur including start-up, 
minimum load, energy, and ramping costs will be efficient. Whether it 
is cost-effective to start up a generator and make it available for 
dispatch depends on the prices and scheduled quantities over the 
multiple hours and services for which the generator is committed, not 
on the prices in any single hour or for any single service. Allowing 
participants to bid these costs helps provide for a more efficient 
dispatch of generating units to meet load and other services, because 
it allows the start-up decisions underlying the dispatch schedules to 
be based on prices and quantities for a period greater than a single 
hour. Not permitting start-up and minimum load bids can reduce 
efficiency because the decision to start up and dispatch generators is 
made separately for each hour, resulting in start up decisions that can 
cause losses for generators. Also, when the start-up and minimum load 
bids are submitted along with minimum run and down times, generators 
are ensured that they will not be dispatched in a way that is 
physically damaging to the unit.
g. Transaction Costs and Risk
    Transaction costs associated with participation in well functioning 
RTO markets should be low, and market participation should involve no 
unnecessary risks. For example, in sequentially clearing markets, 
bidders are exposed to the risk that they may be chosen in one of the 
markets that clears first, yet would have preferred to have been chosen 
in a market that cleared later. In order to hedge against such risks, 
bidders may undertake expensive and time consuming bid preparation 
strategies to decrease the likelihood that such profitable 
opportunities would be missed.
h. Price Recalculations
    In some instances, it may be necessary to post prices on a 
preliminary basis while the final price calculations are verified. For 
example, in ISO-NE, the computer algorithms generate new dispatch 
points every five minutes, and preliminary market clearing prices are 
based on these dispatch algorithms. However, the actual dispatch 
instructions are issued manually. In circumstances where time does not 
permit all changes in dispatch to be communicated and effected through 
manual processes in a timely manner, the market clearing price 
resulting from the computer algorithm must be adjusted to reflect the 
actual dispatch in the hour.\732\ While an RTO must ensure that the 
final market clearing prices are correct, market clearing procedures 
should minimize price recalculations. Also, any price recalculation 
should be done quickly. Otherwise, market participants could incur 
large transaction costs in attempts to hedge against such risk. Risk 
exposure can be further reduced if market participants can engage in 
bilateral transactions, or participate in other markets, to lock in 
prices prior to participating in the RTO-facilitated markets.
---------------------------------------------------------------------------

    \732\ See ISO New England, Internal Review of Operations, June 
7-8, 1999, Report issued August 20, 1999. Electronic dispatch is 
under consideration in ISO-NE.
---------------------------------------------------------------------------

i. Multi-Settlement Markets
    Multi-settlement markets may involve a day-ahead and real-time 
market. For real-time markets, prices are determined by real-time 
dispatch quantities, and deviations from day-ahead schedules are priced 
at the real-time price. When day-ahead schedules are financially 
binding, they are financial commitments subject to payments for 
deviations at the real-time price. If market participants adhere to 
day-ahead schedules, they need not participate in the real-time 
markets. If needed for reliability, bids need to be physically binding 
and may be subject to Commission-approved penalties for failure to 
adhere to the bid. Without financially binding commitments in the day-
ahead market, the riskiness of market participation

[[Page 941]]

increases since the day-ahead bids could be changed before real-time 
dispatch. If bids for ancillary services are accepted, the accepted 
capacity must be physically ready to meet reliability commitments when 
called upon. The lack of a physical capacity commitment has been a 
problem in some ISOs.
j. Preventing Abusive Market Power
    An efficient market design does not favor market participants that 
have the potential to exercise market power and minimizes the 
incentives for market participants to engage in abuse of market power. 
For example, since large players are more likely to cause market power 
problems, a market design that favors large players (e.g., portfolio 
bidding \733\) may create an incentive for consolidation and resulting 
market power problems. Fewer restrictions on imports of services will 
help guard against thin markets, which in turn will help mitigate 
market power. ISO's have experienced problems with thin markets, and 
easing restrictions on imports should help.\734\ Also, artificially 
segmenting a product market into separate geographic markets for the 
same product can also create additional price volatility and 
opportunities for the exercise of market power.\735\
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    \733\ Portfolio bidding refers to bids that aggregate all 
generating units under the same ownership. This is in contrast to 
generation owners bidding in each unit separately.
    \734\ Report of the Market Surveillance Committee of the 
California Independent System Operator, August 19, 1998 at 35-36 
(MSC August Report).
    \735\ The Cal ISO at one time segmented their product markets 
into separate geographic markets that corresponded to the defined 
congestion zones even when no congestion existed. It has since 
reformed this practice. See MSC August Report, at 32-33.
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    If market participants are allowed to submit bids which can then be 
changed before financial settlements are completed, these non-binding 
bids can be used as a signaling device to facilitate collusive 
behavior.
k. Market Information and Market Monitoring
    One property of an efficient market has market clearing prices and 
quantities being made available immediately. This information enables 
market participants and potential future market participants to assess 
the market and plan their businesses efficiently. It will also allow 
market participants to spot errors in the market clearing process and 
get them corrected.
    Disclosure of individual bids could be made eventually, but not 
immediately. Such disclosures will allow detection of market design and 
implementation flaws, and allow study of the market by independent 
analysts and market participants. It may lead to the exposure of the 
exercise of market power. To detect the withholding of capacity, a 
simple screen is to provide the output, reserve quantities, and maximum 
capacity of each generator. Immediate disclosure of individual bids is 
undesirable because it might facilitate collusion by the market 
participants. It also might affect the bids of market participants who 
wish to keep their costs confidential. However, after six months or a 
year, the information on individual bids has essentially no value for 
collusion and discloses little new information about any bidder's 
current costs. Nonetheless, the information's value for market 
monitoring remains high.\736\
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    \736\ The Commission approved the disclosure of bid information 
in the following orders. See PJM Interconnection, L.L.C., 86 FERC 
para. 61,247 at 61,890, order on reh'g, 88 FERC para. 61,274 (1999); 
Central Hudson Gas & Electric Corp. et al. 86 FERC para. 61,062 at 
61,204, order on reh'g, 88 FERC para. 61,138 (1999).
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l. Prices and Cost Averaging
    Market designs that base prices on the averaging or socialization 
of costs,\737\ may distort consumption, production, and investment 
decisions and ultimately lead to economically inefficient outcomes. 
Where possible and cost effective, cost causality principles can be 
used to price services and eliminate averaging.\738\
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    \737\ Socialization of costs means that costs that could be 
assigned to a particular market participant(s) are instead spread 
over all participants regardless of whether or not they caused the 
costs.
    \738\ While it is desirable from an efficiency standpoint to 
eliminate the averaging of costs, the costs associated with 
calculating cost causation in some instances could be shown to 
outweigh the benefits of eliminating averaging.
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    For example, in some congestion management mechanisms, the cost of 
alleviating congestion is spread over all loads. This scheme could have 
some generators creating monetary benefits for other generators. In 
addition, it could lead to over-consumption of power by some loads and 
under-consumption by other loads. Moreover, such averaging mechanisms 
for congestion management do not send the correct price signals for the 
location of new generation, thus leading to problems with long-term 
implications.\739\
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    \739\ MSC October Report, at 112.
---------------------------------------------------------------------------

    Moreover, if pass-throughs or uplift charges are paid by all load 
to ensure bid-cost recovery, as in some approved ISO market designs, it 
may be appropriate to couple these pricing mechanisms with incentive 
mechanisms for the RTO to control them.

I. Collaborative Process

    The Commission proposed a regional collaborative process to 
facilitate the creation of RTOs. State commissions had encouraged the 
Commission to sponsor activities in each region of the country that 
will bring together representatives of public and private electric 
utilities, state regulators, consumer groups, representatives from 
Canada or Mexico, as appropriate, and any other interested parties that 
need to be part of such a process. The Commission proposed that 
regional workshops be held after the Final Rule is issued to determine 
what, if any, impediments exist to the formation of RTOs in a 
particular region and how the Commission staff could help to overcome 
those impediments. Staff resources that will be available for the 
collaborative process include technical staff, dispute resolution 
staff, and any other staff assistance that would be beneficial.
    Comments. Almost all commenters support the Commission's 
collaborative proposal. Of the 49 comments that addressed this issue, 
47 are generally supportive. These commenters include a number of state 
commissions.\740\ In addition, NARUC supports the continuation of a 
``dynamic process requiring continuing dialogue between FERC and the 
states.'' A number of public power entities also support the 
process.\741\ Numerous Canadian entities also filed comments regarding 
the usefulness of a collaborative process for the international aspects 
of RTO formation.\742\
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    \740\ See, e.g., Nine Commissions, Illinois Commission, Indiana 
Commission, Michigan Commission, Montana Commission, Nevada 
Commission, South Carolina Commission, Wisconsin Commission and 
Wyoming Commission.
    \741\ See, e.g., APPA, NRECA, CMUA, SRP, Snohomish, Seattle, 
RUS, East Texas Cooperatives, IMEA, and Arkansas Cities.
    \742\ See, e.g., Powerex, BC Hydro and Canada DNR.
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    Only Florida Commission and CP&L are not fully supportive. Florida 
Commission suggests that FERC collaboration will not work in Florida 
but may work in other regions of the country. CP&L is not supportive 
because the collaborative process could be used by the Commission ``as 
a means of forcing utilities to develop RTO proposals on the 
Commission's timetable'' which results in the Commission ``being 
disingenuous when it describes its RTO policy as `voluntary'.'' 
Otherwise, CP&L believes the conferences will only serve as an 
opportunity for participants to ``posture'' and that limited Commission 
resources should not be used for

[[Page 942]]

