[Federal Register Volume 64, Number 111 (Thursday, June 10, 1999)]
[Proposed Rules]
[Pages 31390-31444]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 99-12553]



[[Page 31389]]

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Part III





Department of Energy





_______________________________________________________________________



Federal Energy Regulatory Commission



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18 CFR Part 35



Regional Transmission Organizations; Proposed Rule

Regional Transmission Organizations; Intent To Prepare and 
Environmental Assessment for the Regional Transmission Organizations 
Rulemaking, Request for Comments on Environmental Issues, and Public 
Scoping Meeting; Notice

  Federal Register / Vol. 64, No. 111 / Thursday, June 10, 1999 / 
Proposed Rules  

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM99-2-000]


Regional Transmission Organizations; Notice of Proposed 
Rulemaking

May 13, 1999.
AGENCY: Federal Energy Regulatory Commission.

ACTION: Notice of proposed rulemaking.

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SUMMARY: The Federal Energy Regulatory Commission (Commission) is 
proposing to amend its regulations under the Federal Power Act (FPA) to 
facilitate the formation of Regional Transmission Organizations (RTOs). 
The Commission proposes to 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 proposes 
minimum characteristics and functions that a transmission entity must 
satisfy in order to be considered to be an RTO.

DATES: Initial comments are due August 16, 1999. Reply comments are due 
September 15, 1999.

ADDRESSES: Send comments to: Office of the Secretary, Federal Energy 
Regulatory Commission, 888 First Street, NE., Washington, D.C. 20426.

FOR FURTHER INFORMATION CONTACT:
Alan Haymes (Technical Information), Office of Electric Power 
Regulation, Federal Energy Regulatory Commission, 888 First Street, 
NE., Washington, D.C. 20426, (202) 219-2919.
Wilbur C. Earley (Technical Information), Office of Economic Policy, 
Federal Energy Regulatory Commission, 888 First Street, NE., 
Washington, D.C. 20426, (202) 208-0100
Brian R. Gish (Legal Information), Office of the General Counsel, 
Federal Energy Regulatory Commission, 888 First Street, NE., 
Washington, D.C. 20426, (202) 208-0996

SUPPLEMENTARY INFORMATION: In addition to publishing the full text of 
this document in the Federal Register, the Commission also provides all 
interested persons an opportunity to inspect or copy the contents of 
this document during normal business hours in the Public Reference Room 
at 888 First Street, N.E., Room 2A, Washington, D.C. 20426.
    The Commission Issuance Posting System (CIPS) provides access to 
the texts of formal documents issued by the Commission from November 
14, 1994, to the present. CIPS can be accessed via Internet through 
FERC's Home page (http://www.ferc.fed.us) using the CIPS Link or the 
Energy Information Online icon. Documents will be available on CIPS in 
ASCII and WordPerfect 6.1. User assistance is available at 202-208-2474 
or by E-mail to [email protected].
    This document is also available through the Commission's Records 
and Information Management System (RIMS), an electronic storage and 
retrieval system 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. RIMS is available in the Public Reference 
Room or remotely via Internet through FERC's Home page using the RIMS 
link or the Energy Information Online icon. User assistance is 
available at 202-208-2222, or by E-mail to [email protected].
    Finally, the complete text on diskette in WordPerfect format may be 
purchased from the Commission's copy contractor, RVJ International, 
Inc. RVJ International, Inc. is located in the Public Reference Room at 
888 First Street, N.E., Washington, D.C. 20426.

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 Inquiries; Conferences with 
Stakeholders and State Regulators
    C. Statutory Framework
III. Discussion
    A. Barriers to Assuring an Abundant Supply of Electric Energy 
throughout the U.S. with the Greatest Possible Economy
    1. Engineering and Economic Inefficiencies in the Operation, 
Planning, and Expansion of Regional Transmission Grids
    2. Actual and Perceived Discriminatory Conduct by Transmission 
Owners to Favor Their Own or Affiliated Merchant Operations
    B. Benefits That RTOs Can Offer
    1. An RTO Would Improve Efficiencies in the Management of the 
Transmission Grid
    2. An RTO Would Improve Grid Reliability
    3. An RTO Would Remove Opportunities for Discriminatory 
Transmission Practices
    4. An RTO Would Result in Improved Market Performance
    5. An RTO Would Facilitate Lighter-Handed Governmental 
Regulation
    6. Conclusion
    C. Concerns Expressed by the State Commissions
    1. Federal Mandate
    2. Regional Flexibility
    3. Retail Markets
    4. Effect on States With Low Cost Generation
    5. Need for Independent Transmission Operation
    6. Transmission Cost Shifting
    7. Boundary Drawing
    8. Regional Approach to Reliability
    9. Pricing Reform
    10. Participation of Public Power
    11. State Role in RTO Governance
    12. Existing Regional Transmission Entities
    D. Minimum Characteristics and Functions for a Regional 
Transmission Organization
    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 TTC and ATC
    6. Market Monitoring
    7. Planning and Expansion
    E. Open Architecture
    F. Ratemaking for Transmission Facilities under RTO Control
    1. Single Transmission Access Rate for Capital Cost Recovery
    2. Congestion Pricing
    3. Performance Based Rate Regulation
    4. Consideration of Incentive Pricing Proposals
    G. Public Power Participation in RTOs
    H. Other Issues
    1. Pre-existing Transmission Contracts
    2. Treatment of Existing Regional Transmission Entities
    3. Participation by Canadian and Mexican Entities
    4. Providing Service to Transmission-owning Utilities That Do 
Not Participate in an RTO
    5. RTO Filing Requirements
    6. Power Exchanges (PXs)
    I. Implementation of the Rule
    1. Collaborative Process
    2. Filing Requirements
IV. Environmental Statement
V. Regulatory Flexibility Act
VI. Public Reporting Burden and Information Collection Statement
VII. Public Comment Procedures
Text of the Regulations
Appendix A: Staff Summary of the FERC-Industry ISO Conferences
Appendix B: Staff Summary of FERC Consultations With the States
Appendix C: Existing Configurations

I. Introduction and Summary

    In 1996 the Commission put in place the foundation necessary for

[[Page 31391]]

competitive wholesale power markets in this country--open access 
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, 61 FR 21540 (1996), FERC Stats. & Regs. para. 31,036 
(1996) (Order No. 888), order on reh'g, Order No. 888-A, 62 FR 12274 
(1997), FERC Stats. & Regs. para. 31,048 (1997), order on reh'g, 
Order No. 888-B, 62 FR 64688, 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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    As a result, the traditional means of grid management is showing 
signs of strain and may be inadequate to support the efficient and 
reliable operation that is needed for the continued development of 
competitive electricity markets. In addition, there are indications 
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, more reliance on market 
solutions, and lighter-handed regulation that competitive markets can 
bring.
    If electricity consumers are to realize the full benefits that 
competition can bring to wholesale markets, the Commission must address 
the extent of these problems and appropriate ways of mitigating them. 
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. We believe that further 
steps may need to be taken to address grid management if we are to 
achieve fully competitive power markets. We further believe that 
regional approaches to the numerous issues affecting the industry may 
be the best means to eliminate remaining impediments to properly 
functioning competitive markets.
    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 regional 
transmission institutions in a timely manner. We seek to accomplish our 
objective by encouraging voluntary participation. We are therefore 
proposing in this rulemaking minimum characteristics and functions for 
appropriate regional transmission institutions; a collaborative process 
by which public utilities and non-public utilities that own, operate or 
control interstate transmission facilities, in consultation with the 
state officials as appropriate, will consider and develop regional 
transmission institutions; a willingness to consider incentive pricing 
on a case-specific basis and an offer of non-monetary regulatory 
benefits, such as deference in dispute resolution, reduced or 
eliminated codes of conduct, and streamlined filing and approval 
procedures; and a time line for public utilities to make appropriate 
filings with the Commission and initiate operation of regional 
transmission institutions. As a result, we expect jurisdictional 
utilities to form Regional Transmission Organizations (RTOs).
    As discussed in detail herein, regional institutions can address 
the operational and reliability issues now confronting the industry, 
and 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 2; (2) improve grid reliability; (3) remove the 
remaining opportunities for discriminatory transmission practices; (4) 
improve market performance; and (5) facilitate lighter handed 
regulation.
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    \2\ 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 regional transmission 
institutions 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. There are likely to be substantial 
cost savings brought about by regional transmission institutions.
    In light of important questions regarding the complexity of grid 
regionalization raised by state regulators and applicants in individual 
cases, we are proposing a flexible approach. We are not proposing to 
mandate that utilities participate in a regional transmission 
institution by a date certain. Instead, we act now to ensure that they 
consider doing so in good faith. Moreover, 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.
    Rather, the Commission is proposing to establish fundamental 
characteristics and functions for appropriate regional transmission 
institutions. We will designate institutions that satisfy all of the 
minimum characteristics and functions as Regional Transmission 
Organizations (RTOs). Hereinafter, the term Regional Transmission 
Organization, or RTO, will refer to an organization that satisfies all 
of the minimum characteristics and functions.
    Pursuant to our authority under section 205 of the 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 U.S. with 
the greatest possible economy, we propose the following.3
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    \3\ The Commission's legal authority is discussed in Section II.
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    First, the Commission proposes minimum characteristics and 
functions that an RTO must satisfy. Industry participants, however, 
retain flexibility in structuring RTOs that satisfy these 
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.
    Second, we propose to adopt an ``open architecture'' policy 
regarding RTOs, whereby all RTO proposals must

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allow the RTO and its members the flexibility to improve their 
organizations in the future in terms of structure, operations, market 
support and geographic scope to meet market needs. In turn, the 
Commission will provide the regulatory flexibility to accommodate such 
improvement.
    Third, we propose 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 adopted in the Final Rule,4 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. Each proposed RTO must plan to be operational by 
December 15, 2001. 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.
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    \4\ An RTO proposal includes a basic agreement filed under 
section 205 of the FPA setting out the rules, practices and 
procedures under which an 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, 205, or 206, 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 proposed rule, a utility may file a petition for a declaratory 
order asking whether a proposed transmission entity would qualify as 
an RTO, to be followed by appropriate filings under sections 203, 
205 and/or 206.
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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 explains the extent to which the 
transmission entity in which it participates meets the minimum 
characteristics and functions for an RTO, or proposes to modify the 
existing institution to become an RTO. Alternatively, the public 
utility must file an explanation of efforts, obstacles and plans with 
respect to conforming to these characteristics and functions.
    Through the required filings, utilities will make known to the 
public any plans for RTO participation so that other utilities and the 
competitive market can respond accordingly. This proposal relies 
primarily on the enlightened self-interest of stakeholders in each 
region. Such public disclosure of plans for transmission facilities 
will benefit the industry, the financial community, and public policy 
makers as the electric industry restructuring continues.
    To facilitate RTO formation in all regions of the Nation, the 
Commission proposes to sponsor and support a collaborative process 
under section 202(a) 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 
specific RTOs.
    Prior to undertaking this proposed rulemaking, we held eight 
technical conferences in 1998 with all industry stakeholders as well as 
three technical conferences this year with state regulatory commissions 
to obtain their views on the need for, and benefits of, regional 
organizations. We gained valuable insight from the participants, 
including many state commissions that have undertaken or are 
considering state retail choice programs for the consumers in their 
states. In light of the comments received, we wish to respond to 
several concerns that were raised.
    First, we are not proposing to mandate RTOs, nor are we proposing 
detailed specifications on a particular organizational form for RTOs. 
The goal of this rulemaking is to get RTOs in place through voluntary 
participation. While this Commission has specific authorities and 
responsibilities under the FPA to protect against undue discrimination 
and remove impediments to wholesale competition, we believe it is 
preferable to meet these responsibilities in the first instance through 
an open and collaborative process that allows for regional flexibility 
and induces voluntary behavior.
    Second, the development of RTOs is not intended to interfere with 
state prerogatives in setting retail competition policy. The Commission 
believes that RTOs can successfully accommodate the transmission 
systems of all states, whether or not a particular state has adopted 
retail competition. However, for those states that have chosen to adopt 
retail wheeling, RTOs can play a critical role in the realization of 
full competition at the retail level as well as at the wholesale level. 
In addition, the Commission believes that RTOs will not interfere with 
a state's prerogative to keep the benefits of low-cost power for the 
state's own retail consumers.
    Third, we propose to allow RTOs to prevent transmission cost 
shifting by continuing our policy of flexibility with respect to 
recovery of sunk transmission costs, such as the ``license plate'' 
approach.
    Fourth, the existence of RTOs has not, and will not in the future, 
interfere with traditional state and local regulatory responsibilities 
such as transmission siting, local reliability matters, and regulation 
of retail sales of generation and local distribution. In fact, RTOs 
offer the potential to assist the states in their regulation of retail 
markets and in resolving matters among states on a regional basis. They 
also provide a vehicle for amicably resolving state and Federal 
jurisdictional issues.
    Finally, we do not propose to establish regional boundaries in this 
rulemaking. Our foremost concern is that a proposed RTO's regional 
configuration is sufficient to ensure that the required RTO 
characteristics and functions are satisfied. To this end, the 
Commission proposes guidance regarding the scope and regional 
configuration of RTOs.
    We now turn to the state of the electric utility industry in the 
wake of Order No. 888 and how the development of RTOs achieves 
efficient, reliable and competitive power markets.

II. Background

    In April 1996, in Order Nos. 888 and 889, 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, they 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 have become apparent in the three years 
since the issuance of our orders.

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

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practices existed in the electric industry, and that transmission-
owning utilities had discriminated against others seeking transmission 
access.5 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.6
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    \5\ Order No. 888, FERC Stats & Regs. at 31,682.
    \6\ 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: (a) take transmission services under the same tariff of 
general applicability as do others; (b) state separate rates for 
wholesale generation, transmission, and ancillary services; and (c) 
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.7 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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    \7\ 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 ISOs had the 
potential to provide significant benefits, efforts to remedy undue 
discrimination should begin by requiring the less intrusive functional 
unbundling approach. Order No. 888 set forth eleven principles for 
assessing ISO proposals submitted to the Commission. 8 Order 
No. 888 also stated:

    \8\ Id. at 31,730.
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    [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. 9
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    \9\ Id. at 31,655.
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    In section III.A.2 of this Notice of Proposed Rulemaking, we 
discuss our experiences to date with functional unbundling. 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.

B. Developments Since Order Nos. 888 and 889

    In the three 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 in 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 
third-party use 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 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, New England, where there was deep concern about 
adequacy of generation supply only three years ago, now has 
approximately 30,000 MW of generation proposed. That response comes 
almost entirely from independent generating plants that 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 put new stresses on regional 
transmission systems--stresses that call for regional solutions.
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 independent power marketers and generators; increases in 
the volume of trade in the industry, particularly as marketers make 
multiple sales; state efforts to create retail competition; and new and 
different uses of the transmission grid.
    With respect to divestiture, since August 1997, 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 10 percent of U.S. generating 
capacity. In all, according to publicly available data, 27 utilities 
have sold all or some of their generating assets and 7 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, there have been more than 20 
applications filed with us to approve proposed mergers involving public 
utilities. Most of these mergers have been approved by various 
regulatory authorities, including the Commission, although a few have 
been rejected or withdrawn, and several mergers are pending regulatory 
approval. Most of these merger proposals have been between electric 
utilities with contiguous service areas, while some of the proposed 
mergers have been between utilities with non-

[[Page 31394]]

contiguous service areas. The Commission has also been presented with 
merger applications involving the combination of electric and natural 
gas assets.
    There has been significant growth in the volume of trading in the 
wholesale electricity market. In the first quarter of 1995, according 
to power marketer quarterly filings, marketer sales totaled 1.8 million 
MWh, but by the second quarter of 1998, such sales escalated to 513 
million MWh.10 Many new competitors have entered the 
industry. For example, in the first quarter of 1995, there were eight 
power marketers (either independent or affiliated with traditional 
utilities) actively trading in wholesale power markets, but by the 
second quarter of 1998, there were 108 actively trading power 
marketers. The Commission has granted market-based rate authority to 
well over 500 wholesale power marketers, of which some are independent 
of traditional investor-owned utilities, some are affiliated with 
traditional utilities, and some are traditional utilities 
themselves.11
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    \10\ Power marketer quarterly filings, cited in Staff Report to 
the Federal Energy Regulatory Commission on the Causes of Wholesale 
Electric Pricing Abnormalities in the Midwest During June 1998, 
(September 22, 1998) (Staff Price Spike Report) at 3-1 to 3-2. It 
must be noted that a significant portion of the sales represent the 
retrading of power by a number of different market participants. In 
other words, there may be multiple resales of the same generation.
    \11\ Id. at 3-1.
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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 some states, implementing full 
scale retail access programs. As of May 1, 1999, 18 states have enacted 
electric restructuring legislation, 3 have issued comprehensive 
regulatory orders, and 28 others have legislation or orders pending or 
investigations underway.12 Fifteen states have implemented 
full-scale or pilot retail competition programs that offer a choice of 
suppliers to at least some retail customers. Eight states have set in 
motion programs to offer access to retail customers by a date certain.
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    \12\ ``Status of Electric Utility Deregulation Activity as of 
May 1, 1999,'' Energy Information Administration.
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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.'' 13 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.'' 14 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.'' 15
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    \13\ Reliability Assessment 1998-2007, North American Electric 
Reliability Council (September 1998), at 26.
    \14\ Id.
    \15\ 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. 16 NERC's 
TLR procedures were invoked 250 times between January 1 and September 
1, 1998 to prevent facility or interface overloads on the Eastern 
Interconnection. 17
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    \16\  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).
    \17\  Reliability Assessment 1998-2007 at 27.
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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.'' 
18 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. 19 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.'' 20
---------------------------------------------------------------------------

    \18\  Id. at 26.
    \19\  Id. at 7.
    \20\  Id.
---------------------------------------------------------------------------

    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 to an average price for the summer of approximately $40 
per MWh in the Midwest if the price spikes are excluded. 21 
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.
---------------------------------------------------------------------------

    \21\  Staff Price Spike Report at 3-8 to 3-11.
---------------------------------------------------------------------------

    The Commission staff undertook an investigation of the price spike 
incident. 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. 
22
---------------------------------------------------------------------------

    \22\  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.'' 23 Support for this view comes 
from many sources. For example, the Public Utilities Commission of 
Ohio, in its own report on the price spikes, recommended that policy 
makers ``take unambiguous action to require coordination of 
transmission system operations by regionwide Independent System 
Operators.'' 24
---------------------------------------------------------------------------

    \23\  Id. at 5-8.
    \24\  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

[[Page 31395]]

final report. 25 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.'' 
26
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    \25\  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.
    \26\  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 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. 27
---------------------------------------------------------------------------

    \27\  Id. at 76.
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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,28 the PJM ISO,29 ISO New 
England ISO,30 the New York ISO,31 and the 
Midwest ISO.32 In addition, the Texas Commission has ordered 
an ISO for the Electric Reliability Council of Texas 
(ERCOT).33 Moreover, our international neighbors in Canada 
and Mexico are also pursuing electric restructuring efforts that 
include various forms of regional transmission entities.34
---------------------------------------------------------------------------

    \28\ 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).
    \29\ Pennsylvania-New Jersey-Maryland Interconnection, et al., 
81 FERC para.61,257 (1997), reh'g pending (PJM).
    \30\ New England Power Pool, 79 FERC para.61,374 (1997), order 
on reh'g, 85 FERC para.61,242 (1998) (order conditionally 
authorizing ISO New England); New England Power Pool, 83 FERC 
para.61,045 (1998), reh'g pending (order on NEPOOL tariff and 
restructuring)(NEPOOL).
    \31\ 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).
    \32\ 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).
    \33\ See 16 Texas Administrative Code Sec. 23.67(p).
    \34\ See Policy Proposal for Structural Reform of the Mexican 
Electricity Industry, Secretary of Energy, Mexico (February 1999); 
Third Interim Report of the Ontario Market Design Committee (October 
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 system wide 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 began 
through a consensual process and was not driven by a pre-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 (Wisconsin).
    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 traditional control areas, but the 
Midwest ISO does not currently plan to operate a traditional 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 and there are holes in its coverage. 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.35 The 
Midwest ISO did not originally envision an ISO-related centralized 
market for its region.36 In addition, at least one separate 
PX has begun to do business in California apart from the PX established 
through the restructuring legislation.37
---------------------------------------------------------------------------

    \35\ 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.
    \36\ 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.
    \37\ 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).
---------------------------------------------------------------------------

    Not all efforts to create ISOs have been successful. For example, 
after more than two years of effort, the proponents of the IndeGO ISO 
in the Pacific Northwest and Rocky Mountain regions ended their efforts 
to create an ISO. More recently, members of MAPP, an existing power 
pool that covers six U.S.

[[Page 31396]]

states and two Canadian provinces, failed to achieve consensus for 
establishing a long-planned ISO. In the Southwest, proponents of the 
Desert Star ISO have not been able to reach agreement on a formal 
proposal after more than two years of discussion.
    Various reasons have been advanced to explain why it is difficult 
to form a voluntary, multi-state ISO. These include cost shifting in 
transmission capital costs; 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; the likelihood of not being able to 
maintain or gain a competitive advantage in power markets through the 
use of transmission facilities; 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.
    Apart from these efforts to create ISOs, we have received proposals 
for other types of transmission entities. For example, in October 1998 
a group of Arizona entities filed a request with the Commission to 
create an ``independent scheduling administrator'' (ISA) in 
Arizona.38 Unlike an ISO, this entity would not administer 
its own transmission tariff nor would it have any direct operational 
responsibilities. Instead, it appears that its functions would be 
limited to monitoring the scheduling decisions and OASIS site operation 
of the Arizona utilities that operate transmission 
facilities.39 In case of disputes, the ISA would provide a 
type of expedited dispute resolution process. The applicants state that 
the ISA would be a transitional organization that would ultimately 
evolve or be merged into a stronger, multi-state ISO.40 In 
other developments, one public utility has recently made a filing with 
us to sell its transmission assets to a newly formed 
affiliate.41 Another public utility recently filed a request 
for declaratory order asking us to find that its proposal to transfer 
its transmission assets (in the form of ownership or a lease) to a 
``transco'' in return for a passive ownership interest in the transco, 
would satisfy the Commission's eleven ISO principles.42
---------------------------------------------------------------------------

    \38\ Arizona Independent Scheduling Administrator Association, 
Docket No. ER99-388-000 (filed October 29, 1998).
    \39\ A proposal for a similar entity has been in the Pacific 
Northwest. This entity, described as an independent grid scheduler, 
would make actual scheduling decisions rather than simply monitoring 
the decisions made by current transmission owners. See Regional ISO 
Conference (Portland), transcript at 39-40.
    \40\ See Applicant's filing, Docket No. ER99-388-000, at 3.
    \41\ FirstEnergy, Inc., Docket No. EC99-53-000 (filed March 19, 
1999).
    \42\ Entergy Services, Inc., Docket No. EL99-57-000 (filed April 
5, 1999).
---------------------------------------------------------------------------

    As part of general restructuring initiatives, several states now 
require independent grid management organizations. For example, an 
Illinois law requires 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 and Arkansas have 
also enacted legislation requiring their electric utilities to join or 
establish regional transmission entities.
3. The Commission's ISO and RTO Inquiries; Conferences with 
Stakeholders and State Regulators
    In light of the various restructuring activities occurring 
throughout the U.S., the Commission has, within the past year, held 11 
public conferences in 9 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.\43\

    \43\ 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 
viewpoints were expressed. They will be discussed elsewhere in this 
NOPR and are summarized in Appendix A hereto.
    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.'' \44\ The Secretary 
also stated,

    \44\ 63 FR 53889 (1998).
---------------------------------------------------------------------------

    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.

    On November 24, 1998, we gave notice in this docket of our intent 
to initiate a consultation process with State commissions pursuant to 
section 202(a).45 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.46 
During these sessions, we received much valuable advice. We have set 
forth in Appendix B a summary of the comments received, and discuss in

[[Page 31397]]

Section III.B below our response to some of the major concerns 
expressed.
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    \45\ Notice of Intent to Consult Under Section 202(a), 63 FR 
66158 1998*), FERC Stats & Regs. para. 35,534 (1998).
    \46\ See Appendix B for a list of commenters.
---------------------------------------------------------------------------

C. Statutory Framework

    The Commission is granted the authority and responsibility by FPA 
sections 205 and 206, 16 U.S.C. 824d, 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.47 Additionally, as 
discussed in Order No. 888,48 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] Secs. 202 
and 203, and under like directives contained in Secs. 205, 206, and 
207.'' 49
---------------------------------------------------------------------------

    \47\ 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).
    \48\ Order No. 888, FERC Stats. & Regs. at 31,669.
    \49\ Gulf States Utilities Co. v. FPC, 411 U.S. 747, 758-59, 
reh'g denied, 412 U.S. 944 (1973) (Gulf States). See also 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.)
---------------------------------------------------------------------------

    The Commission also 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. This includes public utilities' 
transfers of control of jurisdictional transmission facilities to 
entities such as RTOs. Under section 203, the Commission must approve a 
proposed disposition of jurisdictional facilities if it is consistent 
with the public interest. 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.
    Further, section 202(a) of the FPA, whose authority has recently 
been delegated to the Commission by the Secretary of 
Energy,50 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.''
---------------------------------------------------------------------------

    \50\ 63 FR 53889 (1998).
---------------------------------------------------------------------------

III. Discussion

A. Barriers to Assuring an Abundant Supply of Electric Energy 
Throughout the United States with the Greatest Possible Economy

    In light of our experiences with ISOs and other utility 
restructuring activity in the aftermath of Order Nos. 888 and 889, and 
after almost three years of experience with implementation of Order 
Nos. 888 and 889, we believe that there remain important transmission-
related impediments to a competitive wholesale electric market. We have 
grouped these remaining impediments into two broad categories. The 
first category of impediments consists of engineering and economic 
inefficiencies inherent in the current operation and expansion of the 
transmission grid--inefficiencies that, in and of themselves, are 
hindering fully competitive power markets and imposing unnecessary 
costs on electric consumers. The second category of impediments 
consists of 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. Both 
sets of impediments unnecessarily restrict the scope of bulk power 
markets and inhibit the large-scale competition that we sought in 
issuing Order Nos. 888 and 889.
    The situation of the electric industry is somewhat analogous to the 
natural gas industry after the initial step of open access 
transportation was taken. In 1985, the Commission issued Order No. 
436,51 which instituted open-access, nondiscriminatory 
transportation of natural gas with the goal of increasing competition 
and permitting gas users to purchase gas directly from gas merchants. 
However, the Commission subsequently found that open access alone was 
not sufficient to remove all barriers to competition. 52 
Because of the different structures of the electric and gas industries, 
the specific remaining impediments to competition may not be the same, 
but there are similarities in that open access, without sufficient 
mechanisms for ensuring that such access is equal and efficient for all 
participants, may not be enough to promote a fully competitive market. 
53
---------------------------------------------------------------------------