meetings that ``are not likely to produce positive results.''
    Specific comments about the collaborative process address three 
basic issues: inclusiveness, process and procedures, and outcomes.
    Inclusiveness. The NOPR stated that ``the Commission expects public 
utilities and non-public utilities, in coordination with appropriate 
state officials, and affected interest groups in a region to fully 
participate in working to develop an RTO.'' It further stated that the 
regional public workshops will be convened in cooperation with the 
affected state officials and that transmission owners and operators 
will be invited.
    Many commenters advocate an open collaborative process that would 
include a full complement of participants. They suggest that the 
regional meetings include representatives of all stakeholders, for-
profit transmission companies, not-for-profit transmission entities, 
state regulators, state legislators, state Governors, state energy 
officials, state and non-state consumer advocates, state economic and 
environmental regulators, environmental action interests and public 
power/municipals. Some commenters indicate that in certain regional 
efforts to form an RTO, the deliberations have excluded key interests 
and, as a result, the outcomes were not widely supported. For example, 
PJM/NEPOOL Customers note with respect to the PJM formation process 
that ``[O]nly after all stakeholders were included in organizational 
discussions was true progress made toward implementing an ISO that 
adequately addresses all parties' needs.'' PNGC states that ``[I]f 
other users do not have a seat at the table while merchant functions 
do, obviously a level playing field is not created.'' New Orleans cites 
Entergy's ``failure to even attempt to build a regional consensus 
concerning its transco as a reason that inclusive regional conferences 
are needed.''
    Process and Procedures. Commenters raise a number of questions 
regarding the collaborative process and specifically with respect to 
the regional public workshops. Many commenters support the use/
availability of the Commission's Dispute Resolution Service (DRS) staff 
or the use of outside facilitators. Some commenters request that the 
Commission clarify that the meetings will be open meetings that can be 
attended by any person. Several commenters urge the Commission to take 
the cost and travel time to attend meetings into account in planning 
the regional public workshops. Some specific locations are suggested 
for sites for the regional workshops: New Orleans, Minneapolis/St. 
Paul, and Seattle or Portland.
    Several commenters suggest that the collaborative process begin 
prior to spring 2000 in at least one region of the country--the Upper 
Midwest. Commenters suggest that there is no need to wait and that the 
region would benefit by immediate assistance from Commission staff as 
described in the NOPR.
    Some commenters ask the Commission to be mindful that the number of 
regional meetings scheduled may not only be costly but unproductive as 
well. Two commenters specifically say that we must not allow the 
``death by meetings'' syndrome to be realized. Some interests may want 
to stall RTO formation by promoting an ``endless'' series of meetings 
that are not productive but are designed to ``preserve the status 
quo.'' A few commenters suggest that the role of Commission staff at 
the regional events should not be that of meeting referee but primarily 
to provide policy guidance on key RTO issues and proposals. NRECA 
proposes the creation of several Commission staff teams to ``facilitate 
and informally monitor each RTO formation process'' and provide 
``neutral guidance'' in the regions. Some commenters ask that the 
Commission establish procedural rules in writing in advance of the 
regional workshops so that all parties will know and understand the 
rules prior to the meetings. Some commenters also request that all 
reports, information and data produced for the meetings be readily 
available to all participants.
    Outcomes. The Project Groups suggest that the Commission should 
``clearly delineate the substantive results expected'' from the 
collaborative process. They suggest that collaboration progress reports 
be filed with the Commission and that ``work products'' be required, 
including: (1) Identification of RTO boundaries; (2) a list of all 
transmission owners and facilities in the region; (3) a draft operating 
agreement; (4) a draft governance structure and bylaws; (5) proposed 
operating protocols; (6) a proposed budget/financial structure; (7) a 
draft tariff; and (8) how the proposals meet the Commission's 
guidelines, including a timetable.
    Commission Conclusion. A key element of this Final Rule is our 
commitment to the use of the collaborative process to assist in the 
voluntary formation of RTOs. By collaborative process, we mean a 
process whereby transmission owners, market participants, interest 
groups, and governmental officials can attempt to reach mutual 
agreement on how best to establish RTOs in their respective regions. We 
reiterate our commitment of Commission staff resources, to the extent 
possible, to assist parties in developing RTO proposals.
    We are encouraged that state Commissions, public utilities, public 
power entities and cooperative utilities, power marketing interests, 
and consumer and environmental groups support the use of a 
collaborative process. We are further encouraged that efforts to 
develop RTOs continue in the West and Midwest, and that other areas are 
reviewing the potential benefits of RTOs in their respective areas. We 
believe that this represents a growing recognition throughout the 
nation that RTOs will improve competition in electric markets and 
enhance the reliability of the nation's electric grid.
    We welcome participation in the RTO collaborative process by our 
sovereign neighbors, Canada and Mexico. We believe that it is in our 
mutual best interest to have electricity flow efficiently and 
economically across our international boundaries. We pledge to continue 
to work cooperatively with officials from Canada and Mexico to 
encourage the operation and improvement of an international electric 
system that benefits all consumers.
    The Commission believes that the collaborative process must 
accommodate the fact that different regions of the country are in 
different stages of RTO formation and must be flexible enough to allow 
for these differences. Therefore, we will initiate the collaborative 
process with a series of five workshops in the Spring of 2000. The 
primary objective of each workshop will be to develop a consensus 
agreement by regional participants establishing a strategic process and 
a schedule for any further collaboration. The appropriate collaboration 
process will depend on whether the region is considering formation of 
an ISO, transco, or other form of RTO. To achieve this objective, 
participants will share information about the status of RTOs or RTO 
proposals in the region, identify impediments to RTO formation in the 
area, explore which process(es) could most expeditiously advance 
agreements on RTO formation, and determine what role(s), if any, 
Commission staff should play in advancing discussions in each region. 
One result of these discussions may be regional decisions that more 
than one RTO would be appropriate in the area encompassed by 
participants at the workshop. Therefore, the collaborative

[[Page 943]]

processes that follow the various workshops may differ significantly. 
This includes possible variations in the role that will be played by 
Commission staff in each RTO formation effort.
    The Commission believes that regional workshops in the Spring of 
2000 will expedite the RTO formation process. In selecting locations 
for the initial Spring 2000 workshops, we recognize trends in the 
broader regionalization of the nation's electric system. We also 
consider the evolving electric markets as well as the configuration of 
the regional grid. We emphasize that the selection of locations for 
initial workshops is not to indicate a preference for specific RTO 
boundaries, but to provide convenient workshop locations. With these 
considerations in mind, we designate the following workshop locations. 
Parties may attend more than one regional workshop. We expect all 
transmission owners to attend at least one workshop.
    Workshops will be held in the following cities in February, March 
or April, 2000:

1. Philadelphia, Pennsylvania
2. Cincinnati, Ohio
3. Atlanta, Georgia
4. Kansas City, Missouri
5. Las Vegas, Nevada

    Workshops are expected to last for two days. Additional information 
about the regional workshops will be provided in January 2000.
    At the request of parties, the Commission staff may play a role in 
the formation of RTOs. Commission staff will convene the regional RTO 
workshops and provide policy and technical guidance consistent with 
this rule. The Commission will supply meeting space for the five 
initial Spring 2000 workshops. Regional participants are expected to 
bear the costs of collaborative meetings after the initial five 
workshops. Commission staff time and staff travel expenses will be 
provided as resources allow.
    We believe that it is critical to make the Spring 2000 Workshop 
phase of the collaborative process open to all interested parties. In 
order to promote an open process, we will provide public notice of 
Spring 2000 Workshop events to allow all interested parties to attend. 
We shall also make available agendas and procedural rules to all 
parties in advance of the regional workshops. Agendas may vary from one 
workshop to another.
    The Spring 2000 Workshops represent the initial step of the 
collaborative process. We expect that other meetings will be convened 
following the workshops by parties in each region to bring the parties 
together to form an RTO in each region. Commission staff may also 
convene additional meetings if this would help RTO formation. The post-
workshop meetings of parties in regions may be held with or without 
Commission staff participation. We will make available the Commission's 
Alternative Dispute Resolution staff upon the request of an RTO group 
in formation. At the request of such a group, independent private 
professional facilitation services may be arranged by Commission staff 
and must be sponsored by the parties within the region. As needed and 
requested by parties forming an RTO in a region, Commission staff 
members will be available to act as settlement judges, mediators, 
facilitators or observers.
    We believe that the best interests of the nation's electric 
consumers will be served by the formation of RTOs. Therefore, we 
encourage parties to establish strategic schedules at the Spring 2000 
Workshops and to convene subsequent meetings with the goal of forming 
an RTO expeditiously. Commission staff will monitor progress with 
respect to the results or outcomes in each region.
    We expect that, following the initial Commission-sponsored 
workshops, parties in each region will work collaboratively to identify 
the appropriate RTO regions, identify all transmission owners and 
facilities in each region, and develop a timely application in 
accordance with the Final Rule.
    We have designated James Apperson of the Commission Staff to serve 
as the collaborative process contact. He may be contacted at (202) 219-
2962 with any questions or comments about the RTO collaborative 
process.

J. Implementation Issues

1. Filing Requirements
    In the NOPR, the Commission proposed that all public utilities that 
own, operate or control interstate transmission facilities (except 
those already participating in a regional transmission entity in 
conformance with the eleven ISO principles enumerated in Order No. 888) 
must file with the Commission by October 15, 2000 either (1) a proposal 
to participate in an RTO that will be operational no later than 
December 15, 2001, or (2) an alternative filing describing efforts to 
participate in an RTO, obstacles to RTO participation, and any plans 
and timetable for future efforts.\743\ For those public utilities that 
file an RTO proposal on or before October 15, 2000, we proposed to 
permit them to file a petition for a declaratory order asking whether a 
proposed transmission entity that would be operational by December 15, 
2001, would qualify as an RTO, with a description of the organization 
and operational structure, a list of the intended participants of the 
institution, an explanation of how the institution would satisfy each 
of the RTO minimum characteristics and functions, and a commitment to 
submit necessary FPA section 203, 205 and 206 filings promptly after 
receiving the Commission's determination on the declaratory order 
petition. Finally, we proposed that the requirements not apply to a 
public utility that owns, operates or controls transmission that also 
is a member of an existing transmission entity that the Commission has 
found to be in conformance with the Order No. 888 eleven ISO 
principles; instead, each such public utility would be required to make 
a filing no later than January 15, 2001, that (1) explains the extent 
to which the transmission entity in which it participates meets the 
minimum characteristics and functions of an RTO; (2) proposes to modify 
the existing institution to become an RTO; or (3) explain efforts, 
obstacles and plans with respect to conforming to these characteristics 
and functions.
---------------------------------------------------------------------------

    \743\ FERC Stats. & Regs para. 32,541 at 33,761-63.
---------------------------------------------------------------------------

    Comments. Most commenters responding on this issue oppose one or 
more aspects of the proposed filing requirements. For example, a number 
of public utilities and two state commissions argue that the October 
15, 2000, filing requirement does not provide enough time. Southern 
Company contends that the proposed filing deadline requirement is 
likely to be counterproductive because it imposes an artificial 
deadline that may interfere with regional discussions. Moreover, once 
established, a prematurely formed RTO may itself prove to be an 
obstacle to more effective transmission organizations. Southern Company 
also claims that the proposed mandatory filing requirements are 
inconsistent with a truly voluntary approach. If the requirement is 
retained, Southern Company suggests that the Commission clarify that 
the alternative filings will be treated as status reports and not be 
subject to deficiency orders or otherwise lead to proceedings in which 
punitive measures might be taken, because any consideration or use of 
penalties seriously undermines the Commission commitment to the 
voluntary nature of RTOs.
    Wyoming Commission recommends that the deadlines not be made

[[Page 944]]