    \51\ Regulation of Natural Gas Pipelines After Partial Wellhead 
Decontrol, Order No. 436, 50 FR 42408 (Oct. 18, 1985), FERC Stats. & 
Regs. [Regulations Preambles 1982-1985] para. 30,665 1985), vacated 
and remanded, Associated Gas Distributors v. FERC, 824 F.2d 981 
(D.C. Cir. 1987), cert. denied, 485 U.S. 1006 (1988), readopted on 
an interim basis, Order No. 500, 52 FR 30334 (Aug. 14, 1987), FERC 
Stats. & Regs. [Regulations Preambles, 1986-1990] para.30,761 
(1987), remanded, American Gas Association v. FERC, 888 F.2d 136 
(D.C. Cir. 1989), readopted, Order No. 500-H, 54 FR 52334 (Dec. 21, 
1989), FERC Stats. & Regs. [Regulations Preambles 1986-1990] para. 
30,867 (1989), reh'g granted in part and denied in part, Order No. 
500-I, 55 FR 6605 (Feb. 26, 1990), FERC Stats. & Regs. [Regulations 
Preambles 1986-1990] para. 30,880 (1990), aff'd in part and remanded 
in part, American Gas Association v. FERC, 912 F.2d 1496 (D.C. Cir. 
1990), cert. denied, 111 S. Ct. 957 (1991).
    \52\ In the case of natural gas, we found that the principal 
remaining barrier was the continued existence of bundled city-gate 
firm sales service that had a transportation component of higher 
quality than available through open access. Hence, we issued Order 
No. 636 to unbundle services and equalize the quality of service 
offered. See Pipeline Service Obligations and Revisions to 
Regulations Governing Self-Implementing Transportation and 
Regulation of Natural Gas Pipelines After Partial Wellhead 
Decontrol, 57 FR 13267 (April 16, 1992), III FERC Stats. & Regs. 
para. 30,939 (April 8, 1992), reh'g granted and denied in part, 
Order No. 636-A, 57 FR 36128 (August 12, 1992), III FERC Stats. & 
Regs. para. 30,950 (August 3, 1992), order on reh'g Order No. 636-B, 
57 FR 57911 (December 8, 1992), 61 FERC para. 61,272 (1992), Notice 
of Denial of Rehearing (January 8, 1993), 62 FERC para. 61,007 
(1993), aff'd in part and vacated and remanded in part, United Dist. 
Companies v. FERC, 88 F.3d 1105 (D.C. Cir. July 16, 1996), order on 
remand, Order No. 636-C, 78 FERC para. 61,186 (1997).
    \53\ For a discussion of the similarities and differences in the 
structure and regulation of the natural gas and electric industries, 
see generally Santa and Sikora, Open Access And Transition Costs: 
Will The Electric Industry Transition Track The Natural Gas 
Restructuring?, 15 Energy L.J. 273 (1994).
---------------------------------------------------------------------------

    Our current understanding of industry conditions, as set forth 
below, will be enhanced by future consultations with and analysis from 
all industry stakeholders, including state commissions. The Commission 
seeks comments in order to achieve a deeper

[[Page 31398]]

appreciation of any impediments to competition in the Nation's 
electricity markets and how they should be addressed.
1. Engineering and Economic Inefficiencies in the Operation, Planning 
and Expansion of Regional Transmission Grids
    The transmission facilities of any one utility in a region are part 
of a larger, integrated transmission system. From an electrical 
engineering perspective, each of the three interconnections in the 
United States (the Eastern, the Western and ERCOT) operates as a single 
``machine.'' 54 The Eastern Interconnection also extends 
into Canada, and the Western Interconnection includes parts of Canada 
and Mexico.
---------------------------------------------------------------------------

    \54\ North American Electric Reliability Council, Electric 
Reliability Panel, ``Reliable Power: Renewing the North American 
Electric Reliability Oversight System,'' December 1997, at 9.
---------------------------------------------------------------------------

    Problems have arisen over the last three years, in part, because we 
have multiple operators of each of these machines. Each separate 
operator usually makes independent decisions about the use, limitations 
and expansion of its piece of the interconnected grid based on 
incomplete information. This approach--separate operation of each 
utility's own transmission facilities--would make engineering sense 
only if each system operated independently of the others. But the 
physical reality is that, within the three interconnected grids, any 
action taken by one transmission provider can have major and 
instantaneous effects on the transmission facilities of all other 
transmission providers.55
---------------------------------------------------------------------------

    \55\ U.S. Congress, Office of Technology Assessment, ``Electric 
Power Wheeling and Dealing, Technological Considerations for 
Increasing Competition,'' May, 1989.
---------------------------------------------------------------------------

    This is not a new phenomenon. Since the very first transmission 
interconnection between two neighboring utilities, interconnected 
utilities have had to cope with the fact that electricity will flow 
over others' lines. In the past, these effects were often small or 
infrequent and the utility could generally pass any costs through to 
captive customers. Today, with the increase in bulk power trade and the 
large shifts in power flows, the effects may be large, frequent and not 
recoverable by the utility bearing the cost.
    Another important change is that the structure of the industry that 
exists today is very different from the industry that existed three 
years ago when we issued Order No. 888. The industry is no longer 
composed uniformly of vertically-integrated, self-sufficient public 
utilities that do not compete with each other. Instead, it is an 
increasingly de-integrated and decentralized industry with many new and 
existing participants that actively compete against each 
other.56
---------------------------------------------------------------------------

    \56\ For example, there are now about 550 Commission-approved 
power marketers. Decentralization has also increased because of 
divestiture of generating plants by traditionally vertically 
integrated utilities. Such sales are frequently required by state 
governments as one element of the structural reforms that accompany 
the introduction of retail competition. During the last three years, 
utilities have sold or have contracts to sell more than 50,000 MW of 
existing generating capacity. About 30,000 MW of additional capacity 
is currently being offered for sale.
---------------------------------------------------------------------------

    As a consequence of these changes in trade patterns and industry 
structure, certain operational problems have become more significant 
and more difficult to resolve. These include: maintaining reliable grid 
operations; determining available transmission capability (ATC); 
57 managing transmission congestion; and planning and 
investing in new transmission facilities. In addition, traditional 
approaches to the pricing and provision of transmission service may be 
hindering the further development of competitive and efficient bulk 
power markets. These impediments include: pancaking of transmission 
access charges; non-market approaches to managing congestion; 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. The Commission believes that 
properly structured RTOs can address both sets of problems and further 
the development of competitive bulk power markets.
---------------------------------------------------------------------------

    \57\ See definition of ATC infra.
---------------------------------------------------------------------------

a. Reliable Grid Operations
    The United States has one of the most reliable power systems in the 
world. For over thirty years, NERC and the regional reliability 
councils have developed and implemented voluntary standards to maintain 
the security of the transmission systems. There is no net public policy 
benefit to promoting competition if reliability suffers as a 
consequence.58 The promotion of competition must therefore 
go hand-in-hand with the creation of new institutions to ensure that 
reliability is maintained or improved in any new industry 
structure.59 We fully agree with the findings of the DOE 
Reliability Task Force:

    \58\ Unless otherwise noted, we use the term ``reliability'' to 
refer to the reliable or secure operation of the bulk power grid. 
This is one component of the broader NERC definition, which also 
includes ``adequacy'' (i.e., sufficient generation and transmission 
capacity) as a second component of overall reliability. See North 
American Electric Reliability Council, ``Glossary of Terms,'' August 
1996, at 21.
    \59\ See George C. Loehr, ``Ten Myths About Electric 
Deregulation: Electrons May Seem Imaginary, But Reliability Is 
Real,'' Public Utilities Fortnightly, April 15, 1998, at 28-31.
---------------------------------------------------------------------------

* * * there is a critical need to be sure that reliability is not 
taken for granted as the industry restructures, and thus does not 
``fall through the cracks.'' 60

    \60\ DOE Task Force Report, at xv.
---------------------------------------------------------------------------

    The DOE Reliability Task Force also pointed out that with the entry 
of many new participants, dramatic increases in unbundled power sales 
and shifts in electrical flows, the nation's bulk power system is being 
stressed in ways that have never been experienced before. A similar 
conclusion was reached by NERC in its 1998 summer assessment of bulk 
power reliability:

    Throughout the Regions, parallel path flows from increased 
electricity transfers are stressing the transmission systems. These 
flows are at magnitudes and in directions not anticipated at the 
time the systems were designed.* * *The transmission system will be 
required to operate under unprecedented, and sometimes unstudied, 
conditions.61

    \61\ NERC, ``1998 Summer Assessment: Reliability of Bulk 
Electricity Supply in North America,'' May 1998, at 2-3.
---------------------------------------------------------------------------

These stresses have always existed but not in these magnitudes. 
Moreover, they could be more readily accommodated through voluntary ad 
hoc agreements when there were fewer industry participants who 
generally did not compete against each other in any significant 
way.62 But as we have noted, this traditional industry 
structure is rapidly disappearing. Our concern is that the reliability 
fault lines may become more prominent and dangerous.
---------------------------------------------------------------------------

    \62\ In assessing the continued viability of the current system, 
NERC's blue-ribbon Electric Reliability Panel concluded that: ``The 
competitive dynamics among a much larger universe of players is not 
at all conducive to a system of voluntary peer compliance.'' 
Electric Reliability Panel Report, December 1997, at 28.
---------------------------------------------------------------------------

    It is well accepted that the operation of interconnected 
transmission networks requires careful coordination and the exchange of 
information between many individual systems. Any operational change on 
one system in the network instantly affects other systems. For example, 
the shipment of power from one location to another will divide among 
all transmission paths from source to destination based on the laws of 
physics.63 This is referred to as

[[Page 31399]]

parallel path or loop flow. Such flows will also affect a neighboring 
system's ability to determine ATC accurately. In addition, if a 
transmission facility is already loaded close to its operating limit, 
the additional flow resulting from a transaction contracted for on a 
neighboring system may overload the facility and threaten reliability. 
In order to operate the system in a reliable manner, a single, 
independent grid operator must know all sources and destinations for 
each transaction. The Commission believes that an RTO, as the only 
transmission provider and security coordinator in its region, would 
have the information needed to identify the effects of parallel flows 
and accommodate them in its operations.
---------------------------------------------------------------------------

    \63\ The amount of power flowing on any path in an electrical 
network is inversely proportional to that path's impedance. 
Impedance will depend on the actual length of the line and its 
voltage. See U.S. Congress, Office of Technology Assessment, 
Electric Power Wheeling and Dealing: Technological Considerations 
for Increasing Competition, OTA-E-409, May 1989, at 110-11.
---------------------------------------------------------------------------

    At present, the industry's ability to maintain reliable grid 
operation is hindered by the existence of many separate organizations 
that directly or indirectly affect the operation and expansion of the 
grid. There are more than 100 owners of the Nation's grid who operate 
about 140 separate control areas.64 In addition, there are 
10 regional reliability councils, 23 security coordinators, 5 regional 
transmission groups (RTGs) and 5 independent system operators. With so 
many entities, the lines of authority and communication are not always 
as clear as they should be.65 An additional complication is 
that many of these entities also own generation or have a decision 
making process that continues to be dominated by traditional vertically 
integrated utilities.66 Therefore, their independence and 
commercial neutrality as grid operators is subject to question.
---------------------------------------------------------------------------

    \64\ A control area is an electrical system bounded by 
interconnection (tie-line) metering and telemetry. Within a control 
area, resources are balanced against load, and generation is 
regulated to maintain interchange schedules with other control areas 
and to achieve the target frequency (60 hz) for the entire 
Interconnection. See NERC Operating Policies Manual (available on 
the NERC website at www.nerc.com).
    \65\ See, e.g., Western Systems Coordinating Council, EL99-23-
000, comments of Enron Power Marketing, Inc. at 4-5.
    \66\ See, e.g., New England Power Pool, 86 FERC para. 61,262 at 
61,965 (1999).
---------------------------------------------------------------------------

    It appears that information that is critical for maintaining 
reliability is not being shared as readily now as was generally the 
case in the past. NERC recently observed that there is a growing 
``reluctance on the part of the market participants to share 
operational real-time and operational planning data with TPs 
[transmission providers].'' 67 This is not surprising 
because, as we have noted before, information that is needed for 
reliability purposes may also have a commercial value.68 If 
market participants believe that the entity that receives operational 
information for reliability reasons may use it for commercial 
advantage, they will understandably be reluctant to supply the 
information. After spending more than 18 months reviewing the current 
reliability system, the DOE Reliability Task Force concluded that this 
inherited system, with its patchwork of organizations, inadequate 
information sharing and overlapping and sometimes unclear 
responsibilities, is ``clearly unsustainable'' and that until new 
policies and institutions are in place, ``substantial parts of North 
America will be exposed to unacceptable risk.'' 69
---------------------------------------------------------------------------

    \67\ NERC, Reliability Assessment 1998-2007 at 39 (1998).
    \68\ Midwest ISO, 84 FERC at 62, 158-159.
    \69\ DOE Task Force Report at vii and xi.
---------------------------------------------------------------------------

    This is not just a theoretical concern. During last year's regional 
ISO conferences, several industry participants described three 
``reliability near misses'' in the Midwest. The three incidents on July 
22, 1993, August 7, 1996 and July 11, 1997 came very close to producing 
major outages throughout the Midwest.70 While there has been 
some improvement in coordination among different systems, we believe 
that there are limits to the amount of coordination that can be 
achieved between separate organizations, especially if they are 
competing for the right to use the same limited transmission capacity 
and sometimes competing for the same customers. While competition 
requires decentralization, we think that reliable and efficient grid 
operation requires more coordination. The Commission believes that a 
beneficial platform for both competition and reliability is a single 
independent grid operator that sees the ``big picture'' by having 
access to real-time information on conditions and schedules for the 
entire regional grid.71 Such an entity does not exist in 
several regions of the country. As a consequence, there is, at present, 
a disconnect between electrical flows and information flows that could 
have major reliability consequences.
---------------------------------------------------------------------------

    \70\ Regional ISO Conference (Indianapolis), transcript at 24-
29.
    \71\ The importance of a single operator for reliability was 
stressed in comments of AMEREN and Commonwealth Edison. See Regional 
ISO Conference (Indianapolis), transcript at 19-29.
---------------------------------------------------------------------------

b. Determining Available Transmission Capability (ATC)
    Any transportation service provider should know how much commodity 
it can carry. For electric transmission service providers, the 
calculations of total transmission capability (TTC) and ATC are needed 
to make this determination. TTC and ATC are key elements of the OASIS 
information system.72 Order No. 889 requires each 
transmission provider to calculate and post TTC and ATC numbers to give 
its transmission customers a reasonable estimate of how much power can 
be carried between any two locations on the grid and how much capacity 
is available to support additional trade at any given time.
---------------------------------------------------------------------------

    \72\ ATC is a measure of transfer capability remaining in the 
physical transmission network for further commercial activity over 
and above already committed uses. TTC is the amount of electric 
power that can be transferred over the interconnected transmission 
network in a reliable manner based on certain specified conditions, 
North American Reliability Council, Glossary of Terms (1996).
---------------------------------------------------------------------------

    We have received many complaints about the accuracy and usefulness 
of posted ATC numbers. There are several reasons why it is difficult to 
determine available transmission capability accurately.
    First, ATC numbers are still calculated on an individual company 
basis in many areas of the country. Separate calculations of ATC by 
individual companies are fundamentally inconsistent with the physical 
reality of an interconnected transmission system. An individual 
transmission provider may post ATC numbers in good faith, and attempt 
to provide transmission service based on these numbers, only to learn 
later that the transfer capability that it thought was available no 
longer exists because of decisions made by other transmission providers 
that it did not know about at the time it made its calculations. 
Accurate ATC numbers would require reliable and timely information 
about load, generation, facility outages and transactions on 
neighboring systems. Individual transmission operators will generally 
not have this information. They also may apply differing assumptions 
and criteria to ATC calculations, which may produce wide variations in 
posted ATC values for the same transmission path.73 All 
these considerations make it virtually impossible for an individual 
transmission provider that operates one

[[Page 31400]]

part of a large interconnected grid to calculate ATC 
accurately.74
---------------------------------------------------------------------------

    \73\ This, in turn, creates other problems. According to NERC, 
the ``inconsistent calculation [of ATC] can increase the use of TLR 
and other operational complexities, which has the potential to cause 
reliability problems.'' NERC, Reliability Assessment, 1998-2007, 
September, 1998, at 40. (See definition of TLR in section II.)
    \74\ In addition, it has been frequently alleged that individual 
transmission may intentionally post inaccurate ATC numbers to favor 
their own power marketing efforts. These allegations are discussed 
in section III.A.2.
---------------------------------------------------------------------------

    Second, requests for transmission service are usually based on 
``contract path'' scheduling. This is the practice of finding a 
contiguous chain of utilities from the power supplier to the power 
consumer and contracting with those utilities to transmit the power. 
The implicit assumption is that all the power flows through the 
utilities along this ``contract path.'' In fact, the power divides up 
and flows along all paths from the supplier to the buyer. All utilities 
in the region are affected. Contract path scheduling provides little or 
no information about actual flows on the grid.75 In its 
October 1997 report to the Commission, the Commercial Practices Working 
Group commented that: ``Reserving and scheduling transmission on a 
contract path basis does not even closely resemble the physical impact 
on the system.'' 76 We note that NERC is encouraging 
initiatives that would move the industry toward recognizing actual 
flows in scheduling.77
---------------------------------------------------------------------------

    \75\ See Allegheny Power Service Corporation et al., 78 FERC 
para. 61,314 at 62,339.
    \76\ October 31, 1997 report, at 39.
    \77\ See NERC, 85 FERC at 62,363.
---------------------------------------------------------------------------

c. Managing Congestion
    Congestion occurs when requests for transmission service exceed the 
capability of the grid. When transmission constraints limit the amount 
of power that can be transmitted, the loads on the system may not be 
able to be served by the least-cost mix of available generators. The 
constraints may reflect voltage, temperature and dynamic limits. 
Relieving congestion leads to a more costly pattern of generation 
dispatch. The cost of congestion is the additional energy cost 
associated with the new pattern of dispatch.
    We recognize that even optimally designed systems will normally 
experience at least occasional congestion that at times can be 
significant and costly. In general, congestion can be managed in two 
ways: the construction of new transmission facilities that increase 
grid capacity; or the redispatch of existing or new generators to 
reduce flows or create counterflows on the constrained facility. The 
complete elimination of congestion would typically require the 
construction of new transmission facilities. While this may be a 
physically effective solution, it may not always be cost effective. 
Because of this, we believe that an efficiently operated transmission 
system should have in place mechanisms for pricing congestion and then 
managing congestion through changes in the pattern of dispatch. Without 
mechanisms for determining the cost of congestion, it will be virtually 
impossible to make rational, cost effective decisions to expand the 
grid.
    The Commission believes that efficient congestion management is 
best performed at the regional level. At present, outside of the 
operational ISOs, transaction curtailment through transmission loading 
relief (TLR) procedures is the dominant approach for dealing with 
congestion in the Eastern Interconnection. NERC has reported that its 
TLR procedures were invoked 329 times between July 1997 and October 
1998 on the Eastern Interconnection.78 Current TLR 
procedures are cumbersome, inefficient and disruptive to bulk power 
markets because they rely exclusively on physical measures of flows 
with no attempt to assess the relative costs of different congestion 
management options. Moreover, TLR actions are typically taken by one 
utility without assessing the costs imposed on other grid users. This 
inevitably raises the suspicion that the TLR request could be motivated 
by competitive rather than reliability concerns. For these reasons, the 
Commission has encouraged NERC to develop regional market approaches to 
managing congestion.79
---------------------------------------------------------------------------

    \78\ North American Electricity Reliability Council, Interim 
Market Interface Committee, Minutes of Jan. 12 and 13, 1999 meeting, 
Exhibit D.
    \79\ See NERC, 85 FERC at 62,364.
---------------------------------------------------------------------------

    The Commission recognizes, however, that NERC may not be able to 
comply fully with this policy in the absence of regional organizations 
that have the authority and ability to promote regional congestion 
markets. There are three considerations that support this conclusion.
    First, a regional organization would have accurate and reliable 
information about existing and possible future conditions on the grid. 
Such information is generally not available to individual transmission 
providers. RTOs would have this information because they would function 
as both regional security coordinators and regional transmission 
providers.
    Second, congestion management is best performed at a regional 
level. This is shown in the largely unsuccessful efforts of 
Commonwealth Edison to create congestion markets that would allow 
transmission customers to ``buy-through'' (i.e., firm up) transmission 
rights on congested flow gates. After six months of its one year 
experiment, we note that Commonwealth concluded that it is ``difficult 
for one transmission owner to identify and implement redispatch'' when 
the physical limitations and cost effective options for relief exist on 
other transmission systems that are beyond their reach.80
---------------------------------------------------------------------------

    \80\ Commonwealth Edison, Interim Report on Non-Firm Redispatch, 
Docket No. ER98-2279, December 17, 1998, at 4, 10.
---------------------------------------------------------------------------

    Third, RTOs will be able to establish and define rights to the use 
of the grid. At present, with multiple and independent operators of the 
grid, individual users and owners have unclear and conflicting rights 
to the grid. This makes it difficult to establish congestion markets. A 
congestion market, like any other market, cannot develop in the absence 
of clear rights.\81\ Such rights, whether held by transmission users or 
owners, are a necessary prerequisite for establishing congestion 
markets. Without establishing such rights, the industry will continue 
to grapple with the problem of incomplete markets. Thus, it is 
difficult to achieve efficient and competitive regional bulk power 
markets if congestion on the transmission grid is not accurately 
priced.
---------------------------------------------------------------------------

    \81\ Robert Cooter and Thomas Ulen, Law and Economics, Scott, 
Foresman and Company, 1988, at 91 (``From a legal viewpoint, 
property is a bundle of rights'').
---------------------------------------------------------------------------

d. Planning and Expanding Transmission Facilities
    Transmission planning and expansion are more difficult today than 
three years ago. While uncertainty has always been a fact of life for 
any transmission planning exercise, the level of uncertainty has 
increased with the increasing number and distance of unbundled 
transactions and the wider variation in generation dispatch patterns. 
Uncertainty has also increased because:

    Generation developers are reluctant to disclose their plans for 
future capacity additions. Similarly, utilities intending to 
purchase from others are reluctant to speculate on whom or where 
their suppliers might be, making modeling of such transactions for 
transmission analysis virtually impossible.\82\
---------------------------------------------------------------------------

    \82\ NERC, ``Reliability Assessment, 1998-2007,'' September 
1998, at 39.

One troubling consequence of this uncertainty has been a noticeable 
decline in planned transmission investments. NERC recently reported 
that the level of planned transmission

[[Page 31401]]

additions is significantly lower than five years ago despite an overall 
increase in load growth and unbundled transmission service.\83\ While 
this could simply reflect better utilization of the existing grid, the 
Commission is concerned that it may also reflect an incompatibility of 
existing planning institutions with the new market realities.
---------------------------------------------------------------------------

    \83\ Id. at 7.
---------------------------------------------------------------------------

    We are also concerned that the existing approach to transmission 
pricing may not sufficiently encourage the investments in transmission 
facilities that are needed to improve the reliability and efficiency of 
the grid. Inadequate investment could be a major impediment to the 
development of regional bulk power markets and a possible source of 
future reliability problems. There are at least three concerns about 
the way transmission prices are set.
    First, although there are varying degrees of investment 
coordination around the country, utilities ultimately make transmission 
investment decisions individually rather than through joint decisions 
that internalize commercial and reliability effects of the investment. 
It may be unclear which utility should have the responsibility for 
expanding capacity to relieve a transmission constraint. For example, 
power flows scheduled by one utility with ample transmission capacity 
on its own lines may overload a neighbor's lines. The first utility may 
be unwilling to expand transmission capacity because it needs no extra 
transmission capacity itself, and the second utility may be unwilling 
to expand transmission capacity because it collects no revenues from 
the power flows scheduled by others. In a multi-utility region, 
decisions about where to site new facilities and who should pay for 
capacity expansions can be even more complex unless a regional body 
provides a forum for discussions and a method for resolving disputes.
    Second, the motivation for constructing new facilities is changing 
as the industry changes. Formerly, a utility built transmission 
primarily to deliver power from its generating plants to its customers. 
Inadequate transmission would have hurt power sales, the principal 
source of utility revenue. Today, facility expansion may be needed to 
transmit power sold by others. As generation and transmission ownership 
become increasingly separate and as many states implement or even 
merely consider retail access, the transmission owner's traditional 
incentive for making new transmission investment to support its power 
sales erodes. Incentives for transmission investment need to be related 
more to the power needs of the region than the generation stock of the 
transmission owners.
    Third, the transmission owner that does invest in transmission to 
overcome a constraint may be concerned about recovering its investment. 
Under traditional ratemaking practices, it must recover its investment 
over a long period of time, typically thirty years. But subsequent 
generation construction on the power-poor side of the constraint may 
obviate the need for the line and threaten recovery of its capital 
cost. In addition, where there is higher risk, a higher return 
commensurate with the higher risk may be appropriate. To support this, 
customers and regulators would want assurance that the decision to 
invest in transmission is made in the best interests of the region, 
considering not only all the transmission options but also the 
generation and demand management alternatives to transmission 
construction. Therefore, as discussed below, we will consider concrete 
proposals from regional transmission organizations for transmission 
pricing reforms and the explicit use of pricing incentives to encourage 
RTOs to make efficient investments in new transmission facilities.
e. Pancaked Transmission Rates
    With the exception of power pools, open access under Order No. 888 
focuses on individual, existing transmission providers. Order No. 888 
does not require transmission pricing reforms that are needed to 
support efficient and competitive bulk power markets. The ``missing'' 
reforms include, among others, the elimination of pancaked transmission 
access charges, the use of reservation-based (as opposed to load-based) 
transmission tariffs and the availability of secondary markets in 
transmission rights.84 In this section, we will focus on the 
problems created by the widespread pancaking of transmission access 
charges.85
---------------------------------------------------------------------------

    \84\ See, e.g., Capacity Reservation Open Access Transmission 
Tariffs, Notice of Proposed Rulemaking, FERC Stats. and Regs. para. 
32,519 (1996) and Inquiry Concerning the Commission's Pricing Policy 
for Transmission Services Provided by Public Utilities Under the 
Federal Power Act: Policy Statement, 69 FERC para. 61,086 (1994).
    \85\ We did, however, require non-pancaked rates for power pools 
that offer non-pancaked rates to their own members in Order No. 888. 
Order No. 888, FERC Stats, and Regs. at 31,727-28.
---------------------------------------------------------------------------

    In most of the United States, a transmission customer pays 
separate, additive access charges every time its contract path crosses 
the boundary of a transmission owner. By raising the cost of 
transmission, pancaking reduces the size of geographic power markets. 
This, in turn, can result in concentrated electricity markets. 
Balkanization of electricity markets hurts electricity consumers, in 
general, by forcing them to pay higher prices than they would in a 
larger, more competitive, bulk power market.86
---------------------------------------------------------------------------

    \86\ While it is difficult to estimate the exact impact on 
consumers, we note that there have been studies of the deregulated 
British power markets that have found excessive concentration in 
generation has produced prices 20 to 40 percent above competitive 
levels at certain times. Richard Green and David Newbery, 
Competition in the British Electricity Spot Market, 100 J. Pol. 
Econ., 929, 1992.
---------------------------------------------------------------------------

    The Commission has heard from many states about the negative 
effects of pancaked rates in their efforts to introduce retail 
competition. At this time, about 21 states have introduced or are 
planning to introduce competition for retail loads under their 
jurisdiction.87 Because the Commission has jurisdiction over 
transmission service and rates for unbundled retail customers, we have 
an obligation to address these concerns.88 A retail choice 
initiative, no matter how well designed at the state level, may fail if 
the pool of potential competitors is effectively limited to a few 
nearby supply sources because of pancaked transmission charges.
---------------------------------------------------------------------------

    \87\ ``Status of Electric Utility Deregulation as of May 1, 
1999,'' Energy Information Administration.
    \88\ Order No. 888, FERC Stats. and Regs. at 31,651-52.
---------------------------------------------------------------------------

    This concern of pancaked rates was highlighted to us in the recent 
consultations with our state commission colleagues. Several state 
commissioners emphasized that the success of their retail competition 
initiatives is related to the adoption of non-pancaked transmission 
tariffs and other ISO policies.89 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.
---------------------------------------------------------------------------

    \89\ See, e.g., Comments of Gerald Thorpe (Maryland) and 
President Herbert Tate (New Jersey), RTO Conference (Washington, 
DC), transcript at 37-39; 49-51.
---------------------------------------------------------------------------

f. Conclusion
    We believe that the preferred solution to the engineering and 
economic problems discussed in this section is a regional solution. 
Notwithstanding it success, Order No. 888 has not been able to produce 
a fully efficient and competitive outcome because it does not address 
ATC calculations, congestion

[[Page 31402]]

management, reliability, pancaking of transmission access charges, and 
grid planning and expansion. These are regional problems. Therefore, we 
are proposing a rule to encourage the development of independent 
regional transmission operators that can promote both electric system 
reliability and competitive generation markets.
2. Actual and Perceived Discriminatory Conduct by Transmission Owners 
to Favor Their Own or Affiliated Merchant Operations
    In addition to operational inefficiencies impeding full 
competition, there also exist questions about residual discrimination 
in the provision of transmission services by public utilities. As 
discussed below, many in the industry have expressed a fundamental 
mistrust of transmission owners. In addition, there are allegations, 
and in some circumstances findings, of actual discrimination by 
transmission owners. We discuss below indications of discriminatory 
conduct by vertically integrated utilities and seek further comment on 
utility practices subsequent to Order No. 888.
    Utilities that control monopoly transmission facilities and also 
have power marketing interests 90 have poor incentives to 
provide equal quality transmission service to their power marketing 
competitors. It is, in fact, in the economic self-interest of 
transmission-owning utilities to favor their own power marketing 
interests and frustrate their competitors. As the Commission stated in 
Order No. 888:

    \90\ The term power marketing interests is used as shorthand 
herein to include the utility's own wholesale merchant function as 
well as any affiliates with wholesale merchant functions.
---------------------------------------------------------------------------

    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.\91\
---------------------------------------------------------------------------

    \91\ Order No. 888, FERC Stats. and Regs. at 31,682.

The exercise of transmission market power allows transmission providers 
with power marketing interests to benefit in the short-run by making 
more power sales at higher prices, and benefit in the long-run by 
deterring entry by other market participants. As a result, prices to 
the Nation's electricity consumers will be higher than need be.
    It was to eliminate this inherent tendency of a vertically-
integrated utility to favor its own power sales that Order Nos. 888 and 
889 required utilities to functionally unbundle their transmission and 
power merchant services. Generally, functional unbundling requires a 
public utility to: separate its transmission system functions and staff 
from wholesale generation marketing functions and staff; abide by a 
standard of conduct to define impermissible contact between generation 
and transmission personnel; take transmission services under the same 
open access tariff of general applicability as do others; state 
separate rates for wholesale generation, transmission, and ancillary 
services; and rely on the same Open Access Same-Time Information System 
(OASIS) that its transmission customers rely on to obtain information 
about its transmission system when buying or selling 
power.92 The Commission imposed these requirements to 
establish a foundation for open grid access and competitive electricity 
markets.
---------------------------------------------------------------------------

    \92\ Id. at 31,654-55.
---------------------------------------------------------------------------

    Functional unbundling did not change the incentives of vertically-
integrated utilities to use their transmission assets to favor their 
own generation, but instead attempted to reduce the ability of 
utilities to act on those incentives. 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.\93\ However, the Commission decided 
at the time to adopt what it considered to be the less intrusive and 
less costly remedy.
---------------------------------------------------------------------------

    \93\ Id. at 31,653-54.
---------------------------------------------------------------------------

    Clearly, Order No. 888 has resulted in wholesale power markets 
becoming more competitive, more transmission services being made 
available to more potential users than ever before, and generally lower 
transaction costs.
    However, market participants increasingly have alleged that 
numerous transmission service problems related to discriminatory 
conduct remain, and that these problems are impeding competitive 
wholesale power markets.\94\ Our information about alleged continued 
discriminatory practices comes from several sources. These include 
formal complaints filed with the Commission, 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.
---------------------------------------------------------------------------

    \94\ See, e.g.,  of Roger Fontes on behalf of the Northern 
California Power Agency, Regional ISO Conference (Phoenix), 
Transcript at 136 (``In general, orders 888 and 889 have not fully 
remedied undue discrimination in providing transmission service in 
this country.'')
---------------------------------------------------------------------------

    Compared to the situation before Order No. 888, transmission-owning 
utilities must now resort to more subtle means to frustrate their 
marketing competitors and favor their own marketing interests. 
Continued discrimination may be conscious and deliberate, but it may 
also result from the failure to make sufficient efforts to change the 
way integrated utilities have done business for many years. In either 
case, the tendency of transmission owners to confer advantages, however 
subtle, upon their own marketing interests is discriminatory as against 
other marketers.
    In the sections that follow, we will outline the information 
derived from filings and other sources about remaining impediments to 
competition caused by continued discriminatory conduct by transmission 
owners. We note, and we are well aware, that many allegations that have 
been made in various forums are unproved, and perceived discrimination 
may in fact turn out to have justifiable explanations. 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 resulted from the 
need to serve native load customers or the impartial application of 
operating or technical requirements. Given our considerable difficulty 
in determining whether there has been compliance with our regulations, 
the question arises whether functional unbundling is an appropriate 
long-term regulatory solution.
    We consider allegations of discrimination, even if not reduced to 
formal findings, to be a serious concern for two reasons. First, we may 
be seeing only the ``tip of the iceberg.'' We are aware that instances 
of actual discriminatory conduct may be undetectable in a non-
transparent market. In addition, there are significant disincentives to 
filing and pursuing formal complaints that would result in definitive 
findings. Transmission customers often tell the Commission's 
enforcement staff that they are reluctant to make even informal 
complaints because of concerns that the Commission will not take strong 
action, and fear, perhaps most importantly, of retribution by their 
transmission supplier.95 We also have been told that

[[Page 31403]]

the complaint process is costly and time-consuming,96 and 
that the Commission's remedies for transmission violations do not 
impose sufficient financial harms on the transmission provider to act 
as a significant deterrent.97
---------------------------------------------------------------------------

    \95\ See Comments of Dan Jones on behalf of the Public Utilities 
Commission of Texas, Regional ISO Conference (Kansas City), 
Transcript at 1985 (``And we've also heard that these entities are 
hesitant to bring those complaints forward because they have to deal 
with both sides of that utility'').
    \96\ We note that we have recently issued a Final Rule regarding 
complaint procedures designed to make them more efficient. See 
Complaint Procedures, Final Rule, Docket No. RM98-13-000, 86 FERC 
para. 61,324 (issued March 31, 1999).
    \97\ Comments of National Energy Marketers Association, Docket 
No. RM98-5-000 (filed January 22, 1999).
---------------------------------------------------------------------------

    Perhaps the most problematic aspect of relying on after-the-fact 
enforcement in the fast-paced business of power marketing, however, is 
that there may be no adequate remedy for lost short-term sale 
opportunities. For example, the Electric Power Supply Association 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.98

    \98\ 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.

Accordingly, actual problems with functional unbundling may be more 
pervasive than formally adjudicated complaints would suggest, and the 
informal allegations we hear provide valuable insight.
    Second, we consider the allegations of discrimination to be serious 
because, if nothing else, they represent a perception by market 
participants that the market is not working fairly because such 
participants know that integrated utilities have the incentive and 
opportunity to discriminate. Mistrust in the market can itself be a 
serious impediment to competition. If market participants perceive that 
other participants have an unfair advantage through the affiliation 
with the transmission provider, it can inhibit their willingness to 
participate in the market, including, for example, building new 
generating units, thus thwarting the development of robust competition. 
Such mistrust can also harm reliability. 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.99
---------------------------------------------------------------------------

    \99\ NERC Reliability Assessment 1998-2007, at 39.
---------------------------------------------------------------------------

    The functional unbundling policy underlying Order No. 888 was an 
attempt to regulate the behavior of transmission owners. There are 
growing indications, however, that the conflicting incentives that 
vertically integrated utilities have regarding transmission access may 
be too difficult to police. Many have asserted that it is not realistic 
even to expect functional unbundling to eliminate attempts by 
transmission owners to gain economic advantage. Companies have an 
obligation to maximize value for shareholders, and it should be no 
surprise that they will be aggressive in doing so. For example, in 
comments to the Commission in the Order No. 888 proceeding, 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.'' A representative of Lafayette Utilities 
told us at the New Orleans ISO Conference:

    Notwithstanding functional separation and the requirement not to 
discriminate, transmission personnel are well aware of the interests 
of their company's generation function, and can find a way to give 
preferential treatment. * * * 100
---------------------------------------------------------------------------

    \100\ Comments of Frank Ledoux on behalf of Lafayette Utilities 
System, Regional ISO Conference (New Orleans), Transcript at 180.

---------------------------------------------------------------------------
    A representative of a Wisconsin public utility told us:

    Administration of the tariff entails a myriad of decisions that 
require discretion, as well as ``technical'' judgments (like 
[available transmission capability] and [capacity benefit margin]) 
that have significant competitive ramifications. It is inevitable 
that these decisions and judgments will be made with competitive 
concerns in mind. Functional separation does not solve this 
problem.101

    \101\ Statement of Roy Thilly on behalf of Wisconsin Public 
Power, Inc. at 2, Docket No. PL98-5-000 (filed April 15, 1998).

Similarly, at our regional ISO conference in Indianapolis, we were 
---------------------------------------------------------------------------
told:

    In a capital intensive industry where a high percentage of the 
investment is in generation assets, it is inconceivable that a 
utility, which in some cases has very high generation cost, would 
somehow manage its transmission system so as not to give its 
generation a competitive advantage. I think this is self-
evident.102

    \102\ Comments of Kenneth Hegemann on behalf of American 
Municipal Power, Ohio, Regional ISO Conference (Indianapolis), 
Transcript at 174.
---------------------------------------------------------------------------

While it should not be assumed that such problems exist in every 
circumstance, clearly many market participants do not believe the 
market can yet be trusted with respect to their commercial interests, 
at least in some areas. We now turn to some of the areas that have 
produced the most complaints about continuing discrimination.
a. Calculation and Posting of Available Transmission Capability in a 
Manner Favorable to the Transmission Provider
    Perhaps the most significant complaint with respect to alleged 
discriminatory conduct under functional unbundling concerns the 
important function of calculating and posting the amount of 
transmission capability that is available on a transmission provider's 
system. The transmission provider is required to calculate and post on 
its OASIS the TTC and ATC for each posted transmission 
path.103 ATC is the capacity that is stated to be available 
for transmission service requests. As we discussed above in Section 
III.A.1, it is not possible to calculate accurately the transmission 
capability of one system without knowing the flows scheduled by all 
other interconnected transmission providers in the region. Given this 
technical problem, it may be impossible to distinguish an inaccurate 
ATC presented in good faith from an inaccurate ATC presented for the 
purpose of favoring the transmission provider's marketing interests.
---------------------------------------------------------------------------

    \103\ See 18 CFR 37.6(b) (1998).
---------------------------------------------------------------------------

    Transmission providers with power marketing interests have 
incentives to understate ATC on those paths valuable to its marketing 
competitors, or to divert transmission capacity so that it is available 
for use by its own marketing interests. If there is insufficient ATC, 
competitors may be forced to forego power sale transactions or use a 
less desirable alternative path if one is available.
    The Commission has found violations of ATC postings in three cases. 
In Washington Water Power Company,104 the transmission 
owning utility showed that it had no firm ATC, which would have 
discouraged any potential marketers who needed firm transmission 
service to make a sale. However, the utility then offered its power 
marketing affiliate, Avista

[[Page 31404]]

Energy, an ``interruptible firm'' transmission service that was not 
available to competitors. As the Commission explained in finding a 
violation of Order No. 888:

    \104\ 83 FERC para. 61,097 (1998), further order, 83 FERC para. 
61,282 (1998).
---------------------------------------------------------------------------

    Avista received a preference from Washington Water Power that 
was not available to any of its competitors. Simply stated, Avista's 
customer was deprived of the benefit of choosing among all potential 
power suppliers.

    The case of Wisconsin Public Power Inc. SYSTEM v. Wisconsin Public 
Service Corporation, et al. (Wisconsin Public) 105 
demonstrates both the difficulties and suspicions of discrimination 
resulting from when a transmission customer requests transmission 
service from an integrated utility. WPPI was seeking additional network 
transmission service from both Wisconsin Public Service Corporation 
(WPSC) and Wisconsin Power & Light Company (WP&L). In both cases, the 
requests were denied because of claims that the transmission owners 
were using all available capacity. In the case of WPSC, the Commission 
initially found that the utility had not properly reserved capacity for 
its merchant function and directed that it recompute its ATC without 
that reservation. After WPSC submitted additional documentation, the 
Commission accepted some of WPSC's merchant priority, but still found 
that it had violated its obligations under its tariff, and that its 
actions raised serious concerns about the functional separation of its 
staff. With respect to WP&L, the Commission found that it provided 
unduly preferential treatment to its merchant function, had been 
changing its ATC without posting those changes on OASIS, and had been 
computing ATC where none exists.106
---------------------------------------------------------------------------

    \105\ 83 FERC para. 61,198 (1998), order on reh'g, 84 FERC para. 
61,120 (1998).
    \106\ 83 FERC at 61,860.
---------------------------------------------------------------------------

    The Wisconsin Public cases demonstrate, if nothing else, the 
difficulty of achieving, and enforcing, functional separation of a 
utility's transmission and merchant functions. These types of cases 
require substantial Commission investigative and adjudicative 
resources, not to mention the resources of the parties involved. The 
Commission recognized in Wisconsin Public how RTOs could help eliminate 
these problems. The Commission stated:

    As we recently explained in Louisville Gas & Electric Company, 
et al., 82 FERC para. 61,308 at 62,222 & n. 39 (1998), a properly 
structured ISO, or other transmission entity can eliminate the 
potential for the strategic use of a transmission owner's priority 
to use internal system capacity for native load. The ISO or other 
transmission entity can also eliminate the incentive to engage in 
strategic curtailments of generation that a transmission operator's 
generation service competitors own and can remove any incentive to 
game OASIS operations. This will promote generation entry and 
competition, since a properly structured ISO or other transmission 
entity would have no economic stake in favoring certain market 
participants over others and potential entrants would likely see the 
transmission market as fair. An ISO, therefore, could help to solve 
the problems established in the instant complaints.107

    \107\ Id. at 61,859.
---------------------------------------------------------------------------

    The case of Morgan Stanley Capital Group v. Illinois Power Company 
108 also demonstrated problems associated with ATC and a 
transmission provider's use of its system for its own purposes. Morgan 
Stanley complained that Illinois Power failed to accurately post ATC, 
failed to award transmission capacity in a non-discriminatory manner, 
and allocated transmission in favor of its own bulk power marketing 
arm. Illinois Power admitted the ATC posting error, and the Commission 
found other violations of its tariff in responding to Morgan Stanley's 
request for service. Although the Commission initially also found that 
Illinois Power did not designate its own network resources in the same 
manner as network customers are required to designate them, Illinois 
Power disputed this, and after showing that its network resource was 
legitimate, the Commission dismissed its rehearing as moot. 
Nevertheless, this case demonstrates that a combination of ATC errors 
and unclear procedures feeds the mistrust in the marketplace with 
respect to a transmission owner's ability to use its system to favor 
itself.
---------------------------------------------------------------------------

    \108\ 83 FERC para. 61,204, order granting clarification and 
dismissing reh'g, 83 FERC para. 61,299 (1998).
---------------------------------------------------------------------------

    We also have currently pending before us several formal complaints 
alleging that a transmission provider is improperly keeping its 
transmission capability for its merchant function. In one case, a power 
marketer asserts that a transmission provider has refused service over 
an interconnection on the basis that the transmission provider needs 
all the ATC for native load. The marketer has alleged that the 
transmission provider's claims of reliability concerns are a mask to 
block competitors from importing power into the transmission provider's 
system when the transmission provider has higher cost generation 
available.109 In another recent formal complaint filing, it 
is alleged that a transmission provider denied transmission service and 
then improperly provided it to its merchant group.110
---------------------------------------------------------------------------

    \109\ Aquila Power Corporation v. Entergy Services, Inc., Docket 
No. EL98-36-000, Amended and Restated Complaint at 6 (filed June 23, 
1998).
    \110\ Arizona Public Service Company v. Idaho Power Company, 
Docket No. EL99-44-000 (filed March 3, 1999).
---------------------------------------------------------------------------

    Aside from these cases involving formal complaints, there have been 
a number of other complaints with respect to ATC calculation. For 
example, our enforcement staff receives hotline complaints concerning 
ATC posting problems. The enforcement staff has confirmed a number of 
such ATC errors. In most cases, these errors were corrected within 
several months of having them pointed out, and the utilities often 
offered explanations based on hardware or software problems. We make no 
judgment whether such identified errors were an intentional attempt to 
thwart competition; however, they had the potential to have that 
effect.
    In July 1997, the Commission held a technical conference concerning 
how well the OASIS system was working. Several commenters suggested 
that erroneous ATC calculation and posting was hurting competition. A 
representative from Electric Clearinghouse told us that there is a 
pervasive problem of incorrect or stale information on the OASIS sites, 
and that ``competition is blocked when this occurs.'' That same 
representative stated that very little firm ATC is offered due to the 
utility's caution or strategy, and that some providers will not offer 
firm ATC because they do not want to curtail their own 
transactions.111 At the same conference, a representative 
from the American Public Power Association told us:

    \111\  Open Access Same Time Information Technical Conference, 
Docket No. RM95-9-003 (July 18, 1997), transcript at 23.
---------------------------------------------------------------------------

    ATC is often understated and inconsistently posted on adjacent 
OASIS nodes. Inter-regional coordination is lacking. This fact 
limits the usefulness of the system for commercial 
purposes.112

    \112\ Id. at 28.
---------------------------------------------------------------------------

    In March 1998, a group referring to themselves as power industry 
stakeholders 113 filed a petition for rulemaking on electric 
power industry structure.114 Although we are not addressing 
here the specific relief they are requesting in that Petition, the

[[Page 31405]]

Petition does contain a number of fairly specific allegations 
---------------------------------------------------------------------------
indicating problems in the market. For example, the Petition asserts:

    \113\ The group consists of a number of power marketers and 
users, including, for example, Coalition for a Competitive Electric 
Market, ELCON, Electric Clearinghouse, Inc., and Enron Power 
Marketing, Inc.
    \114\ Petition for a Rulemaking on Electric Power Industry 
Structure and Commercial Practices and Motion to Clarify or 
Reconsider Certain Open-Access Commercial Practices, Docket No. 
RM98-5-000.
---------------------------------------------------------------------------

    Concepts such as ATC and the OASIS have become vehicles for 
obstructing and curtailing, rather than accommodating, transactions. 
Incumbents are able to deny new entrants access to critical, 
accurate information across control areas. This can take the form of 
out-of-date or incorrect postings of ATC or, in some instances, 
intentional withholding of actual ATC. Regardless of the cause, more 
transmission capability is physically available than is being 
released for sale.115

    \115\ Petition at 7-8.
---------------------------------------------------------------------------

    The Petition alleges the existence of ``ATC exclusions, 
inaccuracies and misuses that deny new entrants the ability to evaluate 
market opportunities, and therefore, prevent reasonable access to the 
grid.'' 116 The Petition cited specific instances of 
inconsistent ATC calculations for the same interconnection by the 
systems on either side; an OASIS showing ATC that was not in fact made 
available for scheduling; and an OASIS showing no ATC but the utility 
then using that path for a sale.117
---------------------------------------------------------------------------

    \116\ Id. at 15.
    \117\ Id. at Appendix D.
---------------------------------------------------------------------------

    EPSA, the trade association representing certain power suppliers, 
filed comments in support of the Petition and echoed many of the same 
experiences:

    EPSA agrees that this discriminatory conduct persists 
principally because of the continuing incentives and opportunity for 
transmission owning public utilities covertly to discriminate 
against other transmission customers, by, for example, minimizing 
reported available transmission capability (ATC), delaying or 
inaccurately posting ATC on the OASIS, or otherwise manipulating 
market operations.118

    \118\ EPSA Comments, Docket No. RM98-5-000, at 2 (filed 
September 21, 1998).
---------------------------------------------------------------------------

    EPSA further stated that, ``The manipulation of ATC--whether with 
the intent to deceive or as the result of poor OASIS management--is a 
serious entrance barrier for competitive power suppliers.'' 
119
---------------------------------------------------------------------------

    \119\ Id. at 8.
---------------------------------------------------------------------------

    At our regional ISO conference in New Orleans, we were told by a 
representative from the Public Service Commission of Yazoo City, 
Mississippi, of a specific instance of what it considered to be 
discriminatory treatment:

    Yazoo City, as a participant, has experienced first hand an 
individual [transmission] owner's continued ability to use its 
ownership and control [of] transmission to disadvantage competitors, 
notwithstanding Order 888's mandate of non-discriminatory 
transmission access.

    The representative then went on to describe an instance where a 
marketer could not complete a 10 MW power sale because of transmission 
restrictions, but then the transmission provider offered to supply the 
capacity itself.120 The representative concluded that Orders 
Nos. 888 and 889 have not fully eliminated undue discrimination and 
this will not be achieved ``as long as transmission owners are allowed 
to fence in transmission-dependent utilities and others located on 
their transmission system to enhance the value of their generation 
assets at increased cost to competitors.''
---------------------------------------------------------------------------

    \120\ Comments of Rebert D. Priest on behalf of the Public 
Service Commission of Yazoo City, Regional ISO Conference (New 
Orleans), Transcript at 201-03. After hearing this assertion, 
Entergy Services, Inc. filed a letter in which it stated that it was 
unable to identify any Entergy-imposed restrictions that would have 
prevented the power purchase. See Letter in Docket No. PL98-5-000 
(filed July 1, 1998).
---------------------------------------------------------------------------

    One specific area where there have been allegations that 
transmission owners are using ATC to favor their own merchant 
operations concerns the calculation and use of Capacity Benefit Margin 
(CBM). Although there is no single accepted definition, CBM is 
generally used to mean an amount of transmission transfer capability 
reserved by load serving entities to ensure access to generation from 
interconnected systems to meet their generation reliability 
requirements.121 Some utilities subtract CBM from their 
total transmission capability to arrive at ATC. There is no uniform 
method for calculating CBM. The ability to withhold CBM to ensure 
reliability not only confers a reliability advantage for the 
transmission provider, but may give the transmission provider the 
opportunity to selectively withhold ATC over paths and interconnections 
useful to its generation competitors.
---------------------------------------------------------------------------

    \121\ NERC, Available Transfer Capability Definitions and 
Determinations (June 1996), at 14.
---------------------------------------------------------------------------

    The use of CBM is an issue that is currently being considered in 
several cases pending before the Commission.122 For example, 
with respect to the formation of the PJM ISO, the Commission noted that 
it was not demonstrated that the PJM Pool's historical practice of 
withholding firm transmission interface capacity as a substitute for 
installed generating reserves is consistent with our open access 
policies. The Commission observed that the load serving entities that 
own generating capacity within the PJM control area appeared to benefit 
from this practice as suppliers in addition to benefitting as load 
serving entities.123 The Commission set the issue for 
further briefing and it remains pending. In another pending proceeding 
concerning WPSC's CBM calculation, two of the parties assert that CBM 
``removes firm transmission capacity from open access offerings, 
thereby raising an unnecessary and unjustifiable barrier to 
competition,'' and ``fosters discrimination by giving merchant 
functions gatekeeping control over CBM-related transmission access and 
by giving individual interface transmission owners broad discretion 
over where and how much CBM is withdrawn from ATC.'' 124 In 
the same proceeding, Electric Clearinghouse, Inc. asserts that ``the 
CBM set-aside embodies undue discrimination in access to the monopoly 
owned transmission wires because it ensures certain users a priority 
over the reserved transmission interface capacity to the exclusion of 
other firm transmission users.'' 125
---------------------------------------------------------------------------

    \122\ The Commission recently noticed a technical conference, to 
be held May 20 and 21, 1999, on the issue of CBM. See Capacity 
Benefit Margin in Computing Available Transmission Capacity, Notice 
of Technical Conference, Docket No. EL99-46-000.
    \123\ PJM, 81 FERC at 62,277.
    \124\ Protest of Madison Gas & Electric Company and Wisconsin 
Public Power Inc., Docket No. EL98-2-003 at 3 (filed August 21, 
1998).
    \125\ Protest of Electric Clearinghouse, Inc., Docket No. EL98-
2-003, at 3 (filed Ausust 21, 1998).
---------------------------------------------------------------------------

    As we stated above, we fully recognize that these are assertions 
made in pending cases in which we have not yet made findings. They are 
referenced here as illustrative of the suspicions in the industry of 
continuing opportunities for discriminatory treatment that may 
disadvantage certain competitors where generation owners continue to 
operate transmission.
b. Standards of Conduct Violations
    To ensure the functional separation of a transmission provider's 
transmission and merchant functions, the Commission adopted standards 
of conduct that prohibit the transmission provider's marketing interest 
employees from having any more access to transmission system 
information than is available on OASIS, and requires the transmission 
provider's transmission employees to provide impartial service to all 
transmission customers.126 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 marketing 
competitors.
---------------------------------------------------------------------------

    \126\ See 18 CFR Part 37 (1998).
---------------------------------------------------------------------------

    In spite of the standards of conduct, there continues to be a 
perception by

[[Page 31406]]

many market participants that the transmission provider's marketing and 
transmission interests are not fully functionally separated. 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.127 In 
addition, our enforcement staff receives numerous telephone calls about 
standards of conduct issues; some of these are simply questions about 
what is permissible conduct, but others are complaints of a violation. 
In a number of cases, our staff has verified non-compliance with the 
standards of conduct.128
---------------------------------------------------------------------------

    \127\ See Wisconsin Public, 83 FERC at 61,855, 61,860 (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, 83 FERC 
at 61,463 (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).
    \128\ 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 for a public utility to tell an affiliate to look for a 
marketing offer prior to posting the offer publicly).
---------------------------------------------------------------------------

    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.'' 129 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.
---------------------------------------------------------------------------

    \129\ Petition at 15.
---------------------------------------------------------------------------

    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. The use of 
standards of conduct is not the optimal procedure for ensuring a fair 
marketplace, and may be unnecessary in a properly structured and 
operated market.
    We are increasingly concerned about the extensive regulatory 
oversight and administrative burdens that have resulted from policing 
compliance with standards of conduct. We have discussed above some of 
the cases in which the Commission had to address potential violations 
of the standards of conduct. In addition, transmission providers were 
required to file their standards of conduct for Commission review. In 
response, the Commission initially issued 8 orders concerning 126 
public utilities' standards of conduct.130 Generally, these 
orders required the utilities to revise their standards of conduct and 
post, on the OASIS, organizational charts and job descriptions for 
transmission/reliability and wholesale merchant function employees. The 
Commission subsequently issued 13 more orders requiring the public 
utilities to further revise their standards of conduct and/or 
organizational charts and job descriptions.131 The 
Commission has also issued three orders on rehearing of the standards 
of conduct orders.132
---------------------------------------------------------------------------

    \130\ The citations for these orders are: 81 FERC para. 61,332 
(1997), 81 FERC para. 61,338 (1997), 81 FERC para. 61,339 (1997), 82 
FERC para. 61,028 (1998), 82 FERC para. 61,073 (1998), 82 FERC para. 
61,132 (1998), 82 FERC para. 61,193 (1998) and 82 FERC para. 61,246 
(1998).
    \131\ The citations for these orders are: 84 FERC para. 61,131 
(1998), 84 FERC para. 61,255 (1998), 84 FERC para. 61,320 (1998), 84 
FERC para. 61,327 (1998), 85 FERC para. 61,068 (1998), 85 FERC para. 
61,145 (1998), 85 FERC para. 61,227 (1998), 85 FERC para. 61,390 
(1998), 86 FERC para. 61,044 (1999), 86 FERC para. 61,079 (1999), 86 
FERC para. 61,146 (1999), 86 FERC para. 61,185 (1999) and 86 FERC 
para. 61,246
    \132\ The citations for these orders are: 82 FERC para. 61,131 
(1998), 83 FERC para. 61,357 (1998), and 85 FERC para. 61,382 
(1998).
---------------------------------------------------------------------------

    As of April 1, 1999, 51 utilities' standards of conduct and 
organizational charts and job descriptions have been accepted and 75 
utilities' standards of conduct and/or organizational charts and job 
descriptions have not been accepted and are pending review. This is an 
indication of the significant regulatory effort required by both public 
utilities and the Commission to make the standards of conduct approach 
workable--a regulatory effort that could be greatly reduced through 
more distinct organizational separation.
c. Line Loading Relief and Congestion Management
    A number of complaints have been made alleging that transmission 
providers are acting in a discriminatory manner in implementing line 
loading relief, which is required when a transmission line is in danger 
of being overloaded. Such complaints allege that the transmission 
providers are not providing redispatch service, are favoring their own 
transactions, and are failing to follow curtailment priorities 
established in Order No. 888.133 All of these actions by 
transmission providers may provide subtle competitive advantages in 
wholesale markets. For example, for those purchasers for whom service 
reliability is particularly important, purchasing power from a 
transmission provider may be viewed as offering enhanced reliability.
---------------------------------------------------------------------------

    \133\ We set for evidentiary hearing a formal complaint by 
Wisconsin Electric Power Company making these types of allegations. 
Wisconsin Electric Power Company v. Northern States Power Company 
(Minnesota) and Northern States Power Company (Wisconsin), 86 FERC 
para. 61,121 (1999). The parties subsequently filed a settlement 
agreement.
---------------------------------------------------------------------------

    Like the issue of calculating ATC, the fact that curtailment of 
service in times of congestion is in the control of the transmission 
provider, who also has power transactions on the affected transmission 
lines, leads to suspicions of discriminatory behavior that are 
difficult to verify. For example, a representative of Blue Ridge Power 
Agency told us at one of our ISO conferences:

    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. 134

    \134\ Regional ISO Conference (Richmond), Transcript at 20.