mandatory in any way in the Final Rule because RTO formation is 
supposed to be voluntary. Since it is unclear as to what happens to 
those entities who file an explanation as to why they did not join an 
RTO, Wyoming Commission urges the Commission to defer to each region's 
process and timetable in developing an RTO and acknowledge that not all 
regions are processing at the same pace. It recommends that the 
Commission convert the October 15, 2000, deadline into a milepost for 
reporting RTO development.
    CP&L submits that the time frame is unrealistic because it 
contemplates that new RTOs can be developed, approved by the 
Commission, set up, and begin operation in less than two years. 
Experience has shown that almost every RTO to date has taken at least 
four years to go through that process. Therefore, the Commission should 
modify the filing requirements to simply require informational filings 
on the status of RTO development.
    Sierra Pacific is concerned about insufficient time being allowed 
for transcos to form. It points out that the precedent regarding ISOs 
is much more well-developed than that regarding transcos. The certainty 
surrounding ISOs makes them more attractive particularly when a 
decision to form the entity must be made relatively quickly to meet the 
proposed October 15, 2000, filing date. To lessen the incentive to rush 
to join an ISO, Sierra Pacific suggests that: (1) The date for filing 
an RTO proposal should be extended to June 15, 2002; (2) the Commission 
permit transition mechanisms that will allow transmission owners to 
eventually join transcos; and (3) the Commission not require 
participation in an ISO to become a trap from which a transmission 
owner cannot extricate itself. ComEd provides supporting arguments, 
noting that where divestiture of transmission assets is involved to 
form transcos, the necessary transition period will largely be dictated 
by the sheer complexity--legal, financial (bonds and mortgage), real 
estate (titles/easements), taxation--of separating a designated portion 
of any electric utility that has historically been a vertically 
integrated utility.
    Based on its experience with the Midwest ISO formation process, 
Kentucky Commission also argues that the proposed date to join an RTO 
or respond with reasons for not joining is too short. It points out 
that, if the Commission completes the Final Rule by the end of 1999, 
transmission owners will have less than one year to make a final 
decision on participation. Kentucky Commission urges the Commission to 
give transmission owning utilities additional time to look into joining 
an RTO, so that RTOs are not pushed so quickly that the best model 
fails to materialize as a result of market evolution that remains 
underway. South Carolina Commission and Big Rivers share the concern 
that the proposed timeframe is too ambitious, given the complexity of 
RTO related matters and the need to reach some level of consensus among 
those with vested interests.
    Several commenters noted that meeting the October 15, 2000, filing 
requirement will depend on the Commission's standard of review of those 
filings. For example, TDU Systems observes that the proposed filing 
requirements have no teeth. TDU Systems contends that a public utility 
that decides not to participate in an RTO can make an alternative 
filing setting out the reasons why it is not doing so and what plans it 
has to work towards participation. In TDU Systems' view, while the 
proposed regulations are consistent with voluntary participation, they 
are inconsistent with full and effective participation in RTOs. TDU 
Systems counsels that the Commission should resist calls to water down 
the RTO regulations even more, so as to treat alternative filings as 
mere status reports that allow transmission monopolists to hold on to 
their monopolies.
    Duke submits that if the Commission is willing to accept valid, 
well-justified explanations as to why a utility has not become an RTO 
member, the October 15, 2000, filing requirement is reasonable, noting 
that until state commission review of restructuring and RTOs is 
completed, it may be premature for a utility to commit resources to RTO 
membership. Similarly, Iowa Board suggests that, where transmission 
providers are making legitimate progress, a report to that effect 
should not be received with automatic disfavor. Alternative filings and 
legitimate progress reports should be given equal validity with 
definitive proposal filings.
    A few commenters explicitly support the October 15, 2000, filing 
requirements. For example, SRP believes it to be an acceptable balance 
between mandated participation and the status quo. PJM/NEPOOL Customers 
also support the filing by a date certain because this would expedite 
the collaborative process and ensure that no entity can effectively 
block RTO formation by engaging in inappropriate negotiation tactics. 
And Oglethorpe views the October 15, 2000, time frame as necessary to 
assure the timely development of RTOs and help develop fully 
competitive efficient wholesale markets. Cinergy, noting that only 
after the Commission has had opportunity to review the October 15, 
2000, filings will it be able to determine whether it should order 
participation in or reconfiguration of particular RTOs, suggests that 
by April 15, 2000, all public utilities be required to file a statement 
of position in which each utility identifies each state in which it 
owns transmission, and the RTO in which it is considering membership 
and its potential scope and configuration to the best of its knowledge.
    A number of commenters address issues and treatments relating to 
existing ISOs. Virtually all of the existing ISOs assert that the 
Commission should allow the previously Approved ISOs to continue to 
develop without undue interference in order to foster experimentation 
and testing of proposals.\744\ Cal ISO argues that the Commission 
should find that existing regional entities generally meet the RTO 
criteria and that the Commission should confirm its determination not 
to require substantial changes in approved ISOs that would undermine 
difficult to reach consensus on critical issues. Similarly, the 
Pennsylvania and New York Commissions recommend that FERC grandfather 
the existing ISOs that meet the RTO characteristics and functions. The 
Pennsylvania Commission states that it does not want to tinker with the 
inner workings of PJM, nor constantly revisit and revise operations and 
functions. The New York Commission is concerned that the New York ISO 
tariff may have to incorporate the ``ordinary negligence'' liability 
and indemnification provisions set forth in the pro forma tariff if the 
ISO becomes qualified as an RTO, and that this will increase the ISO's 
exposure to litigation. The South Carolina Commission supports NARUC's 
position urging the Commission to grandfather existing ISO boundaries 
that are satisfactory to the states. Similarly American Forest, CalPX 
and Mid-Atlantic Commissions want the Commission to respect existing 
ISOs.
---------------------------------------------------------------------------

    \744\ See, e.g., NY ISO, Cal ISO, NYPP and ISO-NE.
---------------------------------------------------------------------------

    Furthermore, PJM/NEPOOL Customers contend that their ISOs are in 
basic conformance with the minimum functions and characteristics. To 
the extent that any deficiencies are found, the ISOs should be allowed 
to engage in continued experimentation without interference from the 
Commission. The Wyoming Commission also fails to see why existing ISOs, 
already having gone through a rigorous approval process, should have to 
re-certify as RTOs.

[[Page 945]]

Moreover, EEI notes that the Commission should weigh the incremental 
gains achieved through economies of scale, efficiency, and additional 
savings against the potential incremental costs of reorganization, new 
computer programming, infrastructure changes, and changes required to 
achieve effective communication and coordination. NYPP proposes that 
ISOs be allowed to evaluate the costs and benefits of forming an RTO 
after some years of market experience; hence, they oppose putting 
members of existing ISOs on the same time frame for compliance as non-
members of ISOs/RTOs. United Illuminating recommends that the 
Commission continue to honor and not abrogate pricing arrangements of 
existing ISOs. United Illuminating also contends that, since existing 
ISO members have no opportunity to discriminate because they have 
turned control of their transmission over to their respective ISO, the 
Commission cannot generically abrogate existing ISO pricing 
arrangements pursuant to its FPA section 206 authority in this 
rulemaking. Central Maine offers that consolidating the PJM, New 
England and New York ISOs into a super-ISO will require costly 
expansion of telemetry, communication, and computer equipment, that it 
could result in a decrease in reliability, and that simple 
interregional coordination could accomplish the Commission's goals 
without consolidation.
    A few non-ISO entities oppose any grandfathering of existing 
regional transmission organizations.\745\ For example, New Orleans 
argues that the Commission should not exempt existing regional 
transmission entities from requirements of RTO formation because only 
through universal application will all regions of the country receive 
the benefits of open and competitive electric markets. H.Q. Energy 
Services suggests that a larger territory, such as the combined 
territory served by the existing New York, PJM and New England ISOs, 
would be more effective than the NY ISO standing alone. PG&E counsels 
that freezing the existing ISO structures in place would not serve 
reliability or the marketplace and would be inconsistent with the open 
architecture requirement. It believes that the Commission has struck an 
appropriate balance imposing a reporting requirement on existing ISOs.
---------------------------------------------------------------------------

    \745\ E.g., Illinois Commission, New Orleans, SMUD and Turlock.
---------------------------------------------------------------------------

    Most commenters agree that existing operational transmission 
entities should gradually evolve toward RTOs during a transition 
period, rather than making immediate and drastic changes.\746\ 
According to SMUD, a transition period will enable customers to avoid 
bearing unnecessary costs.
---------------------------------------------------------------------------

    \746\ See, e.g., SMUD, PJM/NEPOOL Customers, NYPP, Cal DWR, 
MEAG, American Forest and Central Maine.
---------------------------------------------------------------------------

    A few commenters address the specific filing requirements outlined 
in the NOPR. The New York Commission asserts that the NY ISO should not 
have to make a filing because it possesses the requirements of an RTO. 
In addition, the Cal ISO argues that existing entities, rather than 
individual public utilities, should be responsible for the RTO filing 
requirements. Likewise, PJM suggests that existing ISOs report to the 
Commission prior to any report by its public utility members, as the 
existing ISO is in a better position to provide the Commission with the 
most accurate information by which to evaluate whether the ISO 
satisfies the minimum characteristics and functions for RTOs. PJM 
suggests that existing ISOs and existing transmission entities file 
reports no later than December 31, 2000, explaining whether they 
satisfy the Commission's requirements for RTOs and identifying any 
additional authority they may require for this purpose. On the other 
hand, EPSA welcomes the proposal requiring a showing of how the 
existing transmission institutions meet the minimum characteristics and 
functions by January 15, 2001, as a way to help address and solve 
continuing discrimination within current ISOs and address whether these 
institutions should be combined into larger groupings. Similarly, NYC 
wants the NY ISO's January 15, 2001, filing to demonstrate how its 
efforts to improve regional cooperation will overcome the institutional 
impediments that have contributed to the city's load pocket condition.
    Finally, commenters raise a number of miscellaneous issues: Puget 
questions whether there will be negative implications for any entity 
the choose to cease participation in an RTO; DOE points out that RTOs 
may need to fund pensions for transferred employees, and existing 
transmission providers may need to fund early retirements or other 
compensation for displaced employees; UMPA recommends that recourse to 
the Commission in a de novo capacity must be part of all RTO dispute 
resolution procedures; and Indiana Commission, Snohomish and Midwest 
ISO express concern about how the Commission intends to handle multiple 
RTO proposals covering approximately the same region.
    Commission Conclusion. The Commission will adopt the NOPR proposal 
requiring 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. As proposed 
initially, we will consider a petition for declaratory order setting 
forth the items listed in section 35.34(d)(3) as a proposal to 
participate in an RTO.
    We believe that the October 15, 2000, date for filing proposals is 
realistic. It is not overly aggressive, given the amount of guidance we 
have provided in this Rule and the amount of flexibility we are 
permitting in how to satisfy the minimum characteristics and functions. 
In addition, the collaborative process that we are promoting in this 
Rule will provide an opportunity for all interested parties with their 
varied interests to resolve many of their differences, in advance, and 
reach consensus on the RTO solution that best fits the overall needs of 
their respective region. The October 15, 2000, filing date should help 
keep the parties focused and accelerate their efforts toward selecting 
an appropriate RTO model.
    The October 15, 2000, date for filing is also reasonable because, 
even if a public utility is unable to file an RTO proposal at that 
time, we are permitting the public utility to make an alternative 
filing reporting on the status of pertinent RTO formation and 
development, the obstacles that have prevented the filing of an 
appropriate RTO proposal, and any of the public utility's plans and 
timetable for future efforts directed toward RTO formation and 
participation.\747\ Given the importance that the Commission places on 
RTO development, it is important for us to understand no later than 
October 15, 2000 just how much progress the industry is making on 
forming RTOs. If the October 15, 2000, filings reveal obstacles that 
prevent serious progress toward RTO formation are reported for a given 
region, we will be able to act early enough to provide guidance on what 
steps we think are appropriate to help address the obstacles (e.g., 
further collaborative efforts). And where serious regional progress is 
reported, but more time is requested in connection with meeting a 
particular RTO requirement, we will be able to act early enough to try 
to accommodate the local needs,

[[Page 946]]

complications and complexities that the particular region faces.
---------------------------------------------------------------------------

    \747\ Of course, these reports may be filed prior to October 15, 
2000.
---------------------------------------------------------------------------