    Likewise, we were told at another ISO conference that operators 
with reliability responsibility possess actual controlling authority 
over transactions, ``thereby giving them a tremendous advantage over 
competitors.'' 135
---------------------------------------------------------------------------

    \135\ Comments of Marvin Carraway on behalf of Clarksdale Public 
Utilities Commission, Regional ISO Conference (Kansas City), 
Transcript at 107.
---------------------------------------------------------------------------

d. OASIS Sites That Are Difficult To Use
    Aside from the problems alleged with respect to posting inaccurate 
ATC calculations on OASIS sites, there have been complaints that some 
transmission providers have implemented their OASIS sites as a tool to 
impede competition rather than as it was intended--as a tool to foster 
competition. It has been alleged that transmission providers have no 
incentive to make the sites easier to use, because it is primarily the 
transmission providers' marketing competitors who would benefit from 
better OASIS sites. 136 The petitioners in Docket No. RM98-
5-000 asserted:

    \136\ See, e.g., Comments of representative from Enron Power 
Marketing speaking at Commission's July 1997 OASIS Technical 
Conference, transcript at 43-44.

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

[[Page 31407]]

    Indeed, to gain a competitive advantage over those who are 
dependent on the timeliness and accuracy of OASIS, vertically 
integrated transmission owners have an incentive to make OASIS as 
slow and uninformative as possible.137
---------------------------------------------------------------------------

    \137\ Petition at 37.
---------------------------------------------------------------------------

    Similarly, EPSA has told us that ``the present transmission regime 
gives existing transmission-distribution utilities an inherent 
advantage to reserve capacity for their own native load use, and 
provides them with no incentive to maintain a properly functioning 
OASIS.'' 138
---------------------------------------------------------------------------

    \138\ EPSA Comments, Docket No. RM98-5-000. at 8 (filed 
September 21, 1998).
---------------------------------------------------------------------------

    As we stated above with respect to ATC calculation, we are not in a 
position to make a judgment that transmission providers are 
deliberately making their OASIS sites difficult to use in order to 
disadvantage marketing competitors. In fact, we are aware that some 
OASIS sites are well run and engender few complaints from users, and 
that there may be legitimate technical and transitional difficulties 
responsible for some of the problems complained of. However, this is 
another example of the situation where market participants perceive 
discriminatory intent, whether or not one exists, because of the 
apparent opportunity and incentive to discriminate.
e. Other Issues Related to Functional Unbundling and Dealing With 
Remaining Undue Discrimination
    While the Commission here has not attempted to provide an 
exhaustive compilation of the remaining opportunities for 
discriminatory practices by transmission operators who are also in the 
power business,139 it believes 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. 
We invite public comments on the extent to which there remains undue 
discrimination in transmission services, and if it remains, in what 
forms. Those comments should address both the areas of alleged 
discrimination we have discussed above, as well as any other areas that 
commenters may have experienced. In addition, we are asking for 
comments about what remedies we should impose in an effort to eliminate 
any remaining discriminatory conduct. For example, should we require 
mandatory participation in an RTO, or are there other possible 
remedies? Could a performance-based rate system be designed to realign 
economic interests to remove the motive for discrimination?
---------------------------------------------------------------------------

    \139\ There have been other violations alleged. For example, 
many relate to pricing and discounting.
---------------------------------------------------------------------------

    One thing that seems apparent is that 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. This kind of regulation goes beyond traditional price 
regulation and forces us to regulate very detailed aspects of internal 
company policy and communication. For functional unbundling to be 
successful, we have to be concerned, in some sense, about ``who spoke 
to whom'' in the company cafeteria. Functional unbundling does not 
necessarily promote light-handed regulation. It also undoubtedly 
imposes a cost on those entities that have to comply with the standards 
of conduct who face additional training and rules that create 
rigidities in their internal management activities.
    It appears, based upon our experience thus far, that no matter how 
detailed the standards of conduct and how intensive our enforcement, 
competitors will continue to be suspicious that the wall between 
transmission operations and power sales is being breached in subtle and 
hard to detect ways. 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. It creates needless uncertainty 
and risk for new investments in generation.
    In section III.B below, we will address how the use of independent 
RTOs can 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.
B. Benefits That Regional Transmission Organizations Can Offer
    In the preceding sections, we have set forth what we consider to be 
at least some of the remaining transmission related impediments to full 
competition in the electricity markets. These impediments include 
engineering and economic inefficiencies in the operation and structure 
of the existing transmission grid that inhibit the development of 
broad-based markets for electric power, and remaining opportunities for 
discriminatory practices by transmission owners with power marketing 
interests.
    We now believe that the establishment of properly structured RTOs 
throughout the U.S. can effectively remove the remaining impediments to 
competition in the power markets. As discussed elsewhere in this NOPR, 
a properly structured RTO will be an entity that is independent from 
all generation and power marketing interests, and has the exclusive 
responsibility for grid operations, short-term reliability, and 
transmission service within a region. Such an entity would not only 
confer benefits related to removing impediments to competition, but 
would also enhance reliability and allow for less intrusive government 
regulation of transmission providers.
    We note that the Commission's recognition of the benefits of 
regional transmission organizations is not new. The Commission has 
encouraged the industry to create such institutions for more than six 
years. In 1993, the Commission issued a policy statement encouraging 
the formation of RTGs, which were defined as voluntary organizations of 
transmission owners, users, and other entities interested in 
coordinating transmission planning (and expansion), operation and use 
on a regional and inter-regional basis. 140 The Commission 
summarized the benefits of such entities as enabling the market for 
electric power to operate in a more competitive, and thus more 
efficient manner; providing coordinated regional planning of the 
transmission system to assure that system capabilities are adequate to 
meet system demands; decreasing the delays that are inherent in the 
regulatory process, resulting in a more market-responsive industry; and 
resolving technical transmission issues (e.g., loop 
flow).141
---------------------------------------------------------------------------

    \140\ Policy Statement Regarding Regional Transmission Groups, 
FERC Stats. & Regs. para. 30,976 at 30,870 and n.4 (1993) (RTG 
Policy Statement).
    \141\ RTG Policy Statement, FERC Stats. & Regs. at 30,871.
---------------------------------------------------------------------------

    One year later, the Commission issued a transmission pricing policy 
statement which encouraged RTGs to address transmission pricing and 
offered to provide more latitude to RTGs than to individual utilities 
for innovative pricing proposals, recognizing that issues such as loop 
flow required a regional approach.142 Then, two years after 
that in Order No. 888, the Commission encouraged the industry to 
consider ISOs, and gave specific guidance on characteristics and 
functions in the form of 11 principles.
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    \142\ Inquiry Concerning the Commission's Pricing Policy for 
Transmission Services Provided by Public Utilities Under the Federal 
Power Act, 59 FR 55031 (November 3, 1994), FERC Stats. & Regs., 
Regulations Preambles para. 31,005, at 31,140, 31,145 (Transmission 
Pricing Policy Statement.)

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[[Page 31408]]

    The Commission has not been alone in recognizing the benefits of 
RTOs. In fact, there is surprising unanimity about the benefits of 
regional transmission solutions to grid management. For example, the 
Edison Electric Institute adopted a resolution that ``recognizes the 
potential benefits of voluntary grid regionalization in addressing 
pancaked transmission rates, congestion management and reliability, 
transmission planning, and market power * * *'' and supported 
``flexible, voluntary, market-based approaches'' toward grid 
regionalization.143 The American Public Power Association 
has stated that ``mandating RTOs will prevent further inequities in the 
provision of wholesale transmission service, provide guidance to the 
states, advance regional solutions to reliability issues to head off 
future crisis situations such as the 1998 Midwest Price Spikes, and 
partially mitigate serious market power concerns that have arisen due 
to the high number of recent mergers in the electric utility 
industry.'' 144 The National Energy Marketers Association 
urges the Commission to ``take bold steps necessary to create larger 
regional transmission organizations (RTOs) and to force maximum 
participation into (sic) these organizations.'' 145 Other 
industry groups representing very different interests have reached 
similar conclusions.146
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    \143\ Edison Electric Institute, Resolution Regarding Grid 
Regionalization, adopted by the Board of Directors, January 7, 1999.
    \144\ Motion of American Public Power Association For Leave To 
Lodge, Docket No. RM99-2-000, filed March 17, 1999, at 2.
    \145\ NEA, ``National Guidelines For Restructuring The Electric 
Generation Transmission and Distribution Industries,'' January 1999, 
at 6.
    \146\ The Electric Power Supply Association recommends that 
``ISOs Must be Regional in Scope.'' (EPSA Position Statement on 
Independent System Operators, January 1997, at 1.) The Electricity 
Consumers Resource Council (ELCON) states that ``a competitive 
electricity marketplace requires the formation of large, regional 
independent system operators.'' (ELCON, ``Independent System 
Operators,'' Profiles On Electricity Issues, No. 18, March 1997, at 
2.
---------------------------------------------------------------------------

    States are also recognizing the need for regional approaches to 
grid operation. At least five states have passed laws or issued 
regulations requiring transmission owning utilities in their states to 
participate in regional transmission entities.147 Other 
state regulators have highly praised the new regional transmission 
entities that are functioning in their regions.148
---------------------------------------------------------------------------

    \147\ Laws to encourage participation in regional ISOs or 
transcos have been passed in Wisconsin, Illinois, Virginia, and 
Arkansas. Regulations to encourage this outcome have been issued by 
the Nevada commission.
    \148\ See, e.g., Comments of Commissioner Marlene Johnson, RTO 
Conference (District of Columbia), transcript at 23-24; Commissioner 
Gerald Thorpe (Maryland), transcript at 39-40; President Herbert 
Tate (New Jersey), transcript at 47-50; and Commissioner Nora Mead 
Brownell (Pennsylvania), transcript at 54.
---------------------------------------------------------------------------

    While these industry groups and state regulators may not agree on 
the form of such regional organizations and how aggressive the 
Commission should be in encouraging their development, they do 
generally agree that such entities would provide substantial benefits.
    We note, additionally, that this same conclusion has also been 
reached in other countries. In almost every country that has chosen to 
introduce competition in its power sector, a single regional or 
national grid management organization has or will be created as the 
necessary platform for achieving fair and efficient bulk power 
competition.149
---------------------------------------------------------------------------

    \149\ Government of Mexico, Secretaria de Energia, Policy 
proposal for structural reform of the Mexican electricity sector, 
1999; World Bank, Reforms and Private Participation in the Power 
Sector of Selected Latin American and Caribbean and Industrialized 
Countries, 1994; National Regulatory Research Institute, Electric 
Power industry Restructuring in Australia: Lessons From Down Under, 
Occasional Paper #20, Ohio State University, January 1997; World 
Bank (Industry and Energy Department), Central and Eastern Europe: 
Power Sector Reform in Selected Countries 1997; Ontario (Canada) 
Market Design Committee, The Fourth and Final Report, January, 1999; 
Alberta (Canada) Department of Energy, Moving To Competition, A 
Guide to Alberta's New Electricity Structure, 1994; Jan Moen, A 
Common Electricity Market in Norway and Sweden: Prerequisites, 
Development and Results So Far, Norwegian Water Resources and Energy 
Administration, May, 1996; National Grid Company, Grid System 
Management, Coventry, England; and J. Culy, E. Read and B. Wright, 
``The Evolution of New Zealand's Electricity Supply Structure,'' in 
International Comparisons of Electricity Regulation, Gilbert and 
Kahn, editors, Cambridge University Press, 1996.
---------------------------------------------------------------------------

    In the following discussion, we address the significant benefits of 
establishing RTOs.
1. An RTO Would Improve Efficiencies in the Management of the 
Transmission Grid
    As discussed in section III.A above, numerous inefficiencies in the 
current operation and structure of the transmission grid may be 
impeding full competition. Establishing RTOs could help remove most, if 
not all, of those inefficiencies in a number of ways.
    First, an RTO would improve efficiency through regional 
transmission pricing. The Commission has long recognized that 
transmission pricing reform is most effectively accomplished on a 
regional basis.150 An RTO would have the geographic scope 
needed to eliminate pancaked transmission rates within its region. This 
would broaden the generation market and could result in more potential 
suppliers and less concentrated generation markets, thereby fostering 
more competitive markets and lower prices to consumers.
---------------------------------------------------------------------------

    \150\ Transmission Pricing Policy Statement, FERC Stats. & Regs. 
at 31,145.
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    Second, regional scope would improve congestion management on the 
grid. An RTO would improve the way congestion is managed over a large 
area, thus expanding the number of potential transactions over existing 
facilities while reducing the number of curtailments.
    The scheduling of power by multiple utilities over a regional grid 
can lead to unexpected overloads on constrained facilities. This can be 
a serious barrier to competitive power trading because some power sale 
transactions may have to be curtailed. With a regional scope, an RTO 
would be better able to manage congestion. An RTO would be in a better 
position to prevent congestion or control it through application of 
appropriate regionwide congestion pricing to ration use of the grid if 
necessary. An RTO would also more readily identify schedules that could 
lead to congestion, and relieve congestion through regional redispatch 
authority. A pricing approach to capacity allocation would improve 
efficiency by ensuring that the most highly valued transactions remain 
on the grid and possibly result in less curtailment than under the 
present approach.
    Third, an RTO would improve efficiency by providing more accurate 
estimates of ATC than those currently provided by individual systems. 
Conditions on all parts of the regional grid affect ATC on individual 
utility systems. Factors such as load estimates, generation and 
transmission outages, generation dispatch orders and transactions on 
individual systems can affect the determination of ATC. An individual 
utility may not have complete or timely information regarding such 
factors and may apply assumptions and criteria in its ATC estimates 
that are different from those of neighboring transmission operators, 
leading to wide variations in ATC values for the same transmission 
path. The information needed may be considered confidential, and market 
participants would be more willing to share it with an independent 
body.
    An RTO would produce better ATC estimates because it would have 
access to complete regional usage information, would have current 
information because the RTO will be the security coordinator as well as 
the OASIS site administrator, and would calculate ATC values on a 
consistent region-wide basis using a regional flow model. An RTO would 
also resolve most, and perhaps all, of the complaints of inaccurate ATC

[[Page 31409]]

postings. Problems are likely to remain only to the extent that 
scheduling reservations across several RTOs continue to be made on a 
contract path basis.
    Fourth, an RTO also would more effectively manage parallel path 
flows. With an RTO in place, the geographic scope for scheduling and 
pricing transmission would be widened and parallel path flows would be 
internalized within the RTO. This should result in more accurate ATC 
calculations, improve reliability, and, with appropriate transmission 
pricing, eliminate or reduce disputes among transmission owners 
regarding uncompensated uses of facilities.
    Fifth, an RTO would promote more efficient planning for 
transmission or generation investments needed to increase transmission 
capacity. One advantage of an RTO that is helpful in planning is that 
it will be able to see the ``big picture.'' Planning and expansion of 
grid facilities will no longer be done on a piecemeal basis. An RTO 
would help identify the best place on the grid to locate new 
generation.151 An RTO also will have more options available 
to it because of its size and configuration. It has the potential to 
select and implement the most efficient investment or operating option 
within the region for relieving a bottleneck. This is in marked 
contrast to the current situation in many regions where individual 
transmission owners are generally limited to investment options in 
their particular service areas even though better (i.e., less costly) 
options may be available elsewhere in the region.
---------------------------------------------------------------------------

    \151\ One of the benefits of the ERCOT (Texas) ISO has been, due 
to the ISO's comprehensive view of the grid, the ability to identify 
the most effective spots on the grid to locate new generation 
facilities. See Chairman Patrick Wood (Texas), transcript at 205-06.
---------------------------------------------------------------------------

    Sixth, an RTO would increase coordination between separate state 
regulatory agencies by providing a single point of focus for 
transmission expansion review, possibly even encouraging multi-state 
agreements to review and approve new transmission 
facilities.152 As RTOs develop viable regional planning 
processes, there may be a growing willingness on the part of individual 
states to accommodate regional regulatory review on either a formal or 
informal basis.153
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    \152\ The Commission recognizes that there may be legal 
impediments to such a shift. For example, most state siting laws 
typically require that the proposed facility must be assessed in 
terms of its benefits for the state rather than the region. See 
Ileana Elsa Garcia, ``State Electric Facility Siting Practices,'' 
background paper prepared for the Harvard Electric Policy Group, 
April 10, 1997.
    \153\ To encourage this movement, we propose requiring that the 
RTO's planning and expansion process must '' accommodate efforts by 
state regulatory commissions to create multi-state agreements to 
review and approve new transmission facilities.'' See section III.E.
---------------------------------------------------------------------------

    Seventh, transactions costs would also be reduced with an RTO in 
place. For example, the consolidation of transmission control 
operations would cut general and administrative costs over the long 
term. In addition, an RTO would administer a single regional 
transmission tariff, thereby permitting ``one stop shopping'' for 
regional transmission service and resulting in simpler and more 
efficient procedures for transmission users to transmit power over 
greater distances.
    Eighth, through regional standardization of transmission services 
and the terms and conditions under which they are transacted, an RTO 
would facilitate establishing transmission rights and the 
``tradeability'' of transmission rights. The early experience suggests 
that independent regional transmission organizations are in the best 
position to establish well-defined rights to the use of the 
grid.154 Such rights are essential to establishing 
congestion markets. Clear rights are also needed for the ability to 
trade transmission rights between customers that place different values 
on capacity. Such trade helps ensure an efficient allocation of current 
capacity and helps ensure that new capacity is built only when and 
where necessary. 155
---------------------------------------------------------------------------

    \154\ See Central Hudson Gas & Electric Corporation, et al., 86 
FERC para. 61, 062 at 61, 228-33 (1999); PJM, 81 FERC at 62,240.
    \155\ Capacity Reservation Open-Access Transmission Tariffs, 
Notice of Proposed Rulemaking, 61 FR 21847 (May 10, 1996), FERC 
Stats. & Regs. para. 32, 519 (CRT NOPR).
---------------------------------------------------------------------------

    Ninth, an RTO would facilitate the success of state retail access 
programs by providing greater confidence in the markets and a larger 
regional market with access to more potential suppliers.
2. An RTO Would Improve Grid Reliability
    With the improved transmission access that has resulted from 
industry compliance with Order No. 888, the volume of wholesale 
electricity transactions has significantly increased along with the 
number of market participants. This has led to industry concerns that 
traditional reliability rules may not guarantee that the bulk power 
system remains secure. Many transmission owners in a region make 
independent decisions about use of a common regional transmission grid. 
A reliability problem on one utility's transmission system may threaten 
the reliability of its neighbor's system. A regional body that operates 
the regional grid and enforces reliability rules for the entire region 
could prove helpful to current efforts and should be considered. An RTO 
would enhance reliability by (1) operating the system for a large 
region, (2) ensuring coordination during system emergencies and 
restorations, (3) conducting comprehensive and objective reliability 
studies, (4) coordinating generation and transmission outage schedules, 
and (5) sharing of ancillary services responsibilities.
3. An RTO Would Remove Opportunities for Discriminatory Transmission 
Practices
    In an RTO, the control of transmission operation is cleanly 
separated 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 service.156 
Accordingly, ATC calculations can be made in an unquestionably 
objective manner, OASIS sites can be equally relied upon by all 
transmission users, and line loading relief should be free from 
preferences for certain market participants.
---------------------------------------------------------------------------

    \156\ Appropriate price regulation of RTOs would still be 
needed.
---------------------------------------------------------------------------

    In addition, the separation of transmission operation from power 
marketing activities also would reduce opportunities for intentional or 
inadvertent communication of commercially valuable information from the 
transmission provider to any market participant, and should eliminate 
any advantage that market participants may now have with respect to 
arranging transmission service with an affiliated transmission 
provider.
    Finally, removing the opportunity for discriminatory transmission 
practices will help ensure the openness and integrity of the commercial 
process. We have been told repeatedly of the importance of transparency 
and fairness in the relationship between transmission users and 
transmission providers. This was a prominent topic at our ISO 
conferences last year. Fairness, impartiality and market confidence are 
also important to reliability. If the operator orders certain actions 
to be taken for system reliability purposes that might harm the 
interests of some users, those users must know that the action being 
ordered has been made

[[Page 31410]]

fairly and with only technical factors in mind.
    One important benefit of an RTO is that it could help eliminate the 
suspicions about, or remaining actual discriminatory practices by, grid 
operators. The DOE Reliability Task Force concluded that regional 
reliability entities such as RTOs must be ``truly independent of 
commercial interests so that their reliability actions are--and are 
seen to be--unbiased and untainted * * *'' [emphasis added] 
157 The same conclusion was reached by the blue-ribbon 
Electric Reliability Panel convened by NERC to recommend reforms in the 
current U.S. reliability system. The panel concluded that: ``(t)o 
dispel suspicions that the system operator favors one participant over 
another * * *, the operator must be independent from market 
participants.'' 158
---------------------------------------------------------------------------

    \157\ See Secretary of Energy Advisory Board, U.S. Department of 
Energy, ``Maintaining Reliability in a Competitive U.S. Electricity 
Industry,'' September 29, 1998 at xv.
    \158\ Electric Reliability Panel of the North American 
Reliability Council, ``Reliable Power: Renewing the North American 
Electric Reliability Oversight System,'' December 1997, at 17.
---------------------------------------------------------------------------

4. An RTO Would Result in Improved Market Performance
    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 would also improve the performance of electricity markets in 
several ways and consequently lower prices to the Nation's electricity 
consumers.
    The RTO benefits discussed so far in this section would result in 
improving the competitiveness of wholesale electricity markets. To the 
extent that RTOs foster fully competitive wholesale markets, the 
incentives to operate generating plants efficiently are bolstered. 
Suppliers will continuously seek to avoid being made uncompetitive by 
rivals. We have now had close to two decades of experience with 
generating plants being operated in at least partially competitive 
markets. Non-traditional generators have had the opportunity to realize 
increased profits through reduced costs and improved operating 
performance. For years, the growing presence of independent power 
generators has led to highly efficient new capacity coming on line. 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 RTOs. Regions which 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. Availability of customers, and the presence of competing 
suppliers, are creating the incentives for better-performing plants. 
All plants are coming under pressure to improve their availabilities 
and operating efficiencies. Individual firms have made strategic 
decisions to seek to become more competitive, or to prepare themselves 
for future competition.159
---------------------------------------------------------------------------

    \159\ Examples include: Virginia Power, which has made more than 
$1 billion in capital improvements and other investments (without 
raising rates) between 1992 and 1998, including $921 million in 
generating plant and approximately $125 million in transmission line 
upgrades. See Virginia Power, Virginia Power Statement on SCC 
Report, May 24, 1998. This document is available on Virginia Power's 
website at http://www.vapower.com/news/archive/releases980324.html; 
Entergy, which has achieved high performance at its nuclear units in 
terms of capacity factors, outage times and refueling periods, See 
Entergy Operation Services, Inc., Entergy Nuclear Units Have 
Outstanding Year as Entergy Forges Ahead with National Nuclear 
Company, January 26, 1999, press release. This document is available 
on Entergy's website at http://www.entergy.com/news/1999/
nr012699.htm.; New York Power Authority, which has lowered operating 
and maintenance budgets, refinanced debt, and invested $181 million 
in capital improvements. See New York Power Authority, NYPA Exceeds 
Performance Goals in 1998, February 12, 1999, press release. This 
document is available on NYPA's website at http://www.nypa.gov/
press/0212a.htm.; Green Mountain Power, which reduced operations and 
maintenance expenditures by 50% between 1998 and 1995. See Green 
Mountain Power Corporation, Sales and Expenditures, 1995 Annual 
Report. This document is available on Green Mountain Power 
Corporation's website at http://www.gmpvt.com/annrpt95/salesex2.htm; 
and the Tennessee Valley Athority, which realized cost savings of 
22% on fossil-fueled and hydroelectric plant outage projects which 
were subject to a continuous improvement process. See Hans E. Picard 
and C. Robert Seay, Jr., Competitive Advantage Through Continous 
Outage Improvement, Electric Power Research Institute Fossil Plant 
Maintenance Conference, July 29, 1996. This document is avialable at 
website http://www.iac.net/pconsult/epri.html..
---------------------------------------------------------------------------

    By improving competition, RTOs will also 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.160 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 smoother matching of buyers and sellers.
---------------------------------------------------------------------------

    \160\ Evidence from the UK and strategic behavior studies, 
however, indicates that such market power can lead to ongoing cost 
impacts as well as outright efficiency losses. See Richard Green and 
David Newbery, Competition in the British Electricity Spot Market, 
100 J. POL. ECON., 929, 1992.
---------------------------------------------------------------------------

    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 long enough track record with existing 
institutions with which to measure. The Commission will estimate the 
potential cost savings from RTOs as part of its National Environmental 
Protection Act analysis. At this time, we foresee several billion 
dollars annually in efficiency gains to the economy.161
---------------------------------------------------------------------------

    \161\ The benefits are likely to come substantially from lower 
generation operation and maintenance costs that result from new 
plants, improved performance of existing plants, and improved 
congestion management.
---------------------------------------------------------------------------

    The Commission seeks comment on the effect of RTOs on electricity 
market performance, including any data or other information that could 
shed light on quantifying the extent of those benefits.
5. An RTO Would Facilitate Lighter-Handed Governmental Regulation
    There are several ways 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.
    A number of regulatory benefits depend critically on the RTO being 
truly independent of power marketing interests. For example, to the 
extent an RTO is independent of power marketing interests, there would 
be no need for this Commission to monitor and attempt to enforce 
compliance with the standards of conduct designed to unbundle a 
utility's transmission and generation functions.
    An independent RTO with an impartial dispute resolution mechanism 
would resolve disputes without resort to the Commission complaint 
process. The Commission has demonstrated its willingness to defer to 
such mechanisms.162 It is generally more efficient for these 
organizations to resolve many disputes internally rather than bringing 
every dispute to the Commission. We seek comment on what types of 
disputes or other matters would be appropriate for the Commission to 
defer to the decisions of the RTO? In granting deference to decisions 
that result from an acceptable ADR process,

[[Page 31411]]

would there be a need to distinguish between RTOs that are ISOs and 
RTOs that are transcos?
---------------------------------------------------------------------------

    \162\ See PJM, 81 FERC at 62,269.
---------------------------------------------------------------------------

    The Commission could also consider adopting streamlined filing and 
approval procedures. The Commission could consider different filing 
requirements for established RTOS. For example, should we lower the 
threshold for the types of changes to operations or practices that 
would not require a filing with the Commission? Should such a policy be 
applied equally for non-profit and for-profit RTOs?
    Another regulatory benefit is that an RTO could result in more 
streamlined transmission rate proceedings. The Commission has indicated 
its willingness to grant more latitude to transmission pricing 
proposals from appropriately constituted regional groups, and RTOs 
would be such groups.163
---------------------------------------------------------------------------

    \163\ See Transmission Pricing Policy Statement, FERC Stats. & 
Regs. at 31,145, 31,148.
---------------------------------------------------------------------------

    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 utility merger decision making process.
6. Conclusion
    The Commission believes that the widespread formation of RTOs can 
provide substantial benefits. The Commission invites comment on the 
benefits of RTOs and the magnitude of these benefits.

C. Concerns Expressed by the State Commissions

    Our Notice of Intent to Consult with State Commissions in this 
proceeding initiated our commitment to take into account the advice and 
concerns of the states in formulating an RTO policy. Through written 
and oral comments made during the consultations in February 1999, and 
in response to a series of follow-up questions, state commissioners 
raised a number of concerns regarding RTO policy. The Commission 
appreciates the state commissioners' serious consideration and their 
comments have helped shape our proposal. We take the opportunity to 
summarize the principal concerns and how our proposal addresses those 
concerns.
1. Federal Mandate
    Most states oppose a FERC mandate to form RTOs.164 The 
proposed rule would not generically require public utilities to 
transfer control of their transmission facilities to an RTO; however, 
we do seek comment on the issue. We are proposing to provide the 
impetus needed to help form RTOs by engaging the industry and the 
states in a national dialogue regarding RTO characteristics, setting 
minimum characteristics and functions for RTOs, providing flexibility 
for innovative transmission rate proposals, including a willingness to 
consider incentive pricing proposals, and establishing regional 
processes with Commission staff participation after a Final Rule is 
issued for fostering RTO formation. Thus, the proposed rule stops short 
of generically ordering utilities into RTOs but instead, as WUTC 
expresses it, we are at this time adopting: `` * * * a policy of 
encouraging voluntary RTO participation and filings * * * '' 
165 The Commission is, however, concerned that the current 
transmission grid management framework may be preventing electricity 
markets from reaching their full competitive potential. We will 
evaluate the comments received in response to our proposals to 
determine if additional action is needed.
---------------------------------------------------------------------------

    \164\ See, e.g, Comments in Docket No. RM99-2-000 of North 
Carolina Utilities Commission (NCUC) at 1; Washington Utilities and 
Transportation Commission at (WUTC) at 4; Georgia Public Service 
Commission (GPSC) at 10; Mississippi Public Service Commission 
(MPSC) at 3; and South Carolina Public Service Commission (SCPSC) at 
1.
    \165\ WUTC at 4-5.
---------------------------------------------------------------------------

2. Regional Flexibility
    At all three consultations with the state commissions and in 
written comments, we were urged by almost every state commission not to 
impose a ``one size fits all'' approach to RTO design.166 
The vast majority of the respondents to the Commission's follow-up 
questions were unwilling to designate a particular type of RTO 
organization as superior in all cases. The Commission agrees and does 
not propose to establish a mandatory national template for RTOs. Such a 
policy would be ill advised at this time. Neither this Commission, nor, 
we suspect, anyone else in the industry knows now what is the best 
combination of ownership and control to achieve an optimal RTO. Given 
the lack of experience to date, the Commission believes that the best 
policy is to encourage regional experimentation. Thus, as discussed 
below, the proposed rule would establish only minimum characteristics 
and functions needed for Commission approval as an appropriate RTO. We 
also propose to initiate collaborative regional processes in which each 
region would be encouraged to design an RTO that best meets its needs. 
This collaborative process is discussed below.
---------------------------------------------------------------------------

    \166\ See, e.g., comments of Florida Public Service Commission 
(FPSC) at 3.
---------------------------------------------------------------------------

    Our proposed policy of regional flexibility should also help some 
states' concerns with the cost of an RTO. As discussed above, we 
believe RTO development will result in substantial benefits for the 
Nation. However, some states are concerned that the costs of an RTO 
will exceed its benefits. The cost of meeting the minimum RTO 
characteristics need not be large, but it is not always easy to measure 
the long-term RTO benefits that would offset these costs. By permitting 
regional flexibility, subject to our minimum characteristics and 
functions, the proposed rule allows each region to design an RTO that 
has costs commensurate with the regional benefits expected.
3. Retail Markets
    States that have not adopted a retail access policy are concerned 
that an RTO in their state might interfere with their prerogatives 
regarding adopting, or not adopting, retail access. The comments and 
responses of some state commissions reiterate the concern that RTO 
formation will lead to retail access where it does not yet 
exist.167 The proposed rule does not require retail access. 
The Commission agrees with FPSC that, ``FERC should not pursue any 
policy that would interfere with or contravene a state's authority to 
adopt or refrain from adopting direct retail access.'' 168 
Having an RTO in a state does nothing to interfere with the state's 
authority to decide retail access policy. Some states whose utilities 
are in RTOs can have retail access while others can choose not to have 
retail access. This is demonstrated today by the presence of ISOs in 
the Middle Atlantic and New England regions, but not all of the states 
in those regions have yet adopted retail competition. Some states with 
retail access believe that an RTO is needed to support their customer 
choice plan because the RTO allows customers, aggregators and marketers 
to reach supplies over a larger area. Those states that do not have 
retail access can nevertheless benefit from an RTO as their utilities 
enjoy the benefits of the RTO to lower native load generation rates by 
buying and selling power over a larger market area.
---------------------------------------------------------------------------

    \167\ See, e.g. response of Kentucky Public Service Commission 
(KPSC) at 1.
    \168\ FPSC comments at 4.
---------------------------------------------------------------------------

    Some states are also concerned that having a Commission-regulated 
RTO provide transmission service for retail

[[Page 31412]]

customers would lead to some loss of control over retail market 
services, such as the ability to assure reliability. A primary purpose 
of an RTO is to ensure transmission reliability. Whether there is any 
decrease in state control over any aspects of retail market services 
would depend on the design of the particular RTO. Under any RTO design, 
the states would retain full control over the generation adequacy of 
franchised power suppliers, transmission siting and local distribution 
reliability. Further, the proposed rule would encourage state 
involvement both in RTO design and ongoing oversight, providing states 
a vehicle to protect all aspects of transmission reliability on behalf 
of retail customers.
4. Effect on States with Low Cost Generation
    States with relatively low cost power are concerned that an RTO 
would result in local utilities selling their low cost power to other 
states. However, the vast majority of the respondents to a follow-up 
question on this issue stated that this is not a likely 
problem.169 Similarly, we do not believe RTOs will cause 
such a result. The presence or absence of retail access is the 
principal factor affecting potential out-of-state sales of low-cost 
power, and this is in the hands of state policy makers. Arguably, 
retail access could lead to low cost power being sold out of state if 
incumbent utilities no longer have an obligation to serve retail 
customers. However, this could happen with or without an RTO. Where 
there is no retail access, state authorities can continue to ensure 
that a utility with a monopoly franchise sells its lowest cost power to 
local native load, even if the utility's transmission is operated by an 
RTO. Indeed, an RTO could actually lower retail rates by expanding the 
market region for the utility to sell the higher cost power not sold to 
native load and sharing in the benefits of regionwide resource planning 
and congestion management.170 And finally, utilities that 
now have low cost generation will help assure access to future low cost 
generation plants by participating in an RTO. New low-cost generation 
plants are more likely to be attracted to regions with a well-
functioning regional market governed by an RTO.171 In other 
words, a state that is low-cost today may not be low-cost tomorrow 
without an RTO in its area.
---------------------------------------------------------------------------

    \169\ See, e.g., responses of Virginia State Corporation 
Commission (VSCC) at 1; WUTC comments at 2; Wisconsin Public Service 
Commission (WPSC) comments at 1; and Florida Public Service 
Commission (FPSC) comments at 1. But see, e.g., response of Alabama 
Public Service Commission (APSC) at 1, and response of District of 
Columbia Public Service Commission (DCPSC) at 1.
    \170\ See response of Indian Utility Regulatory Commission 
(IURC) at 1.
    \171\ According to data in a recent survey, about 64% of 
announced merchant power plants will be located in California, 
Texas, New York, New England, and the middle Atlantic area, while 
such states account for only about 30% of total electricity load in 
the U.S. See Announced Merchant Plants, survey prepared by the 
Electric Power Supply Association, Appril 13, 1999.
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    We seek comment from state commissions regarding how an RTO in 
their state would affect power costs.
5. Need for Independent Transmission Operation
    Many states believe that transmission operators should be 
structurally independent of other market participants. Responses to 
follow-up questions indicated that independence of the transmission 
operator is a basic assumption for an effective RTO.172 As 
the Pennsylvania Public Utility Commission (PaPUC) states, ``It is 
therefore the case that RTOs must have sufficient independence from 
direct control by any single entity or interest group to perform these 
functions well and honestly.'' 173 As discussed below, our 
proposed rule would require strict independence of transmission 
operation from market participants for approval of an RTO application.
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    \172\ See e.g., responses of KPSC at 2 and Missouri Public 
Service Commission (MoPSC) at 1.
    \173\ Supplemental comments at 7.
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6. Transmission Cost Shifting
    There is a concern by some states with utilities with relatively 
low cost transmission facilities that, by joining an RTO, their 
utilities' transmission costs will be averaged with the higher cost 
facilities of utilities in other states in determining RTO transmission 
rates.174 As a result, these states are concerned that 
joining an RTO will increase local transmission rates. This is known as 
transmission cost shifting. It has been an issue in every ISO the 
Commission has approved to date. That is why, in each of those ISO 
cases, we have allowed a transition period in which access fees are 
based on some form of ``license plate'' pricing: access fees are paid 
by load serving entities based on the fixed transmission costs of the 
local utility. As discussed below, we propose to continue and perhaps 
expand such flexibility in allowing the license plate approach or other 
approaches to recover current sunk transmission costs during a 
transition period.
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    \174\ See, e.g., comments of WUTC at 6.
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7. Boundary Drawing
    Many states expressed opposition to the Commission drawing regional 
or RTO boundaries in a rulemaking.175 The proposed rule does 
not set boundaries. Instead, we propose factors for assessing whether a 
proposed RTO's geographic configuration will ensure that the required 
RTO functions, such as assuring reliability, internalizing loop flow, 
managing congestion, and eliminating pancaked rates, are satisfied. In 
other words, we are proposing that the boundaries and other factors 
affecting scope and regional configuration will depend on the functions 
that an RTO performs. We note, however, that some RTO functions are 
likely to be carried out more effectively in a large region.
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    \175\ See, e.g., comments of NCUC at 1 and WUTC at 3.
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8. Regional Approach to Reliability
    Many states believe that regional operation of transmission is 
needed to assure the continued reliability of the transmission 
system.176 The proposed rule would require regional 
operation of transmission by an RTO with primary responsibility for 
short-term reliability as a condition for approval of an RTO 
application. This is discussed below.
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    \176\ See, e.g., comments of NCUC at 3.
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9. Pricing Reform
    Many states want regional approaches to transmission pricing 
reform. In particular, they would like to decrease the incidence of 
pancaked transmission rates. Our proposal is aimed at developing RTOs 
that would provide the forum and have the geographic scope for a 
regional approach to transmission pricing reform. The proposed rule 
would also permit flexibility for experimenting with innovative forms 
of congestion management, which would mean fewer TLR curtailments and 
more assurance that native load is served.
10. Participation of Public Power
    In some regions of the Nation, substantial portions of the 
transmission grid are owned by pubic agencies. The states in these 
regions have expressed a concern that our RTO initiative must address 
how to assure that such public agencies join the RTO. Some of the 
responses to follow-up questions reiterated the need to include public 
power agencies in any RTO formation.177
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    \177\ See, e.g., responses of Iowa Utilities Board (IUB) at 1 
and New Mexico Public Regulation Commission (NMPRC) at 1.
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    The proposed rule would not require RTO formation and so does not 
address

[[Page 31413]]

how to require public agency transmission owners to join RTOs. As 
suggested by KPSC,178 we will allow flexibility in RTO 
formation in order to meet, where possible, the requirements of public 
agencies. Nevertheless, the Commission's objective is to encourage the 
placement of all transmission facilities under the control of an RTO. 
In section III-G of this notice, we have requested comments on ways the 
Commission can facilitate public power participation in RTOs. We are 
also proposing regional processes to help facilitate RTO formation 
under section 202(a) of the Federal Power Act. Because section 202(a) 
applies to public power as well as public utilities, the regional 
processes will include publicly owned transmission entities.
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    \178\ Response at 1.
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11. State Role in RTO Governance
    States want a role in the governance of any RTOs for their states, 
and the Commission proposes to be as flexible as possible in 
accommodating their needs. The state commission responses to follow-up 
questions show that some states want to be closely involved in RTO 
operation 179 while others believe it better to remain 
independent of the RTO in order to engage in better 
oversight.180 Practically all respondents see siting 
authority remaining with the states.
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    \179\ See, e.g., responses of WUTC at 4 and Arizona Corporation 
Commission (ACC) at 2.
    \180\ See, e.g., response of Wisconsin Public Service Commission 
(WPSC) at 3.
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    As discussed below, the proposed rule encourages RTO design to 
accommodate appropriate state oversight, especially with regard to 
planning and siting new multi-state transmission facilities. We request 
comments on the appropriate state role in RTO governance. For example, 
should state government officials participate as voting members of an 
RTO?
12. Existing Regional Transmission Entities
    During our consultations, many of the state commissioners from the 
northeastern region and a representative from California, where 
transmission facilities are already, or soon will be, under the control 
of Commission-approved ISOs, asked that the Commission not require 
major changes to these ISOs during their implementation 
periods.181 The commissioners observed that their states' 
ISOs were still undergoing an implementation and learning period and, 
in some instances, are important to retail choice program 
implementation.
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    \181\ See, e.g., Comments at the Washington, DC conference of 
New England Conference of Public Utilities Commissioners, Inc. 
(NECPUC) at 4 and remarks of California Senator Peace, RTO 
Conference (Las Vegas), transcript at 3-4.
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    The Commission respects the investment of time and other resources 
made in the existing ISOs. We understand the importance of avoiding 
change during the critical implementation periods. Due to these 
considerations, and our proposed policy of regional flexibility, the 
proposed rule does not require major changes to the existing 
transmission entities that the Commission has found in conformance with 
the ISO principles of Order No. 888 at this time, absent compelling 
circumstances. However, any entity must meet our minimum RTO 
characteristics and functions to receive any of the benefits to be 
accorded RTOs. Our objective is to have all of the Nation's 
transmission grid under the control of RTOs that have the minimum 
characteristics and functions adopted in the Final Rule. That is why we 
propose to require the public utility members of existing transmission 
entities that have been found in conformance with the Commission's ISO 
principles to make a filing, individually or jointly, with the 
Commission no later than October 15, 2000, that explains the extent to 
which the entity in which it or they participate meets the minimum RTO 
characteristics and functions. The Commission is also concerned about 
impediments to transactions between existing ISOs (as well as any 
future RTOs). We therefore encourage existing ISOs to consider ways to 
reduce any impediments to transactions among them.
    The Commission invites further comments from the state commissions 
on all aspects of the proposed rule.

D. Minimum Characteristics and Functions for a Regional Transmission 
Organization

    In this section, we propose minimum characteristics and functions 
for a transmission entity to qualify as an 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. There are four minimum characteristics for an RTO:
    (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 addition, there are seven minimum functions that an RTO must 
perform. 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.
    The Commission seeks comment on the following questions: (1) 
whether the Commission's enumeration of minimum criteria omits a 
necessary minimum characteristic or function, or includes an 
unnecessary characteristic or function; (2) whether there is a need to 
distinguish between minimum characteristics and minimum functions 
(i.e., adopt separate categories for the minimum requirements); and (3) 
if so, whether any of the minimum characteristics should be re-
characterized as minimum functions, and vice versa. Comments on these 
questions should take into account the Commission's objective in this 
rulemaking of encouraging the formation of RTOs that promote 
competitive markets and non-discriminatory access to, and reliable 
operation of, the electric grid.
    Under this proposal, all RTOs must satisfy the four minimum 
characteristics on their first day of operation as approved RTOs. The 
Commission also proposes that all RTOs be prepared to perform at least 
four of the seven minimum functions on their first day of operation as 
approved RTOs. Recognizing that more time may be needed to perform 
certain functions, we are proposing that for the other three of the 
functions--establishing procedures for addressing parallel path flows 
with neighboring systems, managing congestion, and planning 
transmission expansion--additional time ranging from one to three years 
after initial operation will be allowed.
    The Commission seeks comments on whether we should grant RTO status 
to entities that are not able to perform immediately these three 
functions. The Commission also seeks comments on

[[Page 31414]]

whether we should grant RTO status to entities that may not be able to 
perform on the first day of operation certain other (i.e., any of the 
remaining four) of the minimum functions. Should we differentiate, for 
purposes of initial implementation, between any of the seven minimum 
functions? If so, has the Commission appropriately identified those 
minimum functions that are most likely to require additional time to 
perform?
    We propose to give transmission entities flexibility in deciding 
how to meet these seven minimum functions. For five of the functions 
(tariff administration, congestion management, ancillary services, 
market monitoring and planning and expansion), we propose to establish 
standards for how the function is performed, but an RTO will have the 
option of demonstrating that an alternative proposal is consistent with 
or superior to the standards in the proposed rule.182 The 
Commission seeks comment on whether this flexibility--i.e., the option 
of demonstrating that an alternative proposal is consistent with or 
superior to the proposed rulemaking standards--should apply to any or 
all of the minimum characteristics.183
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    \182\ We use the term ``standard'' to refer to the required sub-
elements under each characteristic and function.
    \183\ Alternative proposals may include requests for appropriate 
transition periods. We will consider such proposals on a case-by-
case basis, based on an assessment of their effect on regional power 
markets.
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    We also propose that the RTOs would have flexibility in designing 
their organizational structures. We are receptive to all types of RTO 
proposals as long as they satisfy the specified minimum characteristics 
and functions. For example, we will consider proposals for non-profit 
or for-profit organizations. An RTO can be an operator of the grid that 
it controls, an operator and owner of the grid that it controls, or a 
combination of the two.184 The minimum characteristics and 
functions provide a wide range of implementation flexibility and 
discretion. They represent a floor, not a ceiling. To encourage further 
evolution, the Commission is proposing an ``open architecture'' 
requirement. Under this requirement, the RTO must permit further 
improvements that will enhance the efficient operation of regional bulk 
power markets.
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    \184\ One example of an arrangement that combines these two 
approaches would be a transmission entity that owns and operates 
some transmission facilities and operates other facilities under 
long-term leases or other agreements with existing or new 
transmission owners.
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Minimum Characteristics

1. Characteristic 1: Independence. The RTO Must be Independent of 
Market Participants. (Proposed Sec. 35.34(i)(1))
    Market participants must be assured that the RTO will provide 
transmission access to all market participants on a fair and non-
discriminatory basis. The Commission believes that it is a prerequisite 
for achieving fair, open and competitive power markets. An RTO needs to 
be independent in both reality and perception.185 As we have 
said before in the context of ISOs, we think that ``the principle of 
independence is the bedrock upon which the ISO must be built * * 
*''186 It is the Commission's view that independence can be 
achieved if the RTO satisfies three conditions. First, the RTO, its 
non-stakeholder governing board members and its employees must have no 
financial interests in market participants.187 Second, the 
RTO's decision making must not be controlled by any market 
participants. Third, the RTO must have independent authority to file 
changes to its transmission tariff. We now discuss these conditions.

    \185\ This is also the conclusion of almost every one of the 
state commission representatives who attended our recent 
consultatons with the state regulatory community. See, e.g., 
Comments of Commissioners Marlene Johnson and Herbert Tate, Regional 
ISO Conference (Washington, D.C.), transcript at 66-67, 95; Comments 
of Judy Sheldrew, RTO Conference (Las Vegas), transcript at 58.
    \186\ Atlantic City Electric Company, et al., 77 FERC para. 
61,148 at 61,574 (1996). The same conclusion was reached by the DOE 
Reliability Task Force and the NERC Reliability Panel. The DOE 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 * * *'' Task 
Force Report at xv. The Electric Reliability Panel concluded that 
``(t)o dispel suspicions that the system operator favors one 
particular over another * * * the operator must be independent from 
market participants.'' North American Electric Reliability Council, 
Electric Reliability Panel, Reliability Power: Renewing the North 
American Electric Reliability Oversight System, December 22, 1997, 
at 17.
    \187\ We use the terms ``stakeholder'' and ``market 
participant'' interchangeably. They mean any entity that buys or 
sells electric energy in the RTO's region or in any neghboring 
region that might be affected by the RTO's actions, or any affiliate 
of such entity.
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 a. The RTO, its employees and any non-stakeholder directors must not 
have financial interests in any electricity market participants. 
(Proposed Sec. 35.34(i)(1)(i))

    We propose that the RTO, the non-stakeholder members of its 
governing board and all employees be prohibited from having financial 
interests in any market participants. The prohibition clearly applies 
to current financial interests. It does not preclude past financial 
ties with market participants. Nor does it require a total or permanent 
prohibition on all future financial ties with market participants in 
the region. Such a prohibition would make it difficult for the RTO to 
hire experienced and knowledgeable employees. Therefore, we will employ 
a rule of reason standard in deciding what financial ties with market 
participants would be acceptable after an individual leaves the RTO. As 
has been the case in our review of conflict of interest standards for 
ISOs, the Commission would establish these standards on a case-by-case 
basis.188
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    \188\ See, e.g. Midwest ISO, 84 FERC at 62,152-53, order on 
reh'g 85 FERC at 62,036; NEPOOL, 79 FERC at 62,586-87.
---------------------------------------------------------------------------

    The Commission requests commenters to address some or all of the 
following issues related to the proposed requirements. Do we need to 
define the financial independence requirement in more specific terms or 
is it sufficient to enunciate the general principle and then apply it 
on a case-by-case basis? Should the definition of stakeholders or 
market participants be expanded to include entities that operate 
distribution-only facilities (i.e., entities that perform the ``wires'' 
function at lower voltages) and transmission entities in neighboring 
regions? Should this definition be broadened to include sellers and 
buyers of ancillary services? Are there any circumstances in which the 
definition should be expanded to include entities that do not 
participate in power markets in the region but that provide 
transmission services to the RTO or buy transmission service from the 
RTO? Do we need to add more specificity to the requirement that RTOs 
have conflict of interest standards? Are there lessons to be learned 
from the experience of ISOs with conflict of interest standards that 
can now be applied more generally to RTOs?

b. An RTO must have a decisionmaking process that is independent of 
control by any market participant or class of participants. (Proposed 
Sec. 35.34(i)(1)(ii))

    This requirement would be satisfied, for example, by an RTO 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.189 The Commission seeks

[[Page 31415]]

comments on whether this kind of RTO should be deemed to satisfy 
automatically this element of the independence requirement. We also 
request comments on whether there should be a single standard for 
independent decision making for all RTOs regardless of whether they are 
for-profit or non-profit entities. The Commission recognizes that there 
may be other ways to satisfy the independent decision making 
requirement. Therefore, we propose to consider other governance and 
ownership proposals, which will be judged on a case-by-case basis 
against the general requirement of independent decisionmaking.
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    \189\ It is our understanding that a similar standard was 
established by the British government when it created the National 
Grid Company (NGC), the largest, for profit transmission company in 
the world. The company's basic corporate documents prohibit market 
participants from serving on NGC's board and from owning more than 
one percent of the shares in its voting equity. A similar 
prohibition appears to exist in the Wisconsin state law that 
mandates Wisconsin utilities to join either an ISO or an independent 
transmission company by a specific date. See 1997 Wisconsin Act 204, 
Section 30.
---------------------------------------------------------------------------

    With regard to the RTO governing board, we propose to define a non-
stakeholder governing board as a governing board of individuals without 
any financial ties to market participants or their affiliates. 
Individuals on such a board are independent, rather than 
representative, of market participants. Board members usually have 
experience in a variety of fields related to the RTO's operations. 
These could include, among others, transmission operations and 
planning, law, electricity regulation, business management, market 
analysis, and risk management. The non-stakeholder board would be the 
ultimate decision making authority, though it could choose to delegate 
decisions to its staff or committees of stakeholders.190 The 
board would be advised by the RTO staff and perhaps by a committee of 
stakeholders. In recent proceedings, we have accepted this two tier 
approach because it represents a middle ground in that it attempts to 
balance independence with expertise.
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    \190\ An ISO governing board's delegation of decisions to a 
stakeholder committee would be contingent on this committee not 
being dominated by one segment of the industry. We recently found 
that the existing tiered governance arrangements of the New York and 
New England ISOs failed to meet this standard and we ordered both 
ISOs to reduce the voting power of dominant utilities in the lower 
tier of stakeholders charged with advising the non-stakeholder 
governing boards. See Central Hudson, 87 FERC at __, slip. op. at 
12-13; New England Power Pool, 86 FERC para. 61,262 at 61,965.
---------------------------------------------------------------------------

    In the case of a non-stakeholder board, how can we ensure that the 
concerns of market participants are communicated effectively to the 
board? We request comments on what, if any, additional requirements 
should apply to a governing board that is not a stakeholder board or to 
a governing board with both stakeholders and non-stakeholders. For 
either stakeholder or non-stakeholder boards, should we impose an upper 
limit on the size of the board? How should the Commission consider 
proposals for state regulatory or other governmental officials to 
select board members for either stakeholders or non-stakeholder boards? 
How should the Commission view proposals for state government officials 
to serve as voting members of RTO boards?
    With regard to market participants having no more than a de minimis 
interest in the ownership of the RTO, we propose to consider a de 
minimis interest as having no more than a one percent interest in the 
ownership of an RTO. We seek comment on whether one percent is an 
appropriate de minimis ownership interest and, if not, what would 
constitute appropriate de minimis ownership for purposes of 
establishing independence. We also request comment on whether there are 
conditions under which market participants should be allowed to have 
more than a de minimis ownership interest in an RTO. Should the 
Commission have a different standard for passive interests? How should 
the Commission treat preferred equity shares?
    There are several reasons why we are proposing that the independent 
decision making standard can be satisfied by an RTO 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. First, affiliated transmission companies (i.e., 
transmission companies in which one or more market participants have 
more than a de minimis ownership interest) may not be trusted by market 
participants even with elaborate protections (e.g., voting trusts, 
independent trustees and corporate boards not chosen by the owners). We 
believe that market participants are likely to suspect that the 
safeguards will be gamed. This, in turn, could affect investment 
behavior. In particular, market participants may be reluctant to make 
needed investments in generation or marketing of electricity if they 
believe that the RTO is likely to give favored treatment to its 
affiliates.
    Second, affiliated transmission entities that are not independent 
of market participants would continue the regulatory need for detailed 
and hard to enforce codes of conduct. If we permit RTOs to be 
affiliated with one or more market participants, we believe that the 
Commission may have to devote considerable regulatory resources to 
``chasing after conduct'' (i.e., allegations of favoritism). If our 
experience with functional unbundling as well as with affiliated 
natural gas pipelines provides any lessons, we will probably find it 
necessary to issue detailed rules that deal with internal corporate 
matters relating to organizational responsibilities, corporate 
communications, etc.191 For this reason, the existence of 
affiliated transmission entities also could make it difficult to pursue 
light-handed regulation.
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    \191\ Natural gas pipelines that transport gas for others and 
are affiliated with gas marketers or brokers must conform to the 
standards of conduct outlined in Section 161.3 of the Commission's 
regulations. Further, such pipelines, pursuant to Section 250.16 of 
the Commission's regulations must maintain: (a) provisions in their 
effective tariffs that divulge operating employees and facilities 
shared by the pipeline and its affiliate(s) and the procedures used 
to address complaints; (b) a data log showing, by customer 
(affiliate and non-affiliate), how capacity on the pipeline was 
allocated; and (c) information concerning shippers receiving 
discounted rates. Within the natural gas pipeline industry, these 
requirements are sometimes viewed as overly intrusive regulation. 
See ``FERC Clarifies Affiliate Etiquette For Gas Pipelines,'' The 
Energy Daily, November 17, 1998, at 1.
---------------------------------------------------------------------------