    Some concern has been expressed that the October 15, 2000, filing 
date is too short to allow transcos to form because of the inherent 
legal, financial, real estate and taxation complexities associated with 
the transfer of ownership of the affected transmission assets. We are 
not proposing that the restructuring be completed by October 15, only 
that a proposal be filed, or an alternative filing as described in this 
Rule. Moreover, we take note of the fact that other forms of major 
corporate restructuring, including mergers, have proceeded from initial 
idea to formal proposal in a shorter time when the motivation is 
sufficient. Therefore, we do not think the time allowed is too short 
for transco proposals.
    We also reaffirm the proposed January 15, 2001, filing date for 
transmitting public utility members of an existing approved 
transmission entity to address the extent to which that entity conforms 
to the minimum characteristics and functions of an RTO, any plans to 
make it conform, and any obstacles to full conformance with our Final 
Rule. We note that RTOs will not be ``starting from scratch.'' There is 
significant information available about both the good and bad 
experiences with ISOs, and this information should help RTOs meet this 
filing deadline.
    While we are allowing a later filing date for existing transmission 
institutions to file (January 15, 2001, versus October 15, 2000), we do 
this because, in general, the transmission owners in those regions have 
already made substantial progress in establishing regional entities. 
Nonetheless, the Commission needs to know, for all regions, including 
those covered by existing approved transmission institutions, the 
extent of progress toward formation of fully functional RTOs. To the 
extent that an existing ISO, for example, is less than adequate with 
regard to one of the necessary characteristics or functions, we would 
expect the existing institution to be working on a plan of action to 
make the remedial improvements that are required to bring it into 
conformance with the Final Rule.
    In sum, we continue to believe that the October 15, 2000, and 
January 15, 2001, filing dates represent an acceptable balance between 
the need to move toward RTOs as soon at possible and the need for 
sufficient time for transmission owners and market participants to 
develop proposals.
2. Deadline for RTO Operation
    The Commission proposed that all public utilities participate in an 
RTO that will be operational by December 15, 2001. In addition, we 
contemplated implementation of the congestion management function 
within one year after startup (by December 15, 2002), and 
implementation of inter-regional parallel path flow coordination and 
transmission planning and expansion functions within three years after 
startup (by December 15, 2004).
    Comments. Most commenters suggest the December 15, 2001, deadline 
should be changed to a later date or that the Commission provide 
greater flexibility in meeting the deadline. On the other hand, Oregon 
Commission explicitly favors the December 15, 2001, deadline, arguing 
that the time line is designed in stages so that the easiest 
requirements come earliest. EPSA fears that further delay of any of the 
operational deadlines for any of the required RTO functions (i.e., for 
initial startup, congestion management, parallel path flow 
coordination, or transmission planning and expansion) will only 
encourage further debate and dialogue without driving the industry 
towards acceptable resolutions, and prolong the problems of residual 
discrimination and remaining market inefficiencies.
    Two commenters propose an earlier deadline. PG&E contends that the 
transition period for RTOs to meet all requirements must be as short as 
possible--no more than one or two years to fully operational RTOs may 
be reasonable. Sithe similarly argues that, while the negotiations and 
proceedings associated with voluntarily RTOs can take years to 
complete, the California experience suggests that an RTO can be 
established quickly if a deadline exists. Sithe recommends that the 
Commission reconsider its time frame and do everything it can to hasten 
the process of putting in place RTOs with all minimum characteristics 
and functions. It observes that, as proposed in the NOPR, an RTO could 
defer for up to three years the filing of a plan for transmission 
planning and grid expansion. The details may not be finally approved by 
the Commission for at least another year such that a delay of over five 
years could result.
    SRP and American Forest express concern about who will be 
responsible for building and paying for new transmission facilities 
until the RTO takes on this responsibility. In particular, SRP suggests 
that the Commission require each RTO filing to describe who will be 
responsible for financing and building transmission expansions during 
the interim.
    Most commenters, however, view the proposed deadline as too 
aggressive, and recommend that it be eliminated or extended. CP&L views 
the operating deadline as arbitrary and capricious, and argues that the 
deadline will impose higher implementation costs and inefficiency that 
will not benefit the public or the industry. South Carolina Authority 
believes that to assume that a large group of stakeholders with diverse 
interests can somehow come together and agree on a particular RTO model 
and configuration by October 15, 2000 that is up and running by 
December 31, 2001, is unrealistic. East Kentucky suggests that the 
timetable be extended approximately two years. Montana Power encourages 
extension by one year because areas like the Pacific Northwest will 
probably need significant infrastructure to be developed or re-deployed 
and the 14 month time frame contemplated after RTO proposals are due on 
October 15, 2000, is not sufficient time.
    A number of commenters favor a flexible approach and allowing 
provisional RTO status. Cinergy offers that, to overcome obstacles such 
as legal impediments to public power participation, alternative means 
of RTO participation be considered such as joint operations without the 
functional integration of public systems' facilities to allow them to 
control the private use of their systems. SERC generally concurs. 
Williams contends that not all RTOs will be able to develop at the same 
pace, and supports provisional RTO status with dates certain respecting 
those functions not able to be performed at startup.\748\ SNWA 
recommends that, if necessary, a phase-in approach should be used in 
the implementation of an RTO to smooth the implementation process. 
Project Groups contends that, given the California experience, the cost 
of attempting to do everything at once is significant. Transmission ISO 
Participants urges flexibility for transmission owning members of 
exiting ISOs since the current structure represents an imperfect and 
probably unfinished agenda. EEI contends that the Commission should 
allow flexible timetables to establish RTOs that are transcos, 
contending that a vertically integrated utility that selects the option 
of moving transmission assets to a transco faces complex financial and 
tax issues. Nevada Commission urges the

[[Page 947]]

Commission to clarify that there is no prohibition against forming 
interim organizations such as an independent system administrator until 
such time as a viable RTO for the region is formed. South Carolina 
Commission claims that each RTO proposal should be reviewed on a case-
by-case basis for general adherence to the Commission's overall policy 
goals.
---------------------------------------------------------------------------

    \748\ Note that a number of comments opposing deadlines are 
based on the difficulty of attaining specific RTO functions. These 
comments are also addressed in the sections regarding the specific 
functions.
---------------------------------------------------------------------------

    Indiana Commission cautions, however, that careful consideration 
should be given to what will be lost by the acceptance of an RTO 
``lite.'' It argues that existing transmission entities may see little 
value in maintaining relatively high standards and could view the 
Commission acceptance of lower standards as an incentive to gravitate 
to lower standards. PG&E recommends the Commission grant waivers from 
its requirements only in limited cases and only for short durations. 
AEPCO, contends that there should be a reasonable basis for granting 
waivers, particularly for non-jurisdictional entities. In particular, a 
request for waiver should consider: (1) How much additional RTO 
transmission would result from inclusion of the facilities in an RTO; 
and (2) whether the RTO would be functional without inclusion of the 
entity's facilities. Sithe argues that care should be taken when 
considering whether to permit RTOs to go into effect without meeting 
functions and in granting waivers, and suggests that the Commission 
establish clear requirements for RTO approval, strictly scrutinize 
proposals, and not hesitate to reject inadequate proposals.
    Commission Conclusion. We have decided to retain 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 
December 15, 2004).
    As a general proposition, we believe that, given the urgent needs 
of electricity markets as discussed elsewhere in our Final Rule, we 
have an obligation to promote RTO operation at the earliest feasible 
date. Even where a market may already be served by an ISO or other 
approved transmission entity, we are concerned that such market may 
remain hampered to the extent that the approved entity has yet to fully 
conform with our Final Rule.
    In response to those who contend that December 15, 2001, is too 
ambitious for RTO start-up, we note several points. First, we, and the 
industry, now have had the benefit of the experience of the formation 
of five ISOs under Commission jurisdiction, an ISO in ERCOT, some 
international experience with regional transmission entities, and 
substantial discussion of the subject of regional transmission entities 
within the industry. While the timeframe we are suggesting for RTO 
formation may have been unrealistic several years ago, much has been 
learned since then which should facilitate more rapid formation.
    Second, our Final Rule is providing substantial flexibility that 
should permit an RTO to satisfy the minimum characteristics and 
functions in a cost efficient manner. For example, we are not requiring 
control area consolidation; we are not requiring the establishment of a 
PX; we are allowing an RTO to meet its operational control obligation 
through indirect or hierarchical control arrangements via contractual 
agreements with the existing infrastructure such as transmission owners 
and control area operators; and we are allowing an RTO to satisfy its 
security coordinator functions through contractual arrangements with an 
external security coordinator, as long as it is independent. 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 directly ``push all of the buttons.'' Moreover, we are allowing a 
longer phase-in period for functions that may be more difficult to 
establish, such as congestion management, parallel path flow measures, 
and transmission planning and expansion.
    With respect to the comments that question the December 15, 2002, 
deadline for implementing the congestion management function, we 
believe that lack of effective and market-oriented congestion 
management is a critical issue in the industry, and that it needs 
attention soon. We acknowledge that developing a sophisticated 
congestion management program can be an extremely complex and time 
consuming matter. However, implementation of economic approaches to 
congestion management by some of the approved ISOs shows the 
feasibility of these concepts where there is an institution to 
undertake the organization of this function over a large area.
    Some say that transmission congestion is not a serious problem in 
their regions, and that they therefore should not be required to 
develop a complex congestion management plan within a short time-frame. 
We agree that an RTO should not have to expend large resources to 
address a problem that does not exist. However, we are concerned that 
an RTO fully analyze the extent to which transmission congestion does 
or could interfere with electricity sales in its region, and that it be 
prepared to address congestion if it becomes a more serious problem 
through changing markets. As markets become more competitive and the 
volume of discrete transaction increases, transmission congestion may 
become serious unless action is undertaken beforehand. Where 
transmission congestion is infrequent, this Rule does not preclude the 
establishment of relatively less complex forms of market-compatible 
congestion management such as generation redispatch protocols.
    In sum, we think that the phased startup and other functional 
implementation deadlines are reasonable.
3. Commission Processing Procedures
    The Commission recognized that RTO formation would be complicated 
by the requirements for Commission approval of transfer of control of 
jurisdictional facilities under FPA section 203 and Commission approval 
of RTO transmission rates, terms and conditions under FPA section 205. 
In the NOPR, the Commission requested comments on whether the 
Commission should provide expedited or streamlined processing 
procedures for RTO filings and asked for suggestions regarding how the 
Commission can further expedite and streamline procedures.\749\
---------------------------------------------------------------------------

    \749\ FERC Stats. and Regs. para. 32,541 at 33,759.
---------------------------------------------------------------------------

    Comments. Views on streamlined and expedited processing of RTO 
filings are mixed. Commenters that generally favor streamlining include 
Desert STAR and TEP, which suggests that filing requirements be kept 
simple and flexible.
    A number of commenters offer specific suggestions for streamlining 
and expediting the process, including:
     Florida Commission believes that once an RTO or other 
structure has been agreed upon by a group of entities, the Commission 
should expedite all required processes in order to allow the 
participants to start implementing the agreed upon changes.
     Tallahassee recommends that the Commission should clarify 
that it is not revisiting the functional test for distinguishing 
transmission and distribution facilities addressed in Order No. 888.
     Entergy asserts that significant delay in obtaining 
Commission approvals will make it difficult for Entergy to institute a 
transco within the time-lines established by state restructuring laws 
in Arkansas and Texas. Providing clear rules on the

[[Page 948]]

required and permissible features of RTOs as the Commission did in its 
July 30, 1999 Declaratory Order for Entergy and providing clear 
standards on pricing policies will help. Entergy argues that the 
Commission should make explicit its willingness to consider requests 
for expedited approval when a showing is made that expedition is 
necessary, as it has done for California ISO.
     Trans-Elect notes that if a transfer of facilities cannot 
close under Section 203 until the related FPA section 205 proceeding is 
concluded, an expedited Section 205 filing must also take place. One 
way to do this is to waive an Initial Decision and set a date certain 
for the Commission's section 205 decision.
     PJM/NEPOOL Customers recommend that a standard RTO 
governance structure be adopted that allows participation by all 
stakeholder groups. It would expedite processing by requiring that any 
RTO filing demonstrate that all stakeholders were included in the 
formation process.
     SMUD recommends that the Final Rule require that RTOs be 
designed, developed and implemented in a manner that does not require 
numerous tariff amendments to remedy market ills that could be 
addressed prospectively or at a speed that does not dramatically 
increase RTO development costs.
    On the other hand, some commenters urged the Commission to exercise 
caution regarding streamlining and expediting:
     East Texas Cooperatives observes that a poorly configured 
RTO can potentially be more harmful to the industry than the status 
quo, by allowing large transmission owners to dominate regional grid 
management, maintain pancaked rates and discriminate in allocating 
transmission revenue.
     Indiana Commission recommends that state commissions and 
other interested parties have full opportunity to thoroughly review, 
comment, and have an impact on the RTO proposals once they are filed 
with the Commission.
     Puget indicates that a negative implication of allowing 
streamlined filing and approval procedures for RTO participants is that 
regulatory burdens will be leveled against nonparticipants while those 
who join an RTO will be freed from what the Commission implicitly 
recognizes are unnecessary requirements. A truly voluntary system would 
not continue to impose unnecessary regulatory requirements on 
nonparticipants and there is no reason for the Commission to delay 
implementing these regulatory reforms now before a final decision is 
made regarding the wisdom or efficacy of RTOs, or to condition the 
implementation of such reforms on an entity's participation in an RTO.
     Duke contends that, given the size and complexity of the 
typical section 203 and 205 of the FPA filings, it is not clear that 
reducing the time that parties are granted to review such filings and 
provide initial comments may be appropriate. Nonetheless, the 
Commission should work to dismiss irrelevant issues used as leverage to 
extract concessions unrelated to RTO formation, it should consider use 
of less formal hearing procedures for issues that do not require 
discovery, and the Commission should limit the time period allowed for 
evidentiary hearings. Duke acknowledges that the effect of streamlined 
filing and approval procedures could be to reduce costs that would 
otherwise be born by market participants.
    Commission Conclusion. While there is broad-based consensus for 
simplifying the Commission's RTO filing process and responding to RTO 
proposals expeditiously, we must maintain an appropriate balance 
between streamlining and expediting the filing and processing of RTO 
proposals and ensuring due process and the development of an adequate 
record. Given the amount of flexibility we have built into the Rule as 
to organizational structure, it is difficult to predict what issues 
will be raised by the RTO proposals and the degree of complexity raised 
by such issues. Accordingly, while the Commission has the goal of 
ensuring the rapid formation of RTOs, and will attempt to process each 
RTO proposal as expeditiously as possible, certain RTO proposals will 
take longer to analyze and review depending upon the complexity of the 
issues and the level of support among the affected parties. Therefore, 
in addition to the specific guidance provided elsewhere in this Rule, 
we provide further guidance and note the following factors which are 
intended to assist public utilities in streamlining their required 
filings and help expedite the processing of the RTO proposals.
    One factor that should facilitate faster processing is that the 
Final Rule permits delayed implementation dates for various highly 
complex FPA section 205 related RTO provisions (congestion management 
by December 15, 2002, and parallel path flow coordination and 
transmission planning and expansion each by December 15, 2003). 
Therefore, initial RTO proposals need not contain the details for these 
provisions, but need only contain a commitment to complete the 
provision and a timetable for submitting appropriate future filings. 
Likewise, we need not act on those matters initially in our RTO orders.
    Expeditious processing of an RTO submittal is more likely to occur 
if the RTO proposal is the result of a comprehensive and open 
collaborative process with widespread support from transmission owners, 
market participants, and affected state commissions. While we cannot 
pre-approve unopposed proposals, many of our potential concerns could 
be minimized to the extent the proposal has broad support.
    Another potential streamlining measure is that public utilities are 
permitted to file RTO proposals jointly with other entities. For 
example, in the case of existing ISOs and other approved regional 
transmission entities, the regional entity may file on behalf of the 
individual public utilities. This will reduce the volume of submittals 
that must be developed by public utilities and be reviewed by the 
Commission.
    We note that, with the exception of governance, experience gained 
from past ISO proceedings, will be directly transferable whether the 
form of RTO is an ISO or a transco. For transcos, as discussed 
elsewhere in the Final Rule, restrictions on ownership of transcos that 
we have adopted are designed to work in tandem with restrictions on 
governance in order to ensure adequate levels of independence.
    We believe that RTO proposals that reflect the above factors, 
should allow the Commission to minimize the amount of time necessary to 
analyze and process the submittal. While the Commission cannot 
guarantee that we will be able to respond to every proposal within a 
pre-set period of time, we will make every reasonable effort to issue 
an initial order on an RTO proposal within 60 days,\750\ after the 
comment period closes.\751\ With respect to RTO proposals that present 
contested issues or problematic RTO provisions, we will make every 
effort to expedite