    Commenters are asked to address whether these are reasonable 
assessments of the effects of allowing market participants to have more 
than a de minimis ownership interest in RTOs. Is there relevant 
experience from other regulated industries? If we were to allow market 
participants to have more than a de minimis ownership interest for a 
transition period, how long should the transition period be? Would any 
additional safeguards be required during such a transition period? In 
general, which type of institution would better serve the goal of 
independence: a transco with de minimis ownership and a non-stakeholder 
board or an ISO with a non-stakeholder board?

c. The RTO Must Have Exclusive and Independent Authority To File 
Changes to Its Transmission Tariff with the Commission under Section 
205 of the Federal Power Act. (Proposed Sec. 35.34(i)(1)(iii)

    We believe that independence requires that the RTO provide service 
under its own open access transmission tariff and that it has the right 
to file changes to its tariff with the Commission on its own authority. 
In other words, the RTO should not be required to get the prior 
approval of transmission customers, transmission owners or any other 
entities to make Section 205 filings with the Commission. The rationale 
is that if the RTO is taking over the open access transmission service 
obligation from current transmission providers, the RTO

[[Page 31416]]

must be able to independently and unilaterally propose changes in its 
tariff.192 While this is not likely to be a concern for 
transcos, our recent experience suggests that it is an important issue 
for ISOs that seek to become RTOs. We have approved ISOs that appear 
not to meet this standard. For example, the New England ISO provides 
transmission service under the tariff of the NEPOOL RTG rather than its 
own tariff.193 In our order approving the Midwest ISO, we 
stated that: ``We believe that any problems that may arise can be 
addressed by the Midwest ISO's authority to file changes unilaterally 
to the congestion management procedures.'' 194 However, our 
order also accepted a requirement that the ISO get the prior approval 
of existing transmission owners before filing certain types of changes 
in its tariff with us.195 Separately, we have a pending 
request for clarification on this issue from the PJM ISO.196 
Can an RTO be truly independent if it does not have the authority to 
file changes in its tariff without the approval of other entities such 
as transmission owners? Should the ISO's unilateral filing authority be 
limited to transmission rate design and terms and conditions that 
directly affect access but not to changes that would affect 
transmission owners' ability to collect their overall revenue 
requirements? In practice, is this a viable distinction? If an RTO's 
filed rate schedule also includes market design rules, should the RTO 
have Section 205 filing authority to make changes in these rules?
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    \192\ The Commission has previously stated that the 
``[a]uthority to act unilaterally . . . is a crucial element of a 
truly independent ISO.'' 79 FERC para. 61,374 at 62,585 (1997).
    \193\ This has been protested by the New England Conference of 
Public Utility Commissioners. See ``Motion For Leave To Submit 
Answer. . . .,'' Docket Nos. OA97-237 and ER97-1079, April 8, 1997.
    \194\ See Midwest ISO, 84 FERC at 62,163.
    \195\ Id. at 62,151.
    \196\ ``PJM Interconnection, LLC's Request For Clarification, Or 
In The Alternative, Rehearing,'' Docket No. OA97-261, December 27, 
1997.
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2. Characteristic 2: Scope and Regional Configuration. The RTO must 
serve an appropriate region. The region must be of sufficient scope and 
configuration to permit the RTO to effectively perform its required 
functions and to support efficient and nondiscriminatory power markets. 
(Proposed Sec. 35.34(i)(2))
    We propose that all RTO proposals filed with us identify a region 
of appropriate scope and configuration. The scope and configuration of 
the regions in which RTOs are to operate, and the extent to which RTOs 
control the transmission facilities within a region, will significantly 
affect how well they will be able to achieve the desired regulatory, 
reliability, operational, and competitive benefits. Accordingly, we set 
forth below what we consider to be relevant factors that may affect the 
appropriate scope and configuration for a region that an RTO will 
serve.197 If the formation of RTOs is undertaken without 
considering the goals that large regions can best achieve, it is 
unlikely that RTOs will be configured to provide maximum benefits. 
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.198 Alternatively, an RTO 
could propose configurations that interfere with the formation of a 
larger, more appropriately configured RTO.
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    \197\ We note that a number of parties have asked the Commission 
to take the initiative to make the RTO formation process more 
orderly. For example, 11 state commissions filed a petition with 
FERC in February 1998 (which was noticed in both the Midwest ISO 
proceeding and in the generic ISO inquiry) asking FERC to take 
action on the geographic configuration of ISOs, arguing that 
inappropriate borders for ISOs could result in reduced customer 
benefits, economic inefficiencies, unnecessary complication of 
coordinated operations, and detrimental impacts on planning. 
However, in our three RTO conferences, representatives of several 
other state commissions expressed concern about the Commission 
playing too strong a role in RTO formation, arguing, for example, 
that we should not define RTO geographic boundaries but should leave 
this to the parties in each area of the country to determine.
    \198\ See Statement of Ohio Commission Chairman Craig Glazer, 
RTO Conference (St. Louis), transcript at 85-87.
---------------------------------------------------------------------------

    The Commission is aware that there is likely no one ``right'' 
configuration of regions. One particular boundary may satisfy one 
desirable RTO objective and conflict with another. 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 
establish at the time of the Final Rule a set of factors that encourage 
appropriate regional configuration, without actually prescribing 
boundaries.
    In the discussion that follows, the Commission sets forth, and 
solicits comments on, the factors that it believes are important for an 
appropriately configured region in which an RTO would operate.
a. Factors Affecting The Appropriate Scope And Regional Configuration 
Of An Acceptable Region
    The Commission has grouped the factors that it believes are 
significant to developing appropriate regions into regional 
configuration factors and factors for evaluating boundaries.
i. Regional Configuration Factors
    The Commission believes that the most important consideration in 
evaluating the geographic configuration of an RTO is that such 
configuration permit the RTO to perform its functions effectively. We 
believe that 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.199 For example:
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    \199\ 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. 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.
     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 when planned 
and coordinated over a larger region.
    The Commission recognizes, however, that there may be other factors 
that limit how large a region may be, for example, the requirement that 
an RTO be the grid operator. There may be a limitation on how many 
facilities or transactions can be reliably overseen by a single 
operator, imposed either by hardware

[[Page 31417]]

design or costs, or imposed by human limitations to process the 
required amount of information.
    The Commission is not proposing that the RTO must be a control area 
operator, although four of the five ISOs approved so far by the 
Commission are each a single control area.200 If those 
forming an RTO decide that the RTO should be a control area operator, 
this too may limit the RTO's size. However, control area functions 
might be performed over a large area by a master-satellite (or other 
hierarchical) structure. The Commission solicits comments on the 
technical limitations or cost limitations on how large an RTO can be if 
it is to have control area responsibilities.
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    \200\ The Midwest ISO is the only Commission-approved ISO that 
has not proposed a single control area.
---------------------------------------------------------------------------

    The difficulty and cost of transferring operational control over 
many transmission systems to one RTO may also affect regional 
configuration. The larger the number of transmission systems, the more 
complex the task may be and the longer it may take to accomplish. The 
Commission solicits comments on how the number of transmission systems 
to be combined would affect the cost and time required to form an RTO.
    A third factor that may limit size is rate treatment. 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. Also, a uniform transmission rate treatment which 
averages the costs of existing transmission assets across the region 
could subject some RTO participants to higher transmission rates. 
Moreover, sharing the costs of future transmission improvements may 
raise issues regarding whether the transmission improvements provide 
benefits to the entire region and who should pay those costs. These 
issues are discussed further below with respect to cost shifting 
concerns.
    Are there other factors that may limit the geographic scope of an 
RTO? The Commission solicits comments on this issue.
ii. Factors for Evaluating Boundaries
    In addition to the factors affecting the size of a region, other 
factors may affect the location of regional boundaries. The Commission 
believes that RTO boundaries should 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 proposes below a 
list of factors it would consider in evaluating the configuration for a 
proposed RTO. Various factors may indicate different configurations, 
and assessing the appropriateness of a region's configuration will 
require a balancing of factors.
    Given this qualification, the Commission proposes that the 
following factors should be considered in evaluating an RTO's 
boundaries:
    Facilitate performing essential RTO functions and achieving RTO 
goals, as discussed elsewhere in this proposed rule: 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.
    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 inhibiting trade between 
regions that could be mitigated economically. It would be desirable 
that RTO boundaries not perpetuate these barriers.
    Not facilitate 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 RTOs. Thus, it is important to avoid creating an RTO region that 
is dominated by a only a few buyers or sellers of energy, or a region 
where an RTO of inappropriate scope and configuration can exercise 
transmission market power by acting as an unnecessary toll collector on 
a critical corridor.
    Encompass existing control areas: Existing control areas have 
established systems for load balancing within their area. Most existing 
control areas are relatively small. For the sake of efficiency, it may 
be advisable not to divide them. However, the affected parties would 
not be precluded from proposing to divide control areas if they found 
it otherwise advantageous.
    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 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.''
    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. 
The Commission welcomes comments on the relative merits of 
internalizing constraints within a region versus having constraints act 
as natural boundaries between regions.
    Take into account existing regional boundaries (e.g. North American 
Electric Reliability Council (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. There is value in 
keeping together parties that have been working together.
    Take into account international boundaries: The Commission 
recognizes

[[Page 31418]]

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, 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 does not have, and does not 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.
    The Commission seeks comments on the appropriateness of these 
factors to determine an appropriate configuration for the regions in 
which RTOs would operate, and also asks if any additional factors may 
be appropriate.
b. Potential Geographic Configurations
    Any number of RTO configurations could be appropriate regions. One 
approach to establishing RTO regions is to use existing configurations. 
These include the three electric interconnections within the 
continental United States, the ten NERC reliability councils, and the 
twenty-three NERC security coordinator areas. (See Appendix C to this 
NOPR for depictions of these configurations 201). These 
configurations are offered only for the purposes of having three 
examples for assessing how well selected regions can satisfy the 
minimum RTO characteristics and functions and for focusing commenters 
on the trade-offs involved in determining an RTO configuration. The 
Commission has not concluded that the example sets of boundaries are 
acceptable configurations. The Commission seeks comments on how well 
the regions served by existing institutions would satisfy the factors 
enunciated above, and specifically how well they would be able to 
satisfy the minimum RTO characteristics and functions outlined in this 
section, and the advantages and disadvantages of these three examples. 
The Commission also welcomes presentation and evaluation of other 
methods to define appropriate regions.
---------------------------------------------------------------------------

    \201\ While the maps in Appendix C accurately depict the 
existing configurations extending into Canada, this is not intended 
to suggest that our jurisdiction under this proposed rule reaches 
there.
---------------------------------------------------------------------------

c. Control of Facilities within a Region
    In addition to the scope and configuration of the region, effective 
performance also requires that most or all of the transmission 
facilities in a region be included in the RTO. Any RTO proposal filed 
with us should plan to operate all transmission facilities within its 
proposed region. We recognize, however, that there may be cases where 
the proponents of an RTO may not be able to obtain agreement by all 
transmission owners within 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 significant portion 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 proposed region if the 
proponents represent only a small portion of the facilities in that 
region.
    We therefore propose to accept as RTOs only those proposals for 
which a region of appropriate scope and configuration is identified and 
the proponents represent a sufficient portion of the transmission 
facilities within the identified region. Where the proponents do not 
represent all the facilities within a region, they should identify the 
reasons why all facilities are not represented, any efforts that will 
be made to eventually include all facilities, and any interim 
arrangements that could be made with the non-represented facility 
owners to maximize coordination within the region.
    We solicit 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. Should we deny RTO status for any proposal 
that does not include all transmission facilities within an appropriate 
region? If we do not deny RTO status for less than 100 percent 
participation, is there some guideline that we should use for 
determining when the proponents represent an appropriate ``critical 
mass'' for the region? Should we require that the RTO at least 
negotiate certain agreements with any non-participants within its 
region to ensure maximum coordination? If so, what should be the terms 
of such agreements?
    Finally, we seek comment on the question of how much deference, if 
any, we should give to the proposed scope and regional configuration of 
a proposed RTO. How readily, if at all, after balancing all appropriate 
factors, should the Commission be willing to substitute its vision of 
an appropriate RTO configuration for that of its proponents? To what 
extent should the Commission take into account the degree of support in 
assessing a proposed RTO configuration? Should approval or disapproval 
by affected state commissions of the scope or configuration of a 
proposed RTO affect the level of deference the Commission should afford 
such a proposal?
3. Characteristic 3: Operational Authority. The RTO must have 
operational responsibility for all transmission facilities under its 
control.202 (Proposed Sec. 35.34(i)(3))
---------------------------------------------------------------------------

    \202\ Transmission facilities will be distinguished from local 
distribution facilities using the criteria that were established in 
Order No. 888. Order No. 888, FERC Stats. and Regs. para. 31,036 at 
31,770-71.
---------------------------------------------------------------------------

    a. The Regional Transmission Organization May Choose to Directly 
Operate Facilities (Direct control), delegate certain tasks to other 
entities (Functional Control) or Use a Combination of the Two 
Approaches. (Proposed Sec. 35.34(i)(3)(i))

    Operational control raises two basic questions: What functions 
should be performed by an RTO? How should an RTO perform the functions 
that it has reserved for itself? With respect to the first question, 
there is a concern that some splits of functions between an RTO that is 
an ISO and existing control area operators could compromise reliability 
and allow the control area operators to continue to favor their own 
power marketing efforts.203
---------------------------------------------------------------------------

    \203\ Midwest ISO, 84 FERC at 62,156-60, 62,181.
---------------------------------------------------------------------------

    One solution would be for all RTOs to operate a single control 
area. We have decided not to propose this as a requirement or two 
reasons. First, the recent experience with the California ISO suggests 
that the cost of investing in new control centers and 
telecommunications systems and developing new operating systems can be 
very high.204 Second, there is some uncertainty as to 
whether it is technically feasible to establish a single traditional 
control area over a large

[[Page 31419]]

geographic area. In light of these considerations, we do not propose to 
require that an RTO must operate a single control area. However, the 
RTO must have ultimate responsibility for providing non-discriminatory 
transmission service for all market participants and for ensuring the 
short-term reliability of the grid.205 We propose to give an 
RTO considerable flexibility in deciding on the particular division of 
operational responsibilities with existing control areas that will 
allow it to achieve this outcome.
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    \204\ A recent report commissioned by the California ISO found 
that the higher costs of the California ISO relative to other ISOs 
could be explained, in part, by the decisions ``to build a privately 
dedicated communications network, to have a hot standby backup 
center half a state away, to not rely on existing infrastructure 
more than necessary, to attempt full functionality on day one, to 
accomplish the job in about one year. . .'' See ``A Comparative 
Analysis Of Operating Independent System Operators In The United 
States,'' prepared by James H. Caldwell Jr. (TGAL, Inc.) For the 
California ISO, October 15, 1998, at 13.
    \205\ 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 will also grant an RTO considerable flexibility in deciding how 
best to perform the functions that it has reserved for itself. The RTO 
may choose to operate the grid through direct physical operation by RTO 
employees, contractual agreements with other entities (e.g., 
transmission owners and control area operators) or combinations of the 
two. For example, an RTO could lease some control equipment from the 
owners of existing control centers or convert some employees at these 
control centers into RTO employees. Or alternatively, the RTO could 
establish a system of hierarchical control in which it operates a 
master control center and existing control centers become satellites of 
the RTO control center for certain specified functions. 206 
Under this arrangement, the personnel of the existing control centers 
might become employees of the RTO or remain as employees of the control 
center owner but supervised by RTO personnel. We will leave it to the 
discretion of the RTO to decide on the combination of direct and 
functional control that works best for its circumstances.207 
Our only requirement is that the system of operational control chosen 
by the RTO 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 
an RTO to prepare a public report that assesses the efficacy of its 
operational arrangements no later than two years after it begins 
operations.
---------------------------------------------------------------------------

    \206\ See, e.g., Marija Ilic and Shell Liu, Hierarchical Power 
System Control: Its Value in a Changing Industry, Springer-Verlag, 
1996. It appears that certain types of hierarchical arrangements 
have operated successfully in the PJM and NEPOOL pools for many 
years.
    \207\ This topic is also addressed in our discussion of the 
RTO's role as a provider of ancillary services. See the discussion 
of Function 4.
---------------------------------------------------------------------------

    The Commission requests commenters to address the following 
questions. What has been the experience of existing tight power pools 
with master-satellite and hierarchical forms of control? Was there a 
need to modify these operational arrangements when the pool was 
replaced by an ISO? Outside of tight power pools, has the functional 
unbundling requirement in Order No. 888 led to any divisions of 
previously integrated internal operational systems? If so, have these 
new divisions of operational responsibilities created any reliability 
problems?

    b. The RTO must be the security coordinator for the transmission 
facilities that it controls. (Proposed Sec. 35.34(i)(3)(ii))

    The Commission will also require that any qualifying RTO be the 
NERC approved security coordinator for its region. A security 
coordinator is a new type of grid entity that typically coordinates 
reliability between multiple control areas across a region. It has been 
promoted by NERC since 1995 to improve coordination and communication 
across control areas. At present, there are more than 20 security 
coordinators.208
---------------------------------------------------------------------------

    \208\See NERC, Operating Policy 9--Security Coordinator 
Procedures. The current version of this document is available on the 
NERC website at http://www.nerc.com/oc/opermanl.html. 
See also, NERC TLR Order, 85 FERC para. 61,353 at 62,360-62.
---------------------------------------------------------------------------

    Up to now, the job of a security coordinator has been to anticipate 
reliability problems and to take actions to correct these problems if 
they arise. Among the key functions of a security coordinator are to: 
(1) perform load-flow and stability studies of the transmission system 
to identify and address security problems; (2) exchange necessary 
security information with control area operators, ISOs and regional 
reliability councils; (3) monitor real-time operating characteristics 
(e.g., availability of operating reserves, interchange schedules, 
system frequency, actual flows versus limits, generation capacity 
deficiencies) that could affect reliability; (4) take appropriate 
action including, if necessary, the shedding of load in the event of a 
reliability problem.209
---------------------------------------------------------------------------

    \209\ Midwest ISO, 84 FERC at 62, 155-56.
---------------------------------------------------------------------------

    In our Midwest ISO order, we required that the proposed ISO must be 
the security coordinator for its region. Our justification for this 
requirement was that:

    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.

    The same logic applies to any RTO proposal. Therefore, we will 
require that a qualifying RTO must be the security coordinator for its 
region. 210
---------------------------------------------------------------------------

    \210\ We note that this was also the conclusion of the blue-
ribbon Electric Reliability Panel of NERC. In its final report, the 
panel concluded that ``it is essential that the security 
coordinators perform their functions independent of any market 
influences.'' The panel recommended that security coordinators 
should be ``structured as independent entities, or their role 
subsumed into independent system operator-type organizations.'' 
NERC, Electric Reliability Panel, ``Reliable Power: Renewing the 
North American Electric Reliability Oversight System,'' December 
1997, at 35.
---------------------------------------------------------------------------

4. Characteristic 4: Short-term Reliability. The RTO must have 
exclusive authority for maintaining the short-term reliability of the 
grid that it operates. (Proposed Sec. 35.34(i)(4))
    a. The RTO must have exclusive authority for receiving, 
confirming and implementing all interchange schedules. (Proposed 
Sec. 35.34(i)(4)(i))

    Historically, interchange schedules have referred to the scheduling 
actions between adjacent control areas. These schedules could be 
triggered by the sale or exchange of electricity or the wheeling of 
electricity between the two control areas. The first type of action, 
the sale or exchange of electricity between control areas, usually has 
not been accompanied by a separate transmission transaction. Instead, 
the transmission service was implicit in the overall transaction and, 
therefore, its cost was not quoted separately. With the growth of 
unbundled transmission service, triggered in part by our Order No. 888 
requirements, bundled interchange transactions will become rarer. This 
means that in the future, interchange schedules will generally be 
accompanied by, and coincide with, transmission schedules.
    We are proposing that an RTO ``must receive and evaluate all 
requests for transmission service under its own FERC approved tariff.'' 
211 If the RTO operates a control area, this implies that 
the RTO will also be receiving, confirming and implementing interchange 
schedules. Therefore, the three actions should go hand-in-hand for an 
RTO that operates a control area.

[[Page 31420]]

However, this may not be the case for RTOs that do not operate control 
areas. As we stated in our Midwest ISO order, our basic concern is that 
non-RTO control area operators who are also competitors in power 
markets may be ``able to know their competitors' schedules or 
transactions* * *'' 212 If this is true, such knowledge 
would give the control area operators an unfair competitive advantage. 
The Commission directed the ISO to monitor for this potential problem 
and report to us immediately if the problem arises. We recognize, 
however, that it may be difficult to detect this discrimination. In 
addition to our current code of conduct standards, are there any 
actions that the Commission should require to reduce the likelihood of 
this problem that do not require the consolidation of all existing 
control areas within the region? Is it feasible for a non-RTO control 
area operator, operating within an RTO region, to perform its functions 
without having access to commercially sensitive information involving 
its competitors? For example, could an RTO provide control area 
operators with information about scheduled net interchanges between 
control areas without disclosing the individual transactions making up 
the new interchanges? 213

    \211\ See the discussion of Function 1 (Tariff Administration 
and Design), infra.
    \212\ See Midwest ISO, 84 FERC at 62,154-55.
    \213\ See Id. at 62,160.
---------------------------------------------------------------------------

    b. 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. (Proposed 
Sec. 35.34(i)(4)(ii))

    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.'' 214 The entity that controls the transmission 
system must have some degree of control over some 
generation.215 In general, we do not think that this 
authority should extend to initial unit commitment and dispatch 
decisions of generators. However, the Commission believes that it is 
necessary and appropriate that the RTO have authority to order 
redispatch of any generating unit when necessary for the reliability of 
the grid.

    \214\ Id. at 62,151.
    \215\ This seems to be generally recognized in the industry. For 
example, the participants in the Midwest ISO proposed that the ISO 
``will possess authority over generation to the extent that 
generation affects transmission.'' See ER98-1438-000, Applicants' 
Response at 3.
---------------------------------------------------------------------------

    c. 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. (Proposed Sec. 35.34(i)(4)(iii))

    Control over transmission maintenance is a necessary RTO function 
because planned and unplanned outages of individual 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 so adversely affect system 
reliability. The availability or unavailability of specific 
transmission facilities can also have major effects on electricity 
market prices.216
---------------------------------------------------------------------------

    \216\ See ``Staff Report to the FERC on the Causes of Wholesale 
Electric Pricing Abnormalities in the Midwest During June 1998,'' 
September 22, 1998, at 4-3.
---------------------------------------------------------------------------

    Under this proposed requirement, the RTO would determine whether 
the proposed maintenance of transmission facilities could be 
accommodated within established state, regional and national 
reliability standards. 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. Since 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.
    If the RTO is a transmission company that owns and operates 
transmission facilities, these assessments would be an internal company 
matter. If the RTO is an ISO, it would need to review transmission 
requests made by various transmission owners (TOs) of its 
region.217 In this latter case, we would 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 on a regular 
basis.
---------------------------------------------------------------------------

    \217\ 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.
---------------------------------------------------------------------------

    The Commission requests commenters to address a number of questions 
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 proposed requirement does not give the RTO any authority over 
proposed generation maintenance schedules. However, 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.'' 218 Should the RTO have some 
authority over generation maintenance schedules? If so, how much 
authority should it have?
---------------------------------------------------------------------------

    \218\ Midwest ISO, 84 FERC at 62,180.
---------------------------------------------------------------------------

    We also anticipate that the RTO will need 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 would anticipate 
that such quality standards would be implicit or explicit in any 
performance based regulatory proposal. 219/ Is it possible 
for a non-profit ISO to establish similar incentive schemes for the 
transmission owners whose facilities it operates?
---------------------------------------------------------------------------

    \219\ We note that the National Grid Company in England and 
Wales reports annually on quality of service in certain dimensions 
(systems availability, interconnector availability, system security 
and quality of supply) to the Director General of Electricity 
Supply. See National Grid Company ``Report of the Director General 
of Electricity Supply, Financial Year 1997-98.'' A copy of this 
report will be placed in the public record.
---------------------------------------------------------------------------

    Facility ratings. It is widely recognized that 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

[[Page 31421]]

and equipment ratings. If a transmission line or other facility becomes 
overloaded or experiences a forced outage, the short-term reliability 
of the power system may be threatened. Therefore, we anticipate that 
the RTO will need to monitor equipment availability and loading so that 
it can determine which control actions or redispatch options are 
necessary. The options open to the RTO for ensuring short-term 
reliability, such as direct control of transmission facilities, 
initiating transmission loading relief procedures or pursuing 
redispatch options and bids, are discussed in other sections.
    To determine whether existing or scheduled power flows will 
threaten short-term system reliability, flow levels must be compared to 
ratings established in power flow reliability studies. The entity that 
establishes these ratings and operating ranges will have a major 
influence on the reliable operation of the power system. Its 
determinations will not only affect system reliability but also ATC. 
The Commission believes 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 since they will be independent 
in two ways: 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 recognizes that an RTO that is an ISO may initially 
need to rely upon existing values for equipment ratings and operating 
ranges so as not to disrupt reliable system operation. The RTO will 
then have the ongoing task of validating and updating these existing 
values, focusing initially on those identified as critical to the 
development of a competitive electricity market.
    The Commission understands that transmission owners may be 
concerned that changes in existing equipment ratings may lead to 
problems of equipment safety and possible damage. These concerns could 
trigger disputes over the values established by the RTO. We propose 
that if there is a dispute over values established for equipment 
ratings, the RTO values will prevail until the outcome of the dispute 
resolution process. It is the intent of the Commission to promote RTOs 
that have the expertise and personnel capable of determining both 
equipment ratings and operating ranges necessary to maintain system 
reliability. In addition, since RTOs will be independent of all 
stakeholders in the electricity market, they will not have an incentive 
to distort the operation of electricity markets by manipulating 
equipment ratings and reliability assumptions. And most significantly, 
since the RTO is ultimately responsible for system reliability, it will 
be careful not to harm system equipment. Therefore, to avoid an impasse 
over equipment ratings that are determined by one market participant 
and contested by a second, we believe that the RTO's values should 
prevail when there is disagreement, until resolution is reached through 
an ADR process approved by the Commission.220
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    \220\ This is the same policy that we adopted in approving the 
Midwest ISO. See Midwest ISO, 84 FERC at 62,165-66.
---------------------------------------------------------------------------

    The Commission asks commenters to address the following issues. 
Given that an RTO has responsibility for system reliability, what 
should be the extent of its liability for its actions? Would this 
differ depending on whether the RTO owns the facilities?

    d. 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 it from 
providing reliable, non-discriminatory and efficiently priced 
transmission service. (Proposed Sec. 35.30(i)(4)(iv))

    RTOs may be new organizations. However, they will be sharing some 
of their responsibilities with existing organizations. For example, the 
New England ISO shares its responsibilities with the NEPOOL 
RTG.221 The New York ISO shares its reliability 
responsibilities with the New York State Reliability Council. We 
anticipate that, in the near future, RTOs will be implementing 
reliability standards that are established by a separate regional 
reliability council.222 We believe this is necessary to 
maintain the reliable operation of the grid, but it also raises 
concerns because almost every reliability standard will have a 
commercial consequence, and regional or sub-regional reliability groups 
may not be as independent of market participants as RTOs.223 
As a consequence, an RTO could be required to implement a reliability 
standard that may favor the commercial interests of certain types of 
market participants when an equally effective, but more commercially 
neutral, variant of the standard might be feasible. Therefore, it is 
important that the RTO notify us immediately if implementation of 
externally established reliability standards will prevent it from 
meeting its obligation to provide reliable, non-discriminatory 
transmission service.
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    \221\ Commissioner Malachowski, representing the New England 
Conference of Public Utility Commissions (NECPUC), stated that the 
current sharing of power between the New England ISO and NEPOOL is 
unsatisfactory. He said that the New England commissions believe 
that more decision making authority must be transferred to the ISO. 
As a specific example, the mentioned the need for the ISO to have 
more direct authority over market design. RTO Conference 
(Washington, D.C.), transcript at 123.
    \222\ In Order 888, we required that any ISO should ``comply 
with their applicable standards set by NERC and the regional 
reliability council.'' (ISO Principle No. 4)
    \223\ See Central Hudson, 83 FERC at 62,411 for a discussion of 
our concerns about the relationship between the New York ISO and the 
New York State Reliability Council. In this instance, we were 
willing to accept the fact that the NYSRC will establish rules that 
the ISO would implement because any new rule or revisions to 
existing rules would be ``subject to immediate suspension by the 
NYSRC if requested to do so by the New York ISO.'' Id.
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Minimum Functions