[[Page 949]]

consideration of the proposed RTO and we will continue to consider 
alternatives to formal procedures (e.g., ADR procedures), where 
warranted, to avoid initiating a hearing.
---------------------------------------------------------------------------

    \750\ We recognize that, while there is no statutory deadline to 
act on section 203 filings, there is a 60-day statutory clock 
requiring action on section 205 related filings within 60 days from 
the date of filing, in the absence of a proposed effective date 
extending beyond the 60-day time frame. However, in most instances, 
we expect that the RTO submittals will typically propose FPA section 
205 effective dates that will be beyond the 60-day nominal clock.
    \751\ This proposed time frame refers to applications that are 
consistent with the guidance provided in this Rule and that provide 
all the necessary information. We further note that the Commission's 
review process will restart in the event that applicants modify 
their proposal or supplement the supporting information in their 
application.
---------------------------------------------------------------------------

    What the Commission has approved for ISO forms of governance can be 
used as models for governance of RTOs that are ISOs. Nothing in this 
Rule prohibits the types of independent governance structures we have 
approved to date. All of the ISOs approved to date, except one, have a 
two-tier form of governance wherein a non-stakeholder board at the top 
generally has final decision-making authority on most issues. Below 
this board are advisory groups or committees comprised of stakeholders 
that provide advice and may share some decision-making authority. With 
regard to the second-tier, the Commission has required that no one 
constituency in any group or committee be allowed to dominate the 
recommendation or decision-making process over the objection of the 
other classes, and that no one class holds veto power over the will of 
the remaining classes. The California ISO's governance structure is 
different. It has a single-tier hybrid decision-making board comprised 
of both stakeholders and non-stakeholders. No two classes can push 
through a decision over the objection of other classes, and no one 
class has veto power over the will of the remaining classes.
4. Other Implementation Issues
    Commission Conclusion. An additional issue some commenters raised 
in connection with implementation concerns how the Commission intends 
to handle multiple RTO proposals that pertain to the same or 
overlapping regions. We expect that proper adherence to the 
collaborative process and the RTO scope and configuration factors we 
have identified, in the first instance, will bring order to the 
formation of RTOs such that the Commission will not need to step in and 
decide the matter of competing RTOs at the filing stage.
    Several miscellaneous RTO implementation issues that were raised by 
some commenters concern the terms of withdrawal for members from an 
RTO, the RTO's funding of staff compensation in connection with 
transfers of personnel from other entities, and the Commission serving 
as a backstop for RTO's ADR processes. These matters, however, are best 
left to case-specific determinations in response to particular RTO 
proposals.
    In response to those who argue for or against rejection or waiver 
in connection with less-than-fully-conforming RTO submittals, we 
believe the concepts of rejection and waiver are not appropriate. We 
have provided a significant degree of flexibility in the minimum 
characteristics and functions, and in many instances specifically allow 
for alternative ways to satisfy those characteristics and functions. 
Proposals that do not satisfy the minimum characteristics and functions 
will not be approved as RTOs. That does not mean that such a proposal 
would be summarily rejected; in fact, it may still be an improvement 
over the status quo as long as it is consistent with the FPA 
requirements. However, it may be questioned the extent to which 
entities that are not participating in RTOs have acted to eliminate the 
impediments to competition we have identified in this Final Rule.

IV. Environmental Statement

    This section reviews and adopts the Environmental Assessment (EA) 
prepared by the Commission staff in connection with this Final Rule. It 
identifies the alternatives considered by the agency in reaching its 
decision; analyzes and considers whether and to what extent, if any, 
the chosen alternative--adoption of this Final Rule--affects the 
quality of the human environment; and states the Commission's decision.

Summary

    The analysis compares generation and emission trends under the 
Final Rule to baseline trends without the Final Rule. The analysis 
indicates that the Final Rule will result in little generation change 
on a net national basis, but there may be shifts in regional 
generation. Economic benefits of the Final Rule can be realized with no 
significant, adverse environmental impacts. Further, the potential 
exists for environmental benefits to be realized, through the 
encouragement of newer, cleaner resources.

Discussion

A. Background
    To further the policies and goals of the National Environmental 
Policy Act of 1969 (NEPA), Commission staff prepared an EA in order to 
examine potential impacts that could result from implementing the 
Commission's Rule, and to serve as the basis for considering whether 
the Final Rule will have significant impacts on the quality of the 
human environment. On May 14, 1999, the Commission issued a notice of 
intent to prepare an EA, and a request for comments on the scope of the 
issues that should be addressed in the EA. On July 8, 1999, a public 
scoping meeting was held at the Commission. On October 22, 1999, the 
Commission issued an EA, and invited interested parties to comment on 
the EA. Comments were due on November 22, 1999.
    The Commission received two filed comments on the EA (NMA/WFA/CEED 
and Project Groups on behalf of multiple public interest groups). 
Specific comments are addressed in the relevant sections below.\752\
---------------------------------------------------------------------------

    \752\ As noted in the EA, a number of comments filed during 
scoping relate to matters outside the scope of the EA, and for the 
most part deal with policy issues that are addressed in the Rule.
---------------------------------------------------------------------------

B. Scope of the Analysis
    The EA examines potential environmental impacts that could result 
from implementing the Commission's Final Rule. The impacts are 
necessarily uncertain because they would be the product of changes in 
economic regulation that may alter the future behavior and perhaps the 
future structure of electricity supply markets. In turn, these 
behavioral and structural changes could lead to a different set of 
environmental conditions than would otherwise be the case. The analysis 
recognizes the uncertainty of the Rule's potential effects on future 
markets. It presents a systematic view of possible future market 
changes and assesses a range of possible responses to market changes, 
but should not be seen as predictive of specific market or 
environmental outcomes.
    The EA addresses a broad range of potential economic changes that 
could result from the Rule. These impacts include changes in the mix of 
electric generating plants built in the future, shifts in the 
utilization of existing plants, and increases in interregional 
transmission. The analysis, therefore, includes major air pollutants: 
sulfur dioxide (SO2), nitrogen oxides (NOX), 
mercury, and carbon dioxide associated with various types of generating 
plants and fuels. The EA addresses potential environmental impacts at 
national and regional levels.
    Project Groups expressed concern that the EA does not 
retrospectively analyze the impacts of open access policies to date. As 
stated in 1.3.2 of the EA, we believe it is neither possible nor 
desirable to analyze such changes. Data collection lags, and the short 
period of time that has elapsed since the issuance of Order No. 888, 
would preclude us from drawing meaningful conclusions.
    Project Groups also stated that economic impacts are not 
specifically reported in the EA, making it more difficult to evaluate 
the impacts of the

[[Page 950]]