1. Function 1: Tariff Administration and Design. The RTO must 
administer its own transmission tariff and employ a transmission 
pricing system that will promote efficient use and expansion of 
transmission and generation facilities. (Proposed Sec. 35.30(j)(1))
    The pro forma open access transmission tariff that accompanied 
Order No. 888's functional unbundling is based on a traditional 
approach to transmission service: it relies on embedded cost 
ratemaking, contract path scheduling and physical rights to service. We 
recognized that it did not break new ground on transmission pricing 
because it was based ``on the practices and procedures'' that were 
traditionally used by public utilities that owned transmission 
facilities. Instead, the focus of the pro forma tariff is on the non-
price terms and conditions of transmission service needed to get non-
discriminatory transmission service. Our intent was to ``initiate open 
access'' for individual transmission providers. We stated that our 
issuance of the pro forma tariff was ``* * * not intended to signal a 
preference for contract path/embedded cost pricing for the future.'' 
224 In the Capacity Reservation Tariff (CRT) NOPR that was 
issued at the same time, we emphasized that: ``* * * the Commission is 
not committed to traditional tariff design.'' 225 Since the 
issuance of Order No. 888, the Commission has encouraged transmission 
providers to come forward with other open access transmission tariffs 
that they believe have pricing

[[Page 31422]]

provisions that are equal or superior to the mandated tariff that was 
part of the Order No. 888 initiative.
---------------------------------------------------------------------------

    \224\ Order No. 888, FERC Stats. & Regs. at 31,666-67.
    \225\ CRT NOPR, FERC Statutes and Regulations at 33,228 (1996).
---------------------------------------------------------------------------

    To date, the most significant innovations in transmission access 
and pricing have been brought to us by ISOs. This is not surprising. 
Given the interconnectedness of the grid, it is necessary to introduce 
regional pricing innovations through some kind of regional 
organization. This cannot be done by individual transmission providers 
acting alone. We anticipated that regional organizations would be the 
likely innovators in our Transmission Pricing Policy Statement. Among 
the innovations that have been proposed since the issuance of Order No. 
888 are: locational pricing; fixed transmission rights (FTRs) and 
transmission congestion contracts (TCCs) that give defined financial 
rights to grid users (i.e., financial rather than physical rights to 
the grid); and explicit market-based pricing of congestion and 
ancillary services.226 In almost every instance, we have 
approved these proposals because they offer the promise of promoting 
overall operating efficiency and encouraging fair, open and competitive 
energy markets.
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    \226\ See, e.g., Pacific Gas & Electric, 81 FERC para. 61,122 
(1997), Central Hudson, 83 FERC para. 61,352 (1998), NEPOOL, 85 FERC 
para. 61,242 (1998); PJM; 81 FERC para. 61,257 (1997).
---------------------------------------------------------------------------

    Therefore, we take this opportunity to reaffirm the importance of 
such reform by establishing it as an explicit obligation for qualifying 
RTOs. The wording of this requirement is general and this is 
intentional. The Commission believes that RTOs are in the best position 
at this time to develop innovative transmission access and pricing 
regimes that will promote competition and meet the needs of their 
region. The Commission invites commenters to address whether more 
specific guidance is required.
    In carrying out Function 1, the RTO must satisfy each standard 
discussed below, or demonstrate that an alternative proposal is 
consistent with or superior to satisfying the standard.

a. 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.227 (Proposed Sec. 35.30(j)(1)(i))

    \227\ The Commission, of course, retains ultimate authority to 
order transmission services and interconnections pursuant to the 
FPA.
---------------------------------------------------------------------------

    The rationale for this standard is straightforward. The RTO cannot 
ensure nondiscriminatory transmission service to all market 
participants unless it is the sole provider of transmission service 
over facilities that it owns or controls. If it is to be an effective 
``provider'', it must be the only entity that receives, evaluates and 
approves or denies requests for transmission service. However, it 
cannot make informed decisions unless it has accurate and unbiased 
information about pending transmission requests and current system 
conditions. This, in turn, implies that in addition to being the 
transmission service provider, the RTO must be the operator of the 
OASIS site as well as the regional security coordinator (see the 
discussion of function 5 and characteristic 3).
    An organization like an independent scheduling administrator that 
simply monitors the scheduling decisions of current transmission owners 
and offers dispute resolution services in case of a dispute would not 
qualify as an RTO. Similarly, a transmission organization that offers 
service under another entity's tariff would not meet this standard.
    An RTO's obligation to provide nondiscriminatory transmission 
service is not limited just to existing users. It is important that the 
RTO ensures nondiscriminatory access to transmission service for new 
entrants such as new generators. This requires that the RTO, rather 
than existing transmission owners, have the authority to review and 
approve requests for interconnections. The Commission believes that the 
RTO cannot be an effective provider of transmission service if it lacks 
the authority to ensure that new customers are interconnected to the 
grid. This standard should be relatively easy to implement for an RTO 
that owns transmission facilities. However, it may be more difficult 
for an RTO that does not own transmission facilities because actual 
physical construction of the interconnection facilities will usually be 
made by an existing transmission owner who may also be a competitor of 
the new generator. Therefore, the Commission invites comments on how 
this standard can be made effective for RTOs that are ISOs. Are there 
lessons to be learned from the experience of qualifying facilities 
(QFs) under PURPA in getting interconnections to the grid that would be 
applicable to ISOs? Should this standard be expanded to give the RTO 
the authority to review and approve all new interconnections (e.g., to 
connect new generators, to improve reliability, to increase trading 
opportunities with neighboring regions) or all transmission investments 
above some threshold dollar amount?

b. The RTO tariff must not result in transmission customers paying 
multiple access charges to recover capital costs over facilities that 
it controls (i.e., no pancaking of transmission access charges). 
(Proposed Sec. 35.34(j)(1)(ii))

    The elimination of transmission rate pancaking for large regions is 
a central goal of the Commission's RTO policy. Therefore, the offering 
of non-pancaked transmission access charges is a requirement for a 
conforming RTO. In the existing world of many individual transmission 
service providers, transmission customers have generally been required 
to pay an access charge to each transmission provider along the 
contract path (and pay nothing to providers off the contract path). 
This is a form of distance-based transmission pricing, but the charge 
is a function of corporate boundaries crossed on the contract path 
rather than distance traveled on actual flow paths. Such pancaked 
transmission charges have led to multiple transmission charges across 
several transmission systems and make it difficult to create region-
wide power markets. Competition is clearly enhanced when customers are 
able to access larger numbers of generators over a wide geographic 
region when they pay a single transmission access charge. In Order No. 
888, we required tight power pools and holding companies to offer a 
system-wide tariff with non-pancaked rates.228 To date, non-
pancaked transmission access charges have been a feature of all five 
ISOs that we have approved. In this NOPR, we are proposing to extend 
that requirement to RTOs.
---------------------------------------------------------------------------

    \228\Order No. 888, FERC Stats. & Regs. at 31,727-29, 31,731.

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[[Page 31423]]

    Would the requirement for a tariff with non-pancaked rates make the 
voluntary formation of RTOs more difficult because it might result in 
the potential for sudden and unacceptable transmission rate charges? Is 
the severity of any such problem related to the scope and regional 
configuration of the proposed RTO? Does the use of so-called license 
plate design allow the RTO to meet this requirement without cost 
shifting? Would the provision for a reasonable transition period help?
    Waiving of access charges. While the Commission wishes to encourage 
more efficient intra-regional trade, it also would like to encourage 
inter-regional trade. Boundaries are always a potential impediment to 
trade, whether between states, RTOs or countries. Therefore, we 
encourage RTOs to negotiate the mutual waiving of transmission access 
charges to increase the size of effective trading areas. In the Midwest 
ISO proceeding, we were told that this was difficult to 
implement.229 Therefore, commenters are requested to 
recommend actions that the Commission could take to facilitate 
reciprocal waiving of access charges. Even if there is mutual waiving 
of access charges, are there other pricing impediments to inter-
regional trade (e.g., differences in scheduling and curtailment 
conventions between regions) that are likely to impede trade?
---------------------------------------------------------------------------

    \229\ See Response of Midwest ISO Participants, May 1, 1998, at 
11-13.
---------------------------------------------------------------------------

2. Function 2: Congestion Management. The RTO must ensure the 
development and operation of market mechanisms to manage transmission 
congestion. (Proposed Sec. 35.34(j)(2)).
    In carrying out Function 2, the RTO must satisfy each standard 
discussed below, or demonstrate that an alternative proposal is 
consistent with or superior to satisfying the standard.

a. 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. 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. (Proposed 
Sec. 35.34(j)(2)(i))

    As we stated in our recent order addressing NERC's transmission 
loading relief (TLR) procedures, the traditional approaches to 
congestion management may no longer be acceptable in a competitive, 
vertically de-integrated industry.230 For example, the use 
of administrative curtailment procedures has important economic 
consequences for market participants, yet such procedures are usually 
invoked without regard to the relative value of transactions that are 
curtailed. This can lead to a considerable disruption of power markets 
and can be financially damaging for market participants. The Commission 
has concluded that efficient congestion management requires a greater 
reliance on market mechanisms.231 Recent experience suggests 
that only a large regional organization like an RTO will be able to 
create a workable and effective congestion management 
market.232
---------------------------------------------------------------------------

    \230\ See NERC, 85 FERC at 62,364.
    \231\ Id.
    \232\ The recent experience of Commonwealth Edison suggests that 
redispatch markets operated by individual utilities will not be able 
to elicit an adequate response by generators. After six months of an 
experimental program, Commonwealth concluded that it is ``difficult 
for one transmission owner to identify and implement redispatch'' 
when the physical limitations and cost effective options for relief 
are on other transmission systems. According to Commonwealth, the 
only viable solution would be for the redispatch market to be 
operated by a regional transmission system operator. See 
Commonwealth Edison, Interim Report on Non-Firm Redispatch, Docket 
No. ER98-2279, December 17, 1998, at 4 and 10.
---------------------------------------------------------------------------

    As we noted in our order approving the PJM ISO, markets that are 
based on locational marginal pricing and financial rights for firm 
transmission service provide a sound framework for efficient congestion 
management.233 However, just as we do not intend to mandate 
a single corporate form for RTOs, we will not require one specific 
market approach to congestion management. It is our intent to give RTOs 
considerable flexibility in experimenting with different market 
approaches to managing congestion. However, we believe that a workable 
market approach to congestion management should generally 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.
---------------------------------------------------------------------------

    \233\ See, e.g., PJM, FERC 62,252-53.
---------------------------------------------------------------------------

    A market approach to congestion management should lead to more 
efficient transmission prices. As we explained in our Transmission 
Pricing Policy Statement, an efficient pricing policy must meet certain 
objectives.234 Of the four objectives set forth in the 
Policy Statement, two are particularly relevant for congestion 
management. First, the generators that are dispatched in the presence 
of transmission constraints should be those that can serve system loads 
at least cost, given the constraints. Second, given that the demand for 
transmission services during periods of congestion exceeds the system's 
ability to supply them, the limited transmission capacity should be 
used by market participants that value that use most highly.
---------------------------------------------------------------------------

    \234\ Transmission Pricing Policy Statement, FERC Stats. & Regs. 
at 31,140-44.
---------------------------------------------------------------------------

    In designing market mechanisms for congestion management, the 
Commission recognizes that it is important to consider the time frame 
in which decisions must be made and actions must be taken. It is the 
nature of electric systems that operating conditions, including those 
that lead to the presence or absence of congestion, are constantly 
changing. Thus, to manage congestion efficiently while ensuring safety 
and reliability, system operators must be able to take decisive action 
quickly.
    One possible implication of this need for quick, decisive action is 
that markets that directly support congestion management may have to be 
subject to some coordination by the RTO. For example, a congestion 
market that is not coordinated by the RTO might require transmission 
customers to negotiate individually with generators to pre-arrange an 
alternative dispatch that would allow the transmission customer's 
transaction to proceed (or to be efficiently altered) if and when 
congestion arises. However, because congestion can occur suddenly and 
unexpectedly, time may not permit the operator to (1) identify 
impending transmission constraints, (2) inform customers whose 
transactions are affected, (3) allow customers to contact generators, 
and (4) receive instructions from customers as to what actions they 
wish the operator to take with respect to their pending transactions. 
We have expressed concerns that such a process may be unwieldy and even 
unworkable in the limited time in which operators must 
act.235 Although the process could be simplified by 
completing some of these activities in advance, such simplifications 
may come at the cost of eliminating some potentially efficient options.
---------------------------------------------------------------------------

    \235\ We expressed similar concerns in our order authorizing the 
formation of the Midwest ISO. See Midwest ISO, 84 FERC at 62,165-66. 
Nevertheless, we opted to allow the Midwest ISO to go forward with 
its proposal in order to gain actual operating experience.
---------------------------------------------------------------------------

    The Commission invites comments on our requirement that RTOs must 
be responsible for managing congestion with a market mechanism. Can

[[Page 31424]]

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 market power in a congestion market operated or facilitated 
by an RTO?
    We propose that the congestion management function need not 
necessarily be in place on the first day of RTO operation, and propose 
to allow up to one year after start-up for this function to be 
implemented. We recognize that the new approaches to congestion 
management called for by newly competitive markets may take additional 
time to work out. We seek comment on whether such an additional 
implementation time period is warranted, and whether one year is an 
appropriate additional time period.
3. Function 3: Parallel Path Flow. The RTO must develop and implement 
procedures to address parallel path flow issues within its region and 
with other regions. The RTO must satisfy this requirement with respect 
to coordination with other regions no later than three years after it 
commences initial operation. (Proposed Sec. 35.34(j)(3))
    Many power sales and transmission service contracts are written 
under the assumption that the power delivered will flow on a particular 
contract path. This relatively straightforward and easy to administer 
``contract path'' approach assumes that it is possible to determine and 
fix the path through the transmission network along which power will 
flow from source to sink. However, this assumption often does not 
accurately reflect what actually occurs because the scheduled power 
transfer will flow across the interconnected electrical path between 
source and destination according to laws of physics, which means that 
some power may flow over the lines of adjoining transmission systems. 
This power flow effect is commonly referred to as ``parallel path 
flow'' or ``loop flow.''
    Parallel path flows have the potential to create, and have in the 
past created, disputes among transmission system owners. There are 
efficiency and economic equity issues involved when a scheduled 
transaction in fact causes power flows over the facilities of an entity 
that is not compensated, or when the costs of mitigating parallel flows 
are allocated to various transmission owners.236 There are 
also reliability issues involved when parallel path flows overload a 
transmission line, and decisions must be made as to what actions to 
take, and who should bear responsibility for taking necessary steps to 
unload that line.237 The interdependent nature of 
electricity flow implies that one party's ability to transmit energy 
will depend upon the actions of others, and, for scheduling and pricing 
purposes, the capacity of the entire network and not just individual 
systems is the most important factor.238
---------------------------------------------------------------------------

    \236\ See Indiana Michigan Power Company and Ohio Power Company, 
64 FERC para. 61,184 (1993) (Indiana Michigan) (complaint that 95% 
of a power sale flowed over transmission system that was not 
compensated); Southern California Edison Company, et al., 73 FERC 
para. 61,219 (1995) (Southern California) (Commission approved plan 
for mitigating loop flows within the WSSC).
    \237\ See NERC, 85 FERC para. 61,353 (1998).
    \238\ The Order No. 888 pro forma open access tariff does not 
explicitly recognize the effect of parallel path/loop flow.
---------------------------------------------------------------------------

    The Commission has previously expressed its view that the issues 
surrounding parallel path flow are best resolved by mutual arrangements 
between the utilities that have chosen to interconnect.239 
More recently, the Commission directed all public utilities in the 
Eastern Interconnection to file an interim redispatch plan if they are 
not currently participating in a regional congestion management program 
through a power pool.240
---------------------------------------------------------------------------

    \239\ See Indiana Michigan, 64 FERC at 62,554.
    \240\ NERC, 85 FERC at 62,363-64.
---------------------------------------------------------------------------

    The Commission believes that the formation of RTOs, with their 
widened geographic scope of transmission scheduling and expanded 
coverage of uniform transmission pricing structures provides an 
opportunity to ``internalize'' most, if not all, of the effect of 
parallel path/loop flow in their scheduling and pricing processes 
within a region. In particular, we believe that RTO access to region-
wide information on network conditions and power transactions, coupled 
with efficient congestion management and well specified physical and 
financial transmission usage rights, could help RTOs, as regional grid 
managers, in taking preemptive action against curtailment incidents 
that would otherwise be induced by parallel path/loop flow loading of 
critical transmission facilities. We anticipate that parallel path/loop 
flow related disputes will diminish to the extent that RTOs are 
relatively large and able to implement more realistic scheduling and 
pricing procedures that subsume the effect of parallel path/loop flow 
within their regions.
    We propose that measures to address parallel path flow may not 
necessarily be in place on the first day of RTO operation, and propose 
to allow up to three years after start-up for this function to be 
implemented. We seek comment on whether such an additional 
implementation time period is warranted, and whether three years is an 
appropriate additional time period.
4. Function 4: Ancillary Services. An RTO must serve as the supplier of 
last resort of all ancillary services required by Order No. 888, FERC 
Stats. & Regs. para.31,038 (Final Rule on Open Access and Stranded 
Costs), and subsequent orders. (Proposed Sec. 35.34(j)(4))
    In carrying out Function 4, the RTO must satisfy each standard 
discussed below, or demonstrate that an alternative proposal is 
consistent with or superior to satisfying the standard.

a. All market participants must have the option of self-supplying or 
acquiring ancillary services from third parties subject to any general 
restrictions imposed by the Commissions's ancillary services 
regulations in Order No. 888, FERC Stats. & Regs. para. 31,038 (Final 
Rule on Open Access and Stranded Costs), and subsequent orders. 
(Proposed Sec. 35.34(j)(4)(i))

    An RTO is a transmission provider and therefore is subject to the 
general requirements established by the Commission for the provision of 
ancillary services under Order Nos. 888 and 889 and succeeding orders. 
Specifically, these require that the transmission provider must provide 
or cause to be provided six ancillary services on an unbundled 
basis.241 Of the six ancillary services, a transmission 
customer is obligated to purchase two of the services from the 
transmission provider (the RTO)--scheduling, system control and 
dispatch service and reactive supply and voltage control from 
generation. For the remaining four services, a transmission customer 
has the option of self-providing these services, either by acquiring 
them from

[[Page 31425]]

a third party or providing them from the customer's own resources.
---------------------------------------------------------------------------

    \241\ The six ancillary services are: (1) Scheduling, System 
Control and Dispatching Service; (2) Reactive Supply and Voltage 
Control from Generation Sources Service; (3) Regulation and 
Frequency Response Service; (4) Energy Imbalance Service; (5) 
Operating Reserve-Spinning Reservice; and (6) Operating Reserve-
Supplemental Reserve Service. Order No. 888, FERC Stats. & Regs. at 
31,706-17; Order No. 888-A, FERC Stats. & Regs. at 30,227-34.
---------------------------------------------------------------------------

    Our rationale for imposing the ultimate supply obligation on the 
RTO is that not all transmission customers may be equally able to self-
supply (some own generation, others do not) and that in many 
circumstances it may be more efficient (i.e., less costly) for the RTO 
to provide the service for all transmission users on an aggregated 
basis. Our rationale for allowing self-supply is that it provides a 
possible competitive check on the RTO to ensure that it acquires the 
services at lowest cost. In addition, the Commission believes, as a 
matter of policy, that legal monopolies should not be granted (i.e., 
serving as the sole provider of ancillary services) unless they are 
natural monopolies.
    The ancillary services policies in Order Nos. 888 and 889 were 
developed for transmission providers that were generally vertically 
integrated utilities. There was an expectation that they would be able 
to provide many of the generation based ancillary services from their 
own generating resources. An RTO by definition will not own any 
generating resources. Does this difference necessitate a different set 
of ancillary service requirements for RTOs? Are there other ancillary 
services, in addition to scheduling, system control and dispatch, and 
reactive supply and voltage control from generation sources, for which 
the self-supply option should be eliminated? Under what circumstances 
can the RTO's obligation as the ancillary services supplier of last 
resort be eliminated?

b. 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 ancillary service providers 
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. (Proposed Sec. 35.34(j)(4)(ii))

    This policy would, in effect, grant RTOs the exclusive right, 
subject to national and regional reliability norms, to determine the 
quantities and, in some instances, the locations at which certain 
ancillary services must be provided. It would also require that the RTO 
be able to exercise complete operational control, either directly or 
indirectly, over any supplier of ancillary services.
    Direct control (sometimes referred to as hands-on control or actual 
physical operation) would require, for example, that RTO employees 
``push the button'' or that RTO computers send instructions directly to 
generating units or other facilities to take certain physical actions. 
Automatic generation control (AGC) might be one example of direct 
control. If the RTO has direct control, it would have authority, by 
contract or other means, to send direct electronic signals to those 
generators who have offered, in return for a payment, to increase or 
decrease the output of their units in response to the RTO's signals. 
Indirect control (sometimes referred to as functional control, directed 
control or contractual control) requires that the RTO send instructions 
to the owner of the facility who then, in turn, performs the actual 
physical actions to implement these instructions. Indirect control 
usually requires that there be a contractual agreement between the RTO 
and the owner of the facilities that has agreed to provide ancillary 
services.
    The Commission requests commenters to address whether these are 
minimum requirements needed to ensure that the RTO can satisfy its 
obligation to maintain targeted levels of reliability. Would it be 
feasible for the RTO to maintain reliability with less authority?
    In our Midwest ISO order, we stated that the ISO ``* * * should use 
competitive procurement for all services needed to operate the 
system.'' 242 This general requirement would apply to 
ancillary services since they are clearly needed to operate a reliable 
bulk power system. One prerequisite for competitive procurement is a 
competitive market.243 The Commission would anticipate that 
many of the generation-based ancillary services (e.g., balancing and 
reserves) could be acquired in short-term markets that would operate in 
parallel to basic energy markets.244 This has been the 
approach taken by most of the ISOs that we have approved and we see no 
reason why this would be different for transcos or other types of RTO 
entities. Other services such as black start capability and voltage 
support are probably best acquired in long-term markets where potential 
suppliers would compete for the right to enter into a long-term 
contract with the RTO. Apart from establishing the general requirement 
to use competitive markets, the Commission believes that it is best to 
leave many of the detailed market design questions to the individual 
RTOs with case-by-case review by us.245 As we noted earlier, 
we intend to permit regional flexibility and encourage experimentation. 
Such experimentation would be discouraged if we issued regulations that 
are too detailed.
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    \242\ See Midwest ISO, 84 FERC para. 61,231 at 62,164 (1998).
    \243\ However, we recognize that the existence of a competitive 
supply market for ancillary services is no guarantee that the RTO 
will automatically buy efficiently. Therefore, since the RTO may be 
the de facto buyer of many of these services, the Commission is 
receptive to performance-based regulatory proposals that would give 
RTOs explicit incentives to be efficient buyers of ancillary 
services. See section III.F.
    \244\ See Eric Hirst and Brendan Kirby, Unbundling Generation 
and Transmission Services for Competitive Electricity Markets, a 
report prepared for the National Regulatory Research Institute (NRRI 
98-05), January 1998.
    \245\ These would include design issues such as: Are ancillary 
service bids received before, after or at the same time as energy 
market bids? Do ancillary service markets clear simultaneously or 
sequentially? Must the RTO publicly announce the amount of each 
ancillary service that it needs prior to bidding? What do generators 
bid (capacity, energy or both)? If there are multiple bid 
components, are they evaluated together or separately? Should the 
RTO acquire ancillary services from outside its region? These are 
some of the design issues that have arisen in the operation of 
ancillary markets by the California ISO. We expect that there will 
be other design issues as other ancillary market proposals are 
presented to us.
---------------------------------------------------------------------------

    The Commission believes that, whenever it is economically feasible, 
it is important for the RTO to provide accurate price signals that 
reflect the costs of supplying ancillary services to particular 
customers. Accurate price signals are especially important because some 
of the RTO's customers may be competing against each other in other 
power sales markets. It is important that the RTO's actions not distort 
regional power market competition by charging potential competitors 
inaccurate prices for ancillary services that they purchase from the 
RTO.

c. The RTO must ensure that its transmission customers have access to a 
real-time balancing market. 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. (Proposed 
Sec. 35.34(j)(4)(iii))

    Real-time balancing refers to the moment-to-moment matching of 
loads and generation on a system-wide basis. It is a function that 
control area operators must perform to maintain frequency at 60 hz. 
Real-time balancing is usually achieved through the direct control of 
select generators (and, in some cases, loads) who increase or decrease 
their output (or consumption in the case of loads) in response to 
instructions from the system operator. Over the last two years, the 
Commission has seen an increasing use by system operators of market 
mechanisms that rely on bids from generators to achieve

[[Page 31426]]

overall, real-time balancing.246 Since system-wide balancing 
is a critical element of reliable short-term grid operation, we will 
require that it be a responsibility of the RTO. The Commission would 
expect that an RTO will perform the overall system balancing function 
directly if it operates a control area or indirectly if it supervises 
the operation of sub-regional control areas.
---------------------------------------------------------------------------

    \246\ See Pacific Gas & Electric, 81 FERC para. 61,122 (1997), 
Central Hudson, 83 FERC para. 61,352 (1998), NEPOOL, 85 FERC para. 
61,242 (1998); PJM, 81 FERC para. 61,257 (1997).
---------------------------------------------------------------------------

    A separate, but related, issue is balancing by individual grid 
users. The fact that the overall system must be in balance to maintain 
frequency 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. Imbalances are inevitable since generators do 
not exactly meet their schedules and loads always vary from moment-to-
moment.
    As we noted in the Midwest ISO order, unequal access to balancing 
options for individual customers can lead to unequal access in the 
quality of transmission service available to different customers. This 
could be a significant problem for RTOs that serve some customers who 
operate control areas and other customers who do not. Under current 
NERC regulations, control area operators have access to inadvertent 
energy accounts so they can pay back imbalances in kind and thereby 
avoid any penalties.247 In contrast, non-control area 
transmission customers do not have access to such accounts. Instead, 
under the pro forma tariff, load serving entities are subject to a 
deadband and then penalties if the magnitude of their imbalances fall 
outside the deadband. Our concern, as we stated in our Midwest ISO 
order, is that ``nondiscriminatory access would suffer'' under such a 
system.248 Therefore, the Commission proposes to require 
that RTOs operate a real-time balancing market that would be available 
to all transmission customers, or ensure that this task is performed by 
another entity not affiliated with market participants.249
---------------------------------------------------------------------------

    \247\ NERC Operating Manual, at P1-9.
    \248\ Midwest ISO, 84 FERC at 62,155.
    \249\ We have already approved such markets for four ISOs. See 
e.g., PJM Interconnection, L.L.C., Order Accepting In Part and 
Rejecting In Part Proposed Revisions To Rate Schedules, September 
16, 1998 and New England Power Pool, ``Order Conditionally Accepting 
Market Rules and Conditionally Approving Market Based Rates, 85 FERC 
para. 61,379 (1998). These markets generally allow all transmission 
customers to settle their imbalances at real time energy market 
prices. We note that participants in the Midwest ISO have issued a 
request for proposals that could lead to the establishment of such a 
market in their region. See Solicitation of Interest, Creation of an 
Independent Power Exchange for the U.S. Midwest, Joint Committee for 
the Development of a Midwest Independent Power Exchange (Feb. 5, 
1999).
---------------------------------------------------------------------------