Rule. We note, however, that the modeling and analysis conducted for 
the EA are the basis for the economic discussion contained in the Final 
Rule. These economic results do not provide a complete analysis of the 
potential economic impacts because the analysis considers only economic 
effects which may relate to operating decisions or new capacity, and 
thus may lead to environmental consequences. However, there are other 
economic benefits from competitive wholesale electric power markets 
which have little or no effect on the environment.
C. Analytic Approach
    Because the impacts that could result from the rulemaking are 
uncertain, an analytic approach known as scenario analysis was used. In 
this approach, alternative views of the future are postulated and 
analyzed with and without the Final Rule. Potential environmental 
impacts are evaluated by comparing the analytic results of the 
scenarios. First, an analytic base case was developed. This base case 
relies on the assumption that the Commission would pursue current 
policy with respect to wholesale electric competition using existing 
rules and procedures, including case-by-case implementation of regional 
market arrangements.
    Having established an appropriate base case, the EA analyzed future 
impacts assuming that the Rule is in effect. Staff adopted the 
assumption that the Final Rule, although voluntary, would result in the 
establishment of RTOs throughout the study area with the 
characteristics and functions set forth in the Final Rule. Three 
scenarios were developed to reflect a range of possible economic and 
environmental outcomes: Transmission Efficiency Scenario; Transmission/
Generation Efficiency Scenario; New Entry Scenario.
D. Alternatives to the Rule
    The primary alternative to the Final Rule is for the Commission to 
maintain the status quo, that is, to continue its existing open access 
policies. The result of this no-action alternative, without 
implementing the Final Rule, is that the Commission would effectuate an 
open transmission grid, but not address changes in the industry that 
have occurred since Order No. 888 was adopted. However, the no-action 
alternative describes what is likely to happen if the Commission takes 
no action over and beyond implementation of existing policies. Once 
this baseline is established to portray what is likely to happen in the 
electric industry during the study period, the projected impacts of the 
Final Rule can then be determined against this backdrop.
    In addition to the Final Rule and the no-action alternative, 
several alternative approaches were considered and ultimately rejected. 
The alternative of analyzing mandatory RTOs, as compared with voluntary 
RTOs as set forth in the Final Rule, was rejected as moot, since the EA 
assumes that voluntary RTO formation proceeds with little delay and is 
successful in creating RTOs with the functions and characteristics 
contained in the Rule. Hence, assumptions for voluntary RTOs and 
mandatory RTOs are analytically indistinguishable in terms of their 
effects on the transmission grid and on the electric sector generally.
    The other major alternative considered was the analysis of 
alternative fuel price assumptions. Project for Sustainable FERC Energy 
Policy suggested that we prepare such an analysis. However, as we noted 
in the EA, this alternative was ultimately rejected for two reasons. 
First, as reflected in scenarios analyzed in the EIS for Order No. 888, 
plausible variation in gas prices relative to coal prices is unlikely 
to have a major impact on the environmental effects of the Final Rule. 
Therefore, a gas price scenario was selected that had the general 
characteristics of other forecasts, namely, that gas prices will rise 
relative to coal prices. The selection of this gas price scenario does 
not represent an endorsement of this particular gas price path. 
Although we believe it to be a reasonable projection, it is a merely a 
representative projection of gas prices for purposes of the EA. Second, 
there is no need to consider an alternative where competition favors 
gas over coal because such a scenario would have little adverse impact, 
especially when compared with scenarios that tend to favor increased 
coal use relative to gas use. In the rule scenario we selected, we 
included, therefore, a number of improvements in coal technology as a 
result of the RTO Rule, to ensure that the potential impacts of any 
increased coal use relative to the base case would be considered in 
assessing the environmental consequences of the rule.
E. Analytic Framework and Assumptions
    It is expected that the impacts of the Final Rule will result 
primarily from changes in the types and locations of power plants and 
transmission facilities constructed in the future and changes in the 
operating patterns of existing power plants, including changes in the 
fuel mix. To examine the impacts thoroughly, the modeling approach 
chosen includes detailed representations of electric power plants and 
the electric transmission grid, and allows for an economic (least-cost) 
compliance with existing and future environmental regulatory 
requirements.
    Computer modeling capable of simulating regional electric utility 
dispatch and capacity expansion over time was used to characterize 
electric power markets in the base case and rule scenarios. We used a 
large supply optimization model of the U.S. electricity supply sector, 
which emphasizes pollution estimation and pollution control. It has 
been used for Environmental Protection Agency (EPA) regulatory analysis 
in publicly accessible proceedings since 1996.
    Analytic assumptions are a critical part of the modeling. Because 
the model cannot tell us directly what the RTO-related changes will be, 
it must assess how a set of assumed changes in the cost and/or physical 
properties or the electricity system could lead to changes in the use 
of the system, and hence to changes in emissions.
    A series of specific assumptions were developed to model the base 
case and scenarios. Assumptions common to all modeled cases include 
current and future prices of fossil fuels, particularly coal and 
natural gas, and current and future requirements imposed on the 
electric sector by environmental laws and regulations. These 
requirements include: for SO2, continuation of the Title IV 
Acid Rain Program, with Phase II coverage and levels of permitted 
emissions; for NOX, Title IV requirements on coal-fired 
boilers (Phase I and Phase II); emissions cap restrictions in the Ozone 
Transport Region starting in 1999, and implementation of the Final Rule 
governing ozone transport issued by the EPA in 1997, modeled in 
accordance with the EPA's guidance. This EPA Rule imposes a cap on 
NOX on large utility boilers in 22 states in the eastern 
United States and limiting summer NOX emissions to 543,800 
tons; no regulatory restrictions are assumed for mercury or 
CO2.
    Project Groups commented that, since assumptions made in the EA 
about future environmental regulations are critical in determining the 
outcome of the analysis, changes in future environmental regulations 
(particularly due to legal challenges) from those assumed in the EA 
could result in different environmental impacts. Accordingly, the 
comment states that the EA should reflect possible changes. We note 
that there are many important analytic assumptions embodied in the

[[Page 951]]

modeling for the EA. Environmental regulations are directly represented 
in the analysis, and changes in these assumed regulations do have a 
large effect on the results of the modeling. In particular, the 
presence or absence of SO2 and NOX caps is a key 
assumption. Nevertheless, these assumptions are based on regulations 
which are final, as opposed to proposed regulations or speculative 
regulatory actions. These rules and associated regulatory analyses from 
EPA were used as the basis for the EA assumptions. Accordingly, it 
would be premature and speculative to consider changes, if any, from 
pending legal challenges or speculative future regulatory changes.
    In a broader sense, it is clear that successful competitive energy 
markets will be complemented by cost-effective environmental 
regulation, because the incentives for efficient behavior on the part 
of market participants can be decentralized and the need for intrusive 
regulatory action is lessened. Emissions trading programs such as those 
for SO2 and NOX are an important example of such 
cost-effective regulation.
    Other invariant assumptions include: net electric demand growth 
(with the exception of New Entry Scenario); load shape (how demand 
varies with season and time of day within each model region); costs and 
performance of new power plants; and capacity and generation of 
nuclear, hydroelectric, pumped storage, and import supply.
    Because of the importance of the transmission system in the Rule, 
assumptions were made about potential changes that may come about 
either because of the Rule's requirements or because of its increased 
incentives for better grid operation and investment. In addition, the 
Final Rule is expected to develop more competitive bulk electric power 
markets. Competition is expected to increase the incentives for 
efficient behavior among market participants. To assess the potential 
effects of such increased efficiencies on the environment, some 
assumptions affecting new and existing power plants were changed. 
Finally, to respond to concerns expressed by parties in the scoping 
process regarding the role of new entrants in developing competitive 
power markets, particularly the RTOs, a model scenario was developed 
that specifically addresses new entry and enhanced consumer choice.
F. Impacts
    The EA analyzes the electric power capacity and generation 
projections on a national and regional level for the base case, and 
presents the corresponding environmental impacts. Projected trends in 
generating capacity, including economic additions, retirements and 
modifications, and generation by plant type for the base case, are 
analyzed for the years 2005, 2010, and 2015. The data indicate that 
virtually all future capacity additions are expected to be gas-fired 
combined cycle or combustion turbine units; coal will nevertheless 
remain the dominant fuel for generation. Growth in natural gas, 
however, will be rapid, with the share of generation increasing from 13 
percent in 1997 to 32 percent in 2015; total generating capacity is 
expected to grow at a slower rate than demand, resulting in plants that 
will generally be operated at higher capacity factors; regional 
patterns of generation reflect regional demand growth as well as 
changes in interregional trade in electricity. In most regions, growth 
in demand is met by gas-fired (or oil/gas switching) plants, although 
in the Midwest existing coal-fired capacity meets part of the growth in 
the early years of the forecast.
    The EA projects national emissions in the base case for 
SO2, NOX, mercury, and CO2. There are 
also regional emissions projections for NOX. The analysis 
indicates the following:
    1. SO2 emissions will decline gradually to 9.5 million 
tons in 2015. Variations in such emissions during the forecast period 
primarily reflect economic use of the Title IV emissions banking 
program, under which emitting parties may elect to over-control 
SO2 in any year and bank the extra reductions as emission 
credits for later use;
    2. Regional SO2 emissions generally will follow the same 
pattern as the national emissions total. However, emissions reductions 
and shifts are not expected to occur uniformly across regions because 
the SO2 emissions trading program allows emitting parties 
with higher costs of pollution control to purchase allowances from 
emitting parties with lower control costs. This can lead to increases 
in emissions from certain regions;
    3. NOX emissions are projected to decline to 4.1 million 
tons in 2015. These reductions are due to the development of 
NOX regulations under the Clean Air Act. Furthermore, summer 
or ``ozone season'' (May to September) NOX emissions are 
projected to decrease to 1.3 million tons in 2015;
    4. Regional NOX emissions are projected to follow a 
pattern similar to the national trend; however, the implementation of 
NOX controls is assumed to take the form of an emission cap 
and permit trading program similar to the Title IV SO2 
program. Consequently, certain regions may experience different 
NOX emissions trends because of the relative costs of 
controlling NOX and the possibility of trading between 
emitting parties;
    5. CO2 is projected to increase throughout the analysis 
period by 27 percent. Because CO2 is an unregulated 
pollutant at the present time, and because both coal and natural gas 
emit CO2, the rise in both coal and gas-fired generation 
leads to a substantial increase in CO2 emissions during the 
analysis period; and
    6. Mercury emissions range between 50.6 and 53.2 tons during the 
forecast period with no clear trend distinguishable. Mercury is also 
uncontrolled at the present time, but emissions are closely linked to 
coal use (with considerable variation of mercury content in coal from 
specific seams). The relative stability of coal-fired generation in 
later years of the analysis period leads to the observed pattern of 
mercury emissions.
    The analysis indicates that the Midwest is expected to produce 
slightly more power, the East Coast to produce slightly less power. 
These changes are likely to be greatest in the near-term, and to 
decline toward baseline levels over time. The Final Rule would result 
in the slight shifting of the baseline fuel mix projections toward coal 
and away from fuel oil and, to some extent, natural gas; these changes 
are small relative to the overall trend in the fuel mix, in which 
natural gas remains the most rapidly growing fuel. This is consistent 
with the change in regional levels of generation.
    The analysis shows that the overall emissions of SOX, 
NOX, mercury, and CO2, are directionally 
consistent with the observed changes in power generation and fuel mix. 
That is, emissions tend to increase early in the forecast period and 
then decline over time, with several instances of emissions reductions. 
The greatest change in any regulated pollutant (a rise of 3.6 percent 
or 381,000 tons of SO2 in one scenario) occurs as a result 
of changing patterns of emissions banking and trading, which is 
consistent with the design of the SO2 cap and trade 
regulatory program. Regional variations in annual and summer 
NOX are also possible and are also consistent with 
regulatory program design. Emissions budgets are met at all times. 
Other emission changes are relatively small because coal-fired plants, 
which contribute a disproportionate share of these emissions, are 
already heavily utilized and so are unable to increase their output 
significantly in the rulemaking scenarios. In one scenario designed to 
examine increased new entry and demand flexibility,

[[Page 952]]

substantial emissions reductions occur as a result of lower demand for 
electricity combined with cleaner new supply options.

V. Regulatory Flexibility Act Certification

    The Commission received no comments on its certification, in the 
NOPR, that the proposed rule would not have a significant economic 
impact on a substantial number of small entities and that an initial 
regulatory flexibility analysis is not required by 5 U.S.C. Sec. 603. 
The Commission adheres to its earlier reasoning and thus concludes that 
a final regulatory flexibility analysis also is not required.\753\ In 
making this determination, the Commission is required to examine only 
the direct compliance costs that a rulemaking imposes upon small 
businesses. It is not required to consider indirect economic 
consequences, nor is it required to consider costs that an entity 
incurs voluntarily.\754\ This rulemaking does not impose significant 
compliance costs upon small entities. Instead, it leaves them with the 
choice of whether to join an RTO. The only costs that are mandated are 
the minimal costs associated with filing a statement, in the event a 
public utility does not make an RTO filing, explaining its efforts to 
join an RTO, any barriers it encountered, and any future plans to join 
an RTO. Thus, this rulemaking will not have a significant economic 
impact upon any small entities.
---------------------------------------------------------------------------

    \753\ See 5 U.S.C. 604.
    \754\ Mid-Tex Elec. Coop. v. FERC, 773 F.2d 327 (D.C. Cir. 1985) 
(Commission need only consider small entities ``that would be 
directly regulated''); Colorado State Banking Bd. v. RTC, 926 F.2d 
931 (10th Cir. 1991) (Regulatory Flexibility Act not implicated 
where regulation simply added an option for affected entities and 
did not impose any costs).
---------------------------------------------------------------------------

VI. Public Reporting Burden and Information Collection Statement

    The OMB regulations require OMB to approve certain reporting and 
recordkeeping (collections of information) imposed by agency rule.\755\ 
The NOPR was submitted to OMB at the time of issuance. OMB did not 
comment nor did it take any action on the proposed rule. FERC 
identifies the information provided under Part 35 as FERC-516 \756\ and 
under Part 33 as FERC-519.\757\
---------------------------------------------------------------------------

    \755\ 5 CFR 1320.11, 44 U.S.C. 3507(d).
    \756\ Electric Rate Schedule Filings.
    \757\ Application for Sale, Lease, or Other Disposition, Merger 
or Consolidation of Facilities or for the Purchase or Acquisition of 
Securities of a Public Utility.
---------------------------------------------------------------------------

    No comments from the public on the burden estimate were received. 
The filing requirements remain essentially the same as those in the 
NOPR so, therefore, the estimated annual filing burden remains the 
same. The burden estimates for complying with this proposed rule are 
set out in Table 1. The total annual hours for collection (reporting + 
recordkeeping (if appropriate)) is 7,600.
    Information Collection Costs: The Commission has projected the 
average annualized cost for all respondents to be: Annualized Costs 
(Operations & Maintenance): $401,518 (7,600 hours  2080 hours 
per year  x  $109,889=$401,518). The cost per respondent is $7,722 
(participants and non-participants).

                                        Table 1.--Estimated Annual Burden
----------------------------------------------------------------------------------------------------------------
                                                     Number of       Number of       Hours Per     Total Annual
                 Data Collection                    Respondents      Responses       Response          Hours
----------------------------------------------------------------------------------------------------------------
FERC-516 \1\....................................              12               1             300           3,600
FERC-516 \2\....................................              40               1              40           1,600
FERC-519 \1\....................................              12               1             200           2,400
                                                 ---------------------------------------------------------------
      Totals....................................  ..............  ..............  ..............           7,600
----------------------------------------------------------------------------------------------------------------
\1\ Filings to propose participation in an RTO under Sec.  35.34(d).
\2\ Alternative filings under Sec.  35.34(g).

    Comments were solicited on the Commission's need for this 
information, whether the information will have practical utility, the 
accuracy of the provided burden estimates, ways to enhance the quality, 
utility, and clarity of the information to be collected, and any 
suggested methods for minimizing respondents' burden, including the use 
of automated information techniques.
    Title: FERC-516, Electric Rate Schedule Filings; FERC-519 
Application for Sale, Lease, or Other Disposition, Merger or 
Consolidation of Facilities or for the Purchase or Acquisition of 
Securities of a Public Utility.

    Action: Proposed Data Collections.
    OMB Control No.: 1902-0096 and 1902-0082.
    The applicant shall not be penalized for failure to respond to this 
collection of information unless the collection of information displays 
a valid OMB control number.
    Respondents: Business or other for profit, including small 
businesses.
    Frequency of Responses: One time.
    Necessity of Information: The Final Rule revises the requirements 
contained in 18 CFR part 35. The Commission is promoting the voluntary 
establishment of RTOs nationwide by December 2001. In particular, the 
Commission will establish in this rule characteristics and functions 
which applicants must meet to become Commission-approved RTOs. The 
Commission will engage in a collaborative process with state officials 
and others to facilitate RTO development. The rule will require 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.
    Internal Review: The Commission has assured itself, by means of 
internal review, that there is specific, objective support for the 
burden estimates associated with the information requirements. The 
Commission's Office of Markets, Tariffs and Rates will use the data 
included in filings under 18 CFR 35.34 to evaluate efforts for the 
interconnection and coordination of the U.S. electric transmission 
system and to ensure the orderly formation of RTOs as well as for 
general industry oversight. These information requirements conform to 
the Commission's plan for efficient information collection, 
communication, and management within the electric power industry.
    The Commission received approximately 334 comments and reply 
comments on its NOPR but none on its reporting burden. The Commission's 
responses to the comments are addressed in the preamble of this Final

[[Page 953]]

Rule. The Commission is submitting a copy of the Final Rule along with 
information collection submissions for the data collections identified 
above to OMB for its review and approval.
    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].

VII. Effective Date and Congressional Notification

    This rule will take effect March 6, 2000. The Commission has 
determined, with the concurrence of the Administrator of the Office of 
Information and Regulatory Affairs of the Office of Management and 
Budget, that this Rule is a ``major rule'' within the meaning of 
section 351 of the Small Business Regulatory Enforcement Act of 
1996.\758\ The Rule will be submitted to both Houses of Congress and 
the Comptroller General prior to its publication in the Federal 
Register.
---------------------------------------------------------------------------

    \758\ 5 U.S.C. 804(2).
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VIII. 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, N.E., Room 2A, Washington, 
D.C. 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 adding a new Subpart F and a new 
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 transmission or 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 
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;

[[Page 954]]

    (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 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. The 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 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), 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,

[[Page 955]]

    (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.
    (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.
    (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

[[Page 956]]

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), 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)-
(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 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,

[[Page 957]]

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 Commenters

Abbreviation--Commenter

    1. Advisory Committee ISO-NE--Advisory Committee to the Board of 
Directors of ISO New England.
    2. AEP--American Electric Power Service Corporation and its 
public utility operating company subsidiaries: Appalachian Power 
Company, Columbus Southern Power Company, Indiana Michigan Power 
Company, Kentucky Power Company, Kingsport Power Company, Ohio Power 
Company. and Wheeling Power Company.
    3. AEPCO--Arizona Electric Power Cooperative, Inc.
    4. Alabama Commission--Alabama Public Service Commission.
    5. Alberta--Provence of Alberta, Electricity Branch.
    6. Allegheny--Allegheny Energy, Inc.
    7. Alliance Companies--American Electric Power Service 
Corporation, Consumers Energy Company, Detroit Edison Company, 
FirstEnergy Corp. and Virginia Electric and Power Company.
    8. Alliant Energy--Alliant Energy Corporation.
    9. Aluminum Companies--Alcoa Inc., Columbia Falls Aluminum 
Company, Kaiser Aluminum & Chemical Corporation and Vanalco, Inc.
    10. American Forest--American Forest & Paper Association.
    11. AMP-Ohio--American Municipal Power-Ohio, Inc.
    12. APPA--American Public Power Association.
    13. APPA et al. (WP)--Legal White Paper prepared on behalf of 
and sponsored jointly by the American Public Power Association, the 
Electric Consumers Resource Council, the Transmission Access Policy 
Study Group and the Transmission Dependent Utility Systems.
    14. APS--Arizona Public Service Company.
    15. APX--Automated Power Exchange, Inc.
    16. Arizona Authority--Arizona Power Authority.
    17. Arizona Commission--Arizona Corporation Commission.
    18. Arizona ISA--Arizona Independent Scheduling Administrator 
Association.
    19. Arkansas Cities--Cities of Benton, Bentonville, North Little 
Rock, Osceola, Piggott, Prescott and Siloam Springs, Arkansas; the 
Clarksville Light and Water Company; Conway Corporation; Hope Water 
and Light Commission; City Water and Light Plant of the City of 
Jonesboro, Arkansas; Paragould Light and Water Commission; and the 
West Memphis, Arkansas Utilities Commission.
    20. Arkansas Consumers--Arkansas Electric Energy Consumers.
    21. Avista--Avista Corporation, Inc.
    22. Bangor Hydro--Bangor Hydro-Electric Company.
    23. BC Hydro--British Columbia Hydro & Power Authority.
    24. Big Rivers--Big Rivers Electric Corporation.
    25. Blue Ridge--Blue Ridge Power Agency.
    26. Brattle Group--The Brattle Group (Peter Fox-Penner and 
Philip Hanser).
    27. British Columbia Ministry--British Columbia, Canada, 
Ministry of Employment and Investment, Electricity Development 
Branch.
    28. Cal DWR--California Department of Water Resources.
    29. Cal ISO--California Independent System Operator Corporation.
    30. California Board--California Electricity Oversight Board.
    31. California Commission--Public Utilities Commission of the 
State of California.
    32. CalPX--California Power Exchange Corporation.
    33. CAMU--Colorado Association of Municipal Utilities.
    34. Canada DNR--Canada Department of Natural Resources.
    35. CCEM/ELCON--Coalition for a Competitive Electricity Market 
and the Electricity Consumers Resources Council.
    36. CEA--Canadian Electricity Association.
    37. Consumers Energy--Consumers Energy Company.
    38. Central Maine--Central Maine Power Company and Maine 
Electric Power Company.
    39. Champion--Champion International Corporation.
    40. Chelan--Public Utility District No. 1 of Chelan County.
    41. Cinergy--Cinergy Services, Inc.
    42. Clarksdale--Clarksdale Public Utilities Commission.
    43. Cleco--Cleco Corporation.
    44. Cleveland--City of Cleveland, Ohio.
    45. CMUA--California Municipal Utilities Association.
    46. Coalition of Alliance Users--Coalition of Municipal and 
Cooperative Users of Alliance Companies' Transmission.
    47. ComEd--Commonwealth Edison Company.
    48. Conectiv--Conectiv (Atlantic City Electric Company and 
Delmarva Power & Light Company.
    49. Conlon--Mr. P. Gregory Conlon.
    50. Consumer Groups--Industrial Consumers, American Public Power 
Association, National Rural Electric Cooperative Association, 
Transmission Access Policy Study Group, Transmission Dependent 
Utility Systems, Consumer Federation of America and International 
Mass Retail Association.
    51. CP&L--Carolina Power & Light Company.
    52. CRC--Colorado River Commission of the State of Nevada.
    53. CREDA--Colorado River Energy Distributors Association.
    54. CSU--Colorado Springs Utilities.
    55. CTA--Competitive Transmission Association, Inc.
    56. Dalton Utilities--Board of Water, Light and Sinking Fund 
Commissioners of the City of Dalton, Georgia.
    57. Dairyland--Dairyland Power Cooperative.
    58. Desert STAR--Desert STAR.
    59. Detroit Edison--Detroit Edison Company.
    60. Distributed Power--Distributed Power Coalition of America.
    61. DOE--United States Department of Energy.
    62. Dr. Illic--Dr. Marija Illic and Yong Yoon.
    63. Duke--Duke Energy Corporation.
    64. Duquesne--Duquesne Light Company.
    65. Dynegy--Dynegy Inc.
    66. EAL--ESBI Alberta Ltd.
    67. East Kentucky--East Kentucky Power Cooperative, Inc.
    68. 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.
    69. ECAR--East Central Area Reliability Council.
    70. EEI--Edison Electric Institute.
    71. EME--Edison Mission Energy.
    72. Empire District--Empire District Electric Company.
    73. Enron/APX/Coral Power--Enron Power Marketing, Inc., 
Automated Power Exchange and Coral Power, L.L.C.
    74. Entergy--Entergy Services Inc.
    75. EPA--United States Environmental Protection Agency.
    76. EPRI--Electric Power Research Institute.
    77. EPSA--Electric Power Supply Association.
    78. Eric Hirst--Mr. Eric Hirst.
    79. Fertilizer Institute--The Fertilizer Institute.
    80. First Rochdale--1st Rochdale Cooperative Group, Ltd.
    81. FirstEnergy--FirstEnergy Corp.
    82. Florida Commission--Florida Public Service Commission.
    83. Florida Power Corp.--Florida Power Corporation.
    84. FMPA--Florida Municipal Power Agency.
    85. FP&L--Florida Power & Light Company.
    86. FTC--Staff of the Bureau of Economics of the Federal Trade 
Commission.
    87. Gainesville--Gainesville Regional Utilities.
    88. Georgia Transmission--Georgia Transmission Corporation.
    89. GPU Energy--GPU Energy.
    90. Grand Council et al.--Grand Council of the Crees, Greenpeace 
Canada, the Sierra Club of Canada, Mouvement Au Courant, the Centre 
D'Analyses de Politiques Energetiques and New England Coalition for 
Energy Efficiency and the Environment.
    91. Great River--Great River Energy.
    92. H.Q. Energy Services--Energy Services Group of Hydro-Quebec 
and H.Q. Energy Services (U.S.) Inc.
    93. How Group--OASIS How Working Group.
    94. ICUA--Idaho Consumer-Owned Utilities Association.