    The Commission believes that it is important to give RTOs 
considerable discretion in how such a market would be operated. An RTO 
may choose to operate the market itself or assign the task to another 
entity (e.g., a for-profit exchange) that would operate the market 
under the RTO's supervision. In addition, the Commission would expect 
that the design of such a market will necessarily vary between RTOs 
that operate control areas and those that do not. However, in those 
instances where RTO does not operate a control area, the RTO must be 
especially vigilant that transmission customers who continue to operate 
control areas cannot use that functional responsibility to the 
disadvantage of non-control area customers.\250\
---------------------------------------------------------------------------

    \250\ See Midwest ISO, 84 FERC at 62,159-160.
---------------------------------------------------------------------------

    The Commission invites comments on the use of market mechanisms to 
support overall system balancing and imbalances of individual 
transmission users. Is it feasible to rely on markets to support a 
function that is so time-sensitive? Can such markets be 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?
5. Function 5: OASIS and TTC and ATC. The RTO must be the single OASIS 
site administrator for all transmission facilities under its control 
and independently calculate TTC and ATC. (Proposed Sec. 35.34(j)(5))
    The operation of an OASIS site has many dimensions. For example, it 
includes specific practices and terminology. In response to a consensus 
request from the industry, we recently issued a NOPR that proposes to 
standardize various practices and terms. The focus of that NOPR is on 
standardization of protocols for posting, naming and responding to 
posted information.251 Apart from these practices, the 
central and probably most controversial aspect of OASIS operation is 
the calculation and posting of ATC numbers. The calculation of ATC 
depends, in turn, on the calculation of TTC.252 These 
calculations are different from business practices in that the focus is 
on content rather than procedures and practices. There is widespread 
dissatisfaction with the reliability of posted ATC numbers. The 
Commission has received formal and informal complaints from 
transmission customers stating that they cannot rely on posted ATC 
numbers. Criticisms of posted ATC numbers have also been the subject of 
a widely publicized report issued by a major industry 
group.253 It is been alleged that transmission providers who 
also compete in power markets against their competitors have both the 
incentive and ability to post unreliable ATC numbers.254
---------------------------------------------------------------------------

    \251\ Open Access Same-Time Information System, Notice of 
Proposed Rulemaking, FERC Statutes and Regulations para. 32,531 
(1998).
    \252\ See section III.A.1 for definitions of these terms.
    \253\ Commercial Practices Working Group and the OASIS How 
Working Group, ``Industry Report to the Federal Energy Regulatory 
Commission on the Future of OASIS, October 31, 1997.
    \254\ This is discussed more fully in Section III.A.
---------------------------------------------------------------------------

    We recognize that an individual transmission provider may post ATC 
numbers on OASIS in good faith only to find that the projected 
capability does not exist because of scheduling decisions taken by 
other transmission providers elsewhere on the grid. In such 
circumstances, transmission providers are not acting unscrupulously. 
Instead, the problem is simply a mismatch between information flows and 
electrical flows. Regional transmission organizations that perform ATC 
calculations based on complete and timely information would tend to 
eliminate this problem. This seems to be supported by fact that the 
Commission has received very few complaints about ATC calculations made 
by ISOs.
    The essential feature of our proposed requirement is that the RTO 
become the administrator of a single OASIS site for all transmission 
facilities over which it is the transmission provider. This is 
consistent with earlier orders.255 Moreover, every ISO that 
we have approved so far has become the OASIS site administrator for the 
customers that it serves. However, we recognize that this generally 
stated requirement inevitably raises questions as to the level of RTO 
involvement in ATC calculations. An RTO could be involved in ATC 
calculations at three general levels. At Level 1, the RTO's role would 
be limited to receiving and posting ATC numbers received from 
transmission owners. At Level 2, the RTO would receive raw data from 
transmission

[[Page 31427]]

owners and centrally calculate ATC values. At Level 3, the RTO would 
centrally calculate ATC values on data partially or totally developed 
by the RTO. The proposed requirement that the RTO be the OASIS site 
administrator is based on the expectation that the RTO will operate at 
Level 3.
---------------------------------------------------------------------------

    \255\ In the Primergy merger order, we required that the 
proposed ISO should be ``responsible for calculating ATC.'' See 
Primergy, 79 FERC para. 61,158, May 14, 1997.
---------------------------------------------------------------------------

    The RTO must eventually operate at Level 3 to ensure that ATC 
values are based on accurate information that is based on consistent 
assumptions and to minimize the opportunities for conscious 
manipulation. In general, the RTO must perform all the calculations and 
studies necessary to develop the underlying data. When data are 
supplied by others, the RTO must create a system for regularly 
validating the data for accuracy and assumptions. If there is a dispute 
over ATC values, the RTO's values should be used pending the outcome of 
the dispute resolution process.256 The RTO must also 
establish the operating standards (subject to regional and national 
reliability requirements) underlying the ATC calculations.
---------------------------------------------------------------------------

    \256\ This is the same requirement that the Commission imposed 
on the Midwest ISO. See Midwest ISO, 84 FERC at 62,154.
---------------------------------------------------------------------------

6. Function 6: Market Monitoring. The RTO must monitor markets for 
transmission services, ancillary services and bulk power to identify 
design flaws and market power and propose appropriate remedial actions. 
(Proposed Sec. 35.34(j)(6))
    In carrying out Function No. 6, the RTO must satisfy each standard 
discussed below, or demonstrate that an alternative proposal is 
consistent with or superior to satisfying the standard.

    a. The RTO must monitor markets for transmission service and the 
behavior of transmission owners, if any, to determine if their 
actions hinder the RTO in providing reliable, efficient and 
nondiscriminatory transmission service. (Proposed 
Sec. 35.34(j)(6)(i))
    b. The RTO must monitor markets for ancillary services and bulk 
power. This obligation is limited to markets that the RTO operates. 
(Proposed Sec. 35.34(j)(6)(ii))
    c. The RTO must periodically assess how behavior in markets 
operated by others (e.g., bilateral power sales markets and power 
markets operated by unaffiliated power exchanges) affects RTO 
operations and conversely how RTO operations affect the performance 
of power markets operated by others. (Proposed 
Sec. 35.34(j)(6)(iii))

    The RTO's role as market monitor. To date, the Commission has found 
monitoring to be essential in helping to ensure non-discrimination and 
efficiency in the provision of transmission and ancillary services; 
encourage fair, open, and competitive energy markets; and promote 
overall operating efficiency. 257 As we stated in the New 
England ISO order, ``markets are likely to evolve in ways that may not 
be totally anticipated. To ensure that the markets operate 
competitively and efficiently, it is important that any problems 
involving market power or market design are quickly identified so that 
appropriate solutions can be crafted.'' 258 To date, we have 
been willing to use ISOs, or their independent monitoring 
organizations, as a ``first line of defense'' in detecting both market 
power abuses and market design flaws.
---------------------------------------------------------------------------

    \257\ Pacific Gas & Electric, 81 FERC at 61,552; PJM, 81 FERC at 
62,282; NEPOOL, 85 FERC at 62,479-480; Midwest ISO, 84 FERC at 
62,180-181.
    \258\ New England ISO, 85 FERC para. 62,379 at 62,479-480 
(1998).
---------------------------------------------------------------------------

    The proposed requirements are arguably based on the presumption 
that an RTO will be a non-profit, system operator that does not own any 
facilities. The requirements may not be appropriate for a for-profit 
transco that owns the facilities that it operates.259 
Therefore, a threshold question is: what should be the market 
monitoring role, if any, of an independent, for-profit transco? Is it 
reasonable to expect that such an RTO could be objective in its 
assessments? If the RTO is an ISO, do its monitoring activities need to 
be further insulated to ensure independence and objectivity? For 
example, should monitoring be performed by one or more individuals or 
organizations that are funded by the RTO but that have the right to 
issue reports without the RTO's approval?
---------------------------------------------------------------------------

    \259\ We note that at least one entity that is contemplating the 
creation of a for-profit transmission company has proposed that this 
company would perform a market monitoring function. See Statement of 
Mr. Frank Gallaher on behalf of Entergy Corporation, Regional ISO 
Conference (New Orleans), transcript at 18.
---------------------------------------------------------------------------

    The Commission believes that RTOs that are ISOs have a significant 
comparative advantage over other entities in monitoring 
markets.260 First, RTOs have access to considerable 
information about market conduct and performance. For example, we would 
expect that an RTO, in the normal course of business, will develop or 
receive information on quantities of bulk power and transmission 
services bought and sold by different market participants, expected and 
real time transmission system conditions, planned maintenance of both 
generation and transmission facilities and anticipated and real time 
patterns of load and generation. Second, RTOs will be completely 
independent of all market participants. For these reasons, the 
Commission believes that we and our colleagues in state commissions can 
have great confidence in the RTO market assessments.261 Our 
early experience with market assessments performed by the New England 
and California ISOs has been encouraging. The assessments have been 
comprehensive and objective even to the point of criticizing past 
actions by the ISOs themselves.262
---------------------------------------------------------------------------

    \260\ See Midwest ISO, 84 FERC at 62,181.
    \261\ The early experience with market assessments in California 
and New England seems to support this conclusion. See AES Redondo 
Beach, et al., 85 FERC para. 61,123 at 61,462 (1998).
    \262\ See Peter Cramton and Robert Wilson, A Review of ISO New 
England's Proposed Market Rules, Docket No. ER97-1079, September 9, 
1998, and the California ISO Market Surveillance Committee's 
Preliminary Report On the Operation of the Ancillary Services 
Markets., Docket No. ER98-2843, August 19, 1998 Markets.
---------------------------------------------------------------------------

    Despite the advantages of better information and incentives, the 
Commission believes that it is neither fair nor feasible to impose a 
monitoring obligation on RTOs for markets that they do not operate. Our 
preliminary assessment is that it would be difficult for an RTO to 
monitor a market in which it does not have information on prices, 
bidding patterns and marginal costs. However, our experience with ISOs 
has shown that markets for power, ancillary services and transmission 
service are inextricably intertwined regardless of how they are 
organized or who operates them.263 Therefore, we are 
proposing a middle ground for monitoring regional markets not operated 
by the RTO. The RTO's monitoring of markets operated by others will be 
limited to assessing how behavior in these markets affects RTO markets 
and operations and conversely how RTO markets and operations affect 
these other markets.
---------------------------------------------------------------------------

    \263\ See AES Redondo Beach, et al., 85 FERC para. 61,123 at 
61,453 and 61,459-460 (1998).
---------------------------------------------------------------------------

    The Commission also recognizes that any markets, whether operated 
by the RTO or others, will inevitably be affected by basic structural 
characteristics such as the existing pattern of ownership and control 
of generation and transmission facilities. Such characteristics are 
often beyond the control of the RTO. Since our overarching goal in 
promoting RTOs is to promote fair, open and competitive electricity 
markets, we and our state commission colleagues need to understand how 
these structural features affect the potential for competition. 
Therefore, we propose to require RTOs to provide periodic assessments 
as to the effect of existing structural conditions on the 
competitiveness of their region's

[[Page 31428]]

electricity markets. Of all the industry organizations that may exist 
in a region, we think that an RTO is best suited to make this 
assessment because of its first hand knowledge of day-to-day grid and 
generation operations and its independence.
    The Commission requests comments on several threshold issues 
related to these proposed market monitoring requirements. Some argue 
that RTOs should not be charged with any monitoring responsibilities 
particularly with respect to market power abuses.264 They 
argue that the antitrust laws and the Commission offer sufficient 
protection against competitive abuses. Others have argued that RTOS are 
somewhat akin to organized stock exchanges and that the Commission 
should follow the SEC precedent of requiring extensive and 
sophisticated market monitoring by all of the organized exchanges. Are 
there features of electricity and transmission markets that argue for 
imposing similar market monitoring responsibilities on RTOs?
---------------------------------------------------------------------------

    \264\ See, e.g., David B. Raskin, ISOs; The New Antitrust 
Regulators? The Electricity Journal (April 1998).
---------------------------------------------------------------------------

    If the Commission decides to require RTOs to provide some form of 
market monitoring, there are several other questions that arise. Should 
the Commission rely on RTOs as the ``first line of defense'' for 
detecting both design flaws and market power abuses? If this were our 
approach, what would be an appropriate role for the Commission in 
market monitoring? If the RTO is operating one or more markets (e.g., 
ancillary services), is it reasonable to expect that it can perform an 
objective self-assessment? Is there a difference in the market 
monitoring that the Commission can expect from RTOs? For example, if 
the RTO proposes to take a market position in secondary transmission 
rights, is it plausible to expect that the RTO can perform an objective 
assessment of this market? Since the success of retail competition will 
often depend critically on the actions of RTOs, what should be the role 
of state commissions in market monitoring?
    Scope of monitoring activities: design flaws. In observing the 
experience of ISOs over the last year, we have learned that new market 
designs almost inevitably include design flaws that become apparent 
only after the markets begin operation.265 Often these 
problems arise because of unexpected interactions between different 
related markets and unanticipated incentives for buyers and sellers. 
Electricity market restructuring in other countries has also 
experienced the need to make many revisions to market designs and 
rules.266 These experiences indicate that monitoring is 
essential to ensure that the markets and structures evolve to ensure 
just and reasonable rates to consumers. The Commission recognizes that 
market monitoring can be expensive. We would welcome estimates of the 
amount of money spent by ISOs to monitor markets and their assessments 
as to whether they will need to spend more or less money in the future.
---------------------------------------------------------------------------

    \265\ For example, the ancillary services markets in the summer 
of 1998 in California behaved at odds with what one would expect in 
an efficient market. The California ISO market surveillance 
committee produced an extensive evaluation of this problem which led 
to discussions of possible solutions.
    \266\ See, e.g., James Barker, Jr., Bernard Tenenbaum, and Fiona 
Wolfe, ``Governance and Regulation of Power Pools and System 
Operators: An International Comparison,'' Energy Law Journal, Volume 
18, 1997, at 308-309.
---------------------------------------------------------------------------

    Scope of monitoring activities: market power abuses. As we have 
noted before, it is often difficult to predict whether certain entities 
will have market power in the future. This is especially true in new 
markets which operate with new participants and new transmission flow 
patterns. In situations like this, the past is often not a very good 
predictor of the future. As a consequence, the Commission has found 
that in certain situations the better approach is to institute an 
effective monitoring plan rather than to debate numerous assumptions 
and projections that inevitably underlie competing market power 
analyses.267 For abuses that arise from market power, should 
the RTO's role be limited to detecting and describing the abuses? In 
the case of localized market power (e.g., generating units that must 
run for reliability reasons), should the RTO have the authority to take 
corrective actions? If the market power has structural causes, what 
role should the RTO have in developing structural solutions? Should 
RTOs that are ISOs be required to make regular assessments as to 
whether they have sufficient operational authority?
---------------------------------------------------------------------------

    \267\ Pacific Gas & Electric, 77 FERC para. 61,265 (1996). 
NEPOOL, 85 FERC para. 61,379 (1998).
---------------------------------------------------------------------------

    Sanctions and penalties. The Commission seeks comment on whether 
RTOs should be allowed to impose penalties and sanctions. Should the 
penalties be limited to violations of RTO rules and procedures? Should 
the RTO be allowed to impose penalties for the exercise of market 
power? How much discretion should the RTO have in setting penalties? 
For example, should the RTO's penalty authority be limited to 
collecting liquidated damages?

    d. The RTO must provide reports on market power abuses and 
market design flaws to the Commission and affected regulatory 
authorities. The reports must contain specific recommendations about 
how observed market power abuses and market flaws can be corrected. 
(Proposed Sec. 35.34(j)(6)(iv)).

    In order for regulatory agencies, interested parties and the 
general public to benefit from monitoring activities, regular reporting 
of findings is critical. Other than this general requirement, we do not 
propose at this time to establish detailed standards on the format, 
length and content of monitoring reports. We think that these decisions 
are best left to the RTO.
    Should this reporting requirement be limited to producing reports 
only when a specific problem is encountered? Or should RTOs be required 
to make periodic reports that assess the state of competition and 
transmission access even in the absence of specific problems? We note 
that the California and New England ISOs have committed to producing 
annual public reports. Arguably such reports give market participants 
and others a regular opportunity to say whether they agree or disagree 
with the RTO assessment. Also, it is conceivable that such reports 
would be helpful to any market monitoring activities that this 
Commission and state commissions may wish to pursue in the future.
7. Function 7: Planning and Expansion. The RTO must be responsible for 
planning necessary transmission 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. (Proposed Sec. 35.34(j)(7))
    In carrying out Function 7, the RTO must satisfy each standard 
discussed below, or demonstrate that an alternative proposal is 
consistent with or superior to satisfying the standard.

    a. The RTO planning and expansion process must encourage market-
driven operating and investment actions for preventing and relieving 
congestion. (Proposed Sec. 35.34(j)(7)(i))

    RTOs should be designed to promote efficient usage and efficient 
expansion of their regional grids. The former requires efficient price 
signals, such as congestion pricing; the latter requires control over 
planning and expansion. Our specific proposal is that the RTO should 
have ultimate responsibility for both transmission planning and 
expansion within its region.268 This

[[Page 31429]]

requirement is motivated by the fact that investments in new 
transmission facilities must be coordinated to ensure a least cost 
outcome that maintains or improves existing reliability levels. In the 
absence of a single entity with overall responsibility, there would be 
danger that transmission investments would work at cross-purposes and 
possibly even hurt reliability. We recognize that the RTO's 
implementation of this general requirement will require addressing many 
specific design issues.269 Once again, we propose to give 
RTOs considerable flexibility in designing a planning and expansion 
process that works best for its region. We recognize that the specific 
features of this process must take account of and accommodate existing 
institutions and physical characteristics of the region.
---------------------------------------------------------------------------

    \268\ Investments in new transmission facilities might be needed 
for a variety of reasons such as interconnecting new generation or 
load, protecting or enhancing system reliability, improving system 
operating efficiency and flexibility, reducing or eliminating 
congestion and minimizing the need for ``must-run'' contracts with 
one or more generators.
    \269\ Our experience with regional transmission groups suggests 
that the following issues, among others, will need to be addressed: 
Who establishes the planning criteria? Who sets the design criteria? 
Should they be uniform across the system or vary with location? Who 
can initiate studies for transmission investments? Who evaluates and 
publishes different options? Who recommends which projects should be 
built and how the costs and benefits of the project should be 
allocated?
---------------------------------------------------------------------------

    Within these constraints, the Commission has a clear preference for 
market-driven operating and investment actions for preventing and 
relieving congestion.270 However, we understand that the 
feasibility of obtaining market driven solutions requires satisfying 
other prerequisites. For example, transmission prices must accurately 
reflect existing patterns of congestion. Accurate congestion prices are 
the link between current usage and future expansion. Therefore, we 
place considerable emphasis on the need for RTOs to establish a system 
of congestion management that establishes clear rights for existing and 
new transmission facilities and price signals that reflect congestion. 
(See section III.F) Independent governance is also a necessary 
condition for efficient expansion. While accurate price signals can 
signal the need for expansion, such expansion may never be achieved if 
the RTO operates under a faulty governance system (e.g., a governance 
system that allows market participants to block expansions that will 
hurt their commercial interests).

    \270\ This is a topic that has been discussed widely within the 
industry. See, e.g., the papers of Steven L. Walton, Indego 
Transmission Expansion Strategy, Steven Stoft, Five Things You 
Should Know About Grid Investment and Ray Coxe, New Paradigms for 
Siting Transmission in Competitive Electric Markets. These papers 
are available through the Harvard Electric Policy Group website 
http://ksgwww.harvard.edu/hepg.
---------------------------------------------------------------------------

b. The RTO'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 RTO's planning and 
expansion process must be coordinated with programs of existing 
Regional Transmission Groups (RTGs) where necessary. (Proposed 
Sec. 35.34(j)(7)(ii))

    At present, certification and siting of new transmission facilities 
is almost always performed by a state agency, typically the public 
utilities commission, in the state in which the facility will be 
located.271 While there have been discussions about the need 
for regional certification and siting since most new transmission lines 
are integral elements of a regional grid system, such proposals have 
met with little success.272 With the growth of RTOs, this 
could conceivably change. The emergence of a single regional 
transmission organization on the industry side may encourage the 
development of regional organizations or agreements that deal with 
transmission siting and certification on the regulatory side. The 
Commission believes that this would be a positive development if it is 
a voluntary decision of the affected states and replaces existing 
state-by-state determinations that often lack a regional perspective. 
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 future emergence of a regional regulatory 
system.
---------------------------------------------------------------------------

    \271\ See Ileana Elsa Garcia, State Electric Facility Siting 
Practices, prepared for the Harvard Electric Policy Group (HEPG), 
April 10, 1997. Available through the HEPG website at http://
ksgwww.harvard.edu/hepg.
    \272\ See NARUC, ``Options for Jurisdiction over Transmission 
Facility Siting,'' a resource document for the NARUC Committee on 
Electricity, 1991 and Charles D. Gray, NARUC Assistant General 
Counsel, Memorandum, January 1995. Available through the HEPG/
website at http://ksgwww.harvard.edu/hepg.
---------------------------------------------------------------------------

    The Commission recognizes that regional transmission planning in 
some areas is being performed to varying degrees by RTGs.273 
It would be inefficient for RTOs initially to replicate the efforts of 
RTGs. Therefore, we require that RTOs discuss their planning and 
expansion with existing RTGs. However, over time, we would expect that 
the RTG's planning process would become an RTO function and the need 
for such coordination would be reduced or eliminated.
---------------------------------------------------------------------------

    \273\ The Commission has approved RTGs for the New England Power 
Pool, et al., 83 FERC para. 61,045 (1998), Mid-Continent Area Power 
Pool, 76 FERC para. 61,261 (1996), Northwest Regional Transmission 
Association, 71 FERC para. 61,397 (1995), Western Regional 
Transmission Association, 71 FERC para. 651,158 (1995), and 
Southwest Regional Transmission Association, 69 FERC para. 61,100 
(1994).
---------------------------------------------------------------------------

c. If the Regional Transmission Organization is unable to satisfy this 
requirement 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. 
(Proposed Sec. 35.34(j)(7)(iii))

    We recognize that establishing an efficient procedure for 
transmission planning and expansion may require coordination and 
agreements among multiple parties and regulatory jurisdictions, and 
that this may take some time to accomplish. Accordingly, we do not 
propose that an RTO be capable of performing this function on its first 
day of operation. We do expect, however, that RTO proposals contain at 
least a plan explaining how the RTO intends to work toward implementing 
this function. Such a plan should set forth milestones that will result 
in this function being performed within three years after initial 
operation. We seek comment on whether three years is an appropriate 
amount of time for implementation of this function.

E. Open Architecture

    The Commission believes that RTOs hold great promise in 
accomplishing our goal of promoting competition in regional wholesale 
electricity markets. That is why we want to accelerate their 
development. We understand that there are many difficult 
organizational, technical, and policy issues that must be addressed in 
realizing proposals, and that markets are evolving quickly and possibly 
in ways that cannot be foreseen at the time of RTO organization. 
Further, the nature of the institutions supporting the markets may 
change over time as well.
    For these reasons, the Commission will require that RTO design have 
the ability to evolve over time. The Commission is committed to a 
policy of ``open architecture.'' Simply put, open architecture requires 
that there be no provision in any RTO proposal that precludes the RTO 
and its members from improving their organizations to meet market 
needs. The Commission will provide the regulatory flexibility to allow 
such evolution.
    Under open architecture, an RTO should be able to evolve in several 
ways, as long as it continues to satisfy the minimum RTO 
characteristics and

[[Page 31430]]

functions. For example, open architecture would allow basic changes in 
the organizational form of the RTO. An RTO that initially does not own 
any transmission facilities might acquire ownership of some or all of 
those facilities. The RTO's enabling agreements should at best 
anticipate and facilitate such a change, but at minimum should not 
prevent it or make it more difficult than necessary.
    Market trading patterns, technological change, and changes in 
corporate strategies will make changes in RTO membership inevitable and 
desirable. Accommodating change will require flexibility and 
adaptability in the RTO organization and open architecture will permit 
this.
    Market support and operations is another RTO dimension that could 
benefit from open architecture. For example, an RTO may not initially 
operate a PX to support a regional spot market, but if RTO members 
later find that a PX would help the region, the RTO could propose to 
add the PX function as well as a PX market monitoring function. It is 
important that the basic RTO agreement not close off such development. 
Our proposed open architecture policy will ensure that such future 
development is not foreclosed.
    The Commission is interested in receiving comments regarding an 
open architecture policy to ensure that initial RTOs can develop. What 
flexibility needs to be built into RTO contracts? What regulatory 
flexibility is needed from the Commission as part of an open 
architecture policy? In which areas of RTO organization or operations 
is it especially important for the Commission to expect improvement?

F. Ratemaking for Transmission Facilities Under RTO Control

    The Commission expects RTOs to reform transmission pricing, and in 
return we propose to allow RTOs greater flexibility in designing 
pricing proposals. In 1994, the Commission issued its Transmission 
Pricing Policy Statement encouraging transmission pricing reform and 
setting out standards to be used to evaluate innovative transmission 
pricing proposals.274 In the Transmission Pricing Policy 
Statement the Commission allowed ``substantial flexibility'' to be 
given to RTGs in justifying non-conforming proposals. The Commission 
allowed this because RTGs represent the combined interests of 
transmission owners, users and state authorities and because pricing 
proposals for treating loop flow problems work better if all utilities 
in the region use the same method.
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    \274\ The Policy Statement sets out five principles that 
transmission pricing proposals should conform to: meet the 
traditional revenue requirement; reflect comparability (open access 
tariff); promote economic efficiency; promote fairness; and be 
practical. The Policy Statement requires non-conforming proposals to 
satisfy additional factors: promote competitive markets and produce 
greater overall consumer benefits. Overall consumer benefits are 
measured principally by greater access and customer choice, 
projected price decreases to power customers, and service 
flexibility and products to meet customer needs.
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    In this section, we discuss a number of areas in which we expect 
RTOs to provide innovative pricing and in which the Commission may be 
expected to allow flexibility. We seek comments on the issues discussed 
and other RTO pricing issues.
1. Single Transmission Access Rate for Capital Cost Recovery
    One issue in ISO proposals that have come before the Commission is 
the recovery of transmission capital costs through a single access 
rate. Under such a rate, the capital costs of all RTO members would be 
averaged, resulting in a rate that is higher than the individual system 
rate for relatively low-cost transmission systems and lower than the 
rate for high-cost transmission systems. This can cause two kinds of 
``cost-shifting'' concerns: high-cost transmission providers are 
concerned about cost recovery, and customers of the low-cost providers 
are concerned about increased rates.
    Transmission cost shifting has been an issue in every ISO the 
Commission has approved to date, and we have allowed a flexible 
approach to resolving the issue. In each of those cases, we have 
allowed a transition period of between five and ten years during which 
access fees are based on some form of ``license plate'' pricing: access 
fees are paid by load serving entities based on the fixed transmission 
costs of the local utility.275
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    \275\ See, e.g., Order Directing Amendments to Proposals to 
Restructure the Pennsylvania-New Jersey-Maryland Interconnection and 
Providing Guidance, 77 FERC para. 61,148 at 61,577 (addressing 
concerns about cost-shifting between high- and low-cost transmission 
providers).
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    We propose to continue our flexibility in allowing the recovery of 
current sunk transmission costs as transition mechanisms to single 
rates if proposed by RTOs, including the license plate approach as well 
as others. We request comment regarding whether the license plate 
approach to fixed cost recovery is an appropriate long-term measure.
2. Congestion Pricing
    As discussed in prior sections, managing regional congestion is one 
of the problems that an RTO can help solve. We believe that efficient 
congestion management requires a greater reliance on market mechanisms 
276 and this can be effectively accomplished with price 
signals. We propose to allow RTOs considerable flexibility in 
experimenting with different market approaches to managing congestion 
through pricing. 277 Proposals should, however, 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.278
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    \276\ See NERC, 85 FERC