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    95. Idaho Commission--Idaho Public Utilities Commission.
    96. Idaho Power--Idaho Power Company.
    97. Illinois Commission--Illinois Commerce Commission.
    98. IMEA--Illinois Municipal Electric Agency.
    99. IMPA--Indiana Municipal Power Agency.
    100. Indiana Commission--Indiana Utility Regulatory Commission.
    101. Indianapolis P&L--Indianapolis Power & Light Company.
    102. Industrial Consumers--Electricity Consumers Resource 
Council, the American Iron & Steel Institute and the Chemical 
Manufactures Association.
    103. Industrial Customers--Industrial Customers of Northwest 
Utilities.
    104. INGAA--Interstate Natural Gas Association of America.
    105. Iowa Board--Iowa Utilities Board.
    106. IPCF--International Powerline Communications Forum.
    107. ISO-NE--ISO New England Inc.
    108. JEA--JEA.
    109. Justice Department--United States Department of Justice.
    110. Kentucky Commission--Kentucky Public Service Commission.
    111. Konolige/Ford/Fleishman--Kit Konolige, Daniel F. Ford and 
Steven I. Fleishman.
    112. Lenard--Mr. Thomas M. Lenard.
    113. LEPA--Louisiana Energy & Power Authority.
    114. LG&E--LG&E Energy Corp.
    115. Lincoln--Lincoln, Nebraska Electric System.
    116. LIPA--Long Island Power Authority.
    117. Los Angeles--Los Angeles Department of Water and Power.
    118. Loveland Customers--Loveland Area Customers Association.
    119. LPPC--Large Public Power Council.
    120. Manitoba Board--Manitoba Hydro-Electric Board.
    121. MAPP--Mid-Continent Area Power Pool.
    122. Mass Companies--Boston Edison Company, Cambridge Electric 
Light Company and Commonwealth Electric Company.
    123. Massachusetts Division--Massachusetts Division of Energy 
Resources.
    124. MEAG--Municipal Electric Authority of Georgia.
    125. Merrill Energy--Merrill Energy LLC.
    126. Metropolitan--Metropolitan Water District of Southern 
California.
    127. Michigan Commission--Michigan Public Service Commission.
    128. MidAmerican--MidAmerican Energy Company.
    129. Mid-Atlantic Commissions--Delaware Public Service 
Commission, District of Columbia Public Service Commission, Maryland 
Public Service Commission, New Jersey Board of Public Utilities and 
Pennsylvania Public Utility Commission.
    130. Midwest Energy--Midwest Energy, Inc.
    131. Midwest ISO--Midwest Independent Transmission System 
Operator, Inc.
    132. Midwest ISO Participants--Allegheny Energy, 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, Southern Indiana Gas & Electric Company, Southern Illinois 
Power Cooperative, Wabash Valley Power Association, Inc. and 
Wisconsin Electric Power Company.
    133. Midwest Municipals--Missouri River Energy Services, Iowa 
Association of Municipal Utilities and Minnesota Municipal Utilities 
Association.
    134. Minnesota Commission--Minnesota Public Utilities 
Commission.
    135. Minnesota Power--Minnesota Power.
    136. Missouri Commission--Missouri Public Service Commission.
    137. MLGW--Memphis Light, Gas and Water Division.
    138. Montana Commission--Montana Public Service Commission and 
Montana Department of Environmental Quality.
    139. Montana Power--Montana Power Company.
    140. Montana-Dakota--Montana-Dakota Utilities Co.
    141. NARUC--National Association of Regulatory Utility 
Commissioners.
    142. NASUCA--National Association of State Utility Consumer 
Advocates.
    143. NCPA--Northern California Power Agency.
    144. NEMA--National Energy Marketers Association.
    145. NECPUC--New England Conference of Public Utilities 
Commissioners, Inc.
    146. NEPCO et al.--New England Power Company, National Grid 
Group, plc and Montaup Electric Company.
    147. NERA--National Economic Research Associates, Inc.
    148. NERC--North American Electric Reliability Council.
    149. Nevada Commission--Public Utilities Commission of Nevada
    150. New Century--New Century Energies, Inc. and its operating 
utility companies: Public Service Company of Colorado, Southwestern 
Public Service Company and Cheyenne Light, Fuel and Power Company.
    151. New Orleans--Council of the City of New Orleans.
    152. New Smyrna Beach--Utilities Commission, City of New Smyrna 
Beach, Florida.
    153. New York Commission--New York State Public Service 
Commission
    154. Nine Commissions--Pennsylvania Public Utility Commission, 
Virginia State Corporation Commission, Public Utilities Commission 
of Ohio, Indiana Utility Regulatory Commission, Illinois Commerce 
Commission, Michigan Public Service Commission, Missouri Public 
Service Commission, Arkansas Public Service Commission and Oklahoma 
Corporation Commission.
    155. NiSource--NiSource Incorporated.
    156. NJBUS--New Jersey Business Users.
    157. NMA/WFA/CEED--National Mining Association, Western Fuels 
Association, Inc. and Center for Energy and Economic Development.
    158. NU--Northeast Utilities System.
    159. Northwest Council--Northwest Power Planning Council.
    160. NPCC--Northeast Power Coordinating Council.
    161. NPPD--Nebraska Public Power District.
    162. NPRB--Nebraska Power Review Board.
    163. NRECA--National Rural Electric Cooperative Association.
    164. NSP--Northern States Power Company.
    165. NU--Northeast Utilities System.
    166. NWCC--National Wind Coordinating Committee.
    167. NY ISO--New York Independent System Operator, Inc.
    168. NYC--City of New York.
    169. NYEBF--New York Energy Buyers Forum.
    170. NYMEX--New York Mercantile Exchange.
    171. NYPP--Member Systems of the New York Power Pool (Central 
Hudson Gas & Electric Corporation, Consolidated Edison Company of 
New York, Inc., Long Island Power Authority, New York State Electric 
& Gas Corporation, Niagara Mohawk Power Corporation, Orange and 
Rockland Utilities, Inc., Rochester Gas and Electric Corp. and Power 
Authority of the State of New York).
    172. Oglethorpe--Oglethorpe Power Corporation.
    173. Ohio Commission--Public Utilities Commission of Ohio.
    174. Oneok--Oneok Power Marketing.
    175. Ontario IMO--Ontario Independent Electricity Market 
Operator.
    176. Ontario Power--Ontario Power Generation Inc.
    177. Oregon Office--Oregon Office of Energy.
    178. Otter Tail--Otter Tail Power Company.
    179. PacifiCorp--PacifiCorp.
    180. PECO--PECO Energy Company and Horizon Energy.
    181. Pennsylvania Commission--Pennsylvania Public Utility 
Commission.
    182. PG&E--PG&E Corporation.
    183. PGE--Portland General Electric Company.
    184. PGP--Public Generating Pool.
    185. PJM--PJM Interconnection, L.L.C.
    186. PJM/NEPOOL Customers--PJM Industrial Customer Coalition, 
NEPOOL Industrial Customer Coalition and Coalition of Midwest 
Transmission Customers.
    187. Platte River--Platte River Power Authority.
    188. PNGC--Pacific Northwest Generating Cooperative.
    189. Powerex--British Columbia Power Exchange Corporation.
    190. PP&L Companies--PP&L Inc., PP&L EnergyPlus Co., L.L.C., 
PP&L Montana, L.L.C.
    191. PPC--Public Power Council.
    192. Professor Hogan--Professor William W. Hogan.
    193. Professor Joskow--Professor Paul L. Joskow.
    194. Professor Koch--Professor Charles H. Koch, Jr.
    195. Project Groups--Alliance for Affordable Energy, American 
Wind Energy Association, Center for Clean Air Policy, Center for 
Energy Efficiency and Renewable Technologies, Citizen Power, Inc., 
Citizens

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for Pennsylvania's Future, Delaware Division of the Public Advocate, 
Environmental Law & Policy Center of the Midwest, Land & Water Fund 
of the Rockies, Legal Environmental Assistance Foundation, 
Minnesotans for an Energy-Efficient Economy, Natural Resources 
Defense Council, Northwest Energy Coalition, Office of the People's 
Counsel of the District of Columbia, Pace Energy Project, 
Pennsylvania Energy Project, Public Citizen, PJM Public Interest/
Environmental User Group, Renew Wisconsin, Southern Environmental 
Law Center, Tennessee Valley Energy Reform Coalition, Union of 
Concerned Scientists, Wisconsin's Environmental Decade.
    196. PSE&G--Public Service Electric and Gas Company.
    197. PSNM--Public Service Company of New Mexico.
    198. Public Citizen--Public Citizen.
    199. Puget--Puget Sound Energy, Inc.
    200. Rayburn--Rayburn Country Electric Cooperative, Inc.
    201. RECA--Residential Electric Consumers Association.
    202. Reliant--Reliant Energy, Incorporated.
    203. RUS--Rural Utilities Service of the Department of 
Agriculture.
    204. Salomon Smith Barney--Global Power Group of Salomon Smith 
Barney.
    205. San Francisco--City and County of San Francisco.
    206. SCE&G--South Carolina Electric & Gas Company.
    207. Seattle--Seattle City Light Department.
    208. SERC--Southeastern Electric Reliability Council.
    209. Sierra Pacific--Sierra Pacific Resources, Inc.
    210. Sithe--Sithe Energies, Inc.
    211. SMUD--Sacramento Municipal Utility District.
    212. Snohomish--Public Utility District No. 1 of Snohomish 
County, Washington.
    213. SNWA--Southern Nevada Water Authority.
    214. SoCal Cities--Cities of Anaheim, Azusa, Banning, Colton, 
and Riverside, California.
    215. SoCal Edison--Southern California Edison Company.
    216. Sonat--Sonat Power Marketing, L.P.
    217. South Carolina Authority--South Carolina Public Service 
Authority.
    218. South Carolina Commission--Public Service Commission of 
South Carolina.
    219. 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.
    220. SPP--Southwest Power Pool, Inc.
    221. SPRA--Southwestern Power Resources Association.
    222. SRP--Salt River Project Agricultural Improvement and Power 
District.
    223. St. Joseph--St. Joseph Light & Power Company.
    224. Statoil--Statoil Energy, Inc.
    225. STDUG--Southwest Transmission Dependent Utility Group.
    226. Steel Dynamics--Steel Dynamics, Inc.
    227. Tacoma Power--City of Tacoma, Department of Public 
Utilities, Light Division.
    228. Tallahassee--City of Tallahassee, Florida.
    229. Tampa Electric--Tampa Electric Company.
    230. TANC--Transmission Agency of Northern California.
    231. TAPS--Transmission Access Policy Study Group.
    232. 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.
    233. Tennessee Authority--Tennessee Regulatory Authority.
    234. TEP--Tucson Electric Power Company.
    235. Texas Commission--Public Utility Commission of Texas.
    236. Trans-Elect--Trans-Elect, Inc.
    237. Transenergie--Transenergie.
    238. Transmission ISO Participants--Baltimore Gas & Electric, 
Boston Edison Company, Cambridge Electric Light Company, 
Commonwealth Energy Company, Conectiv, GPU Energy, Niagara Mohawk 
Power Company, Northeast Utilities Service Company, PECO Energy 
Company, PP&L, Inc., Potomac Electric Power Company, Public Service 
Electric and Gas Company, Vermont Electric Power Company, Inc.
    239. Tri-State--Tri-State Generation and Transmission 
Association, Inc.
    240. Turlock--Turlock Irrigation District.
    241. TVA--Tennessee Valley Authority.
    242. TXU Electric--TXU Electric Company.
    243. UAMPS--Utah Associated Municipal Power Systems.
    244. UMPA--Utah Municipal Power Agency.
    245. United Illuminating--United Illuminating Company.
    246. UtiliCorp--UtiliCorp United, Inc.
    247. Utility Engineers--Utility Economic Engineers.
    248. Vernon--City of Vernon, California.
    249. Virginia Commission--Virginia State Corporation Commission.
    250. Virginia Power--Virginia Electric and Power Company.
    251. Washington Commission--Washington Utilities and 
Transportation Commission.
    252. WEPCO--Wisconsin Electric Power Company.
    253. WICF--Western Interconnection Coordination Forum.
    254. Williams--Williams Companies, Inc.
    255. Wisconsin Commission--Public Service Commission of 
Wisconsin.
    256. Wolverine Cooperative--Wolverine Power Supply. Cooperative, 
Inc.
    257. WPPI--Wisconsin Public Power, Inc.
    258. WPSC--Wisconsin Public Service Corporation.
    259. Wyoming Commission--Wyoming Public Service Commission.

[FR Doc. 00-2 Filed 1-5-00; 8:45 am]
BILLING CODE 6717-01-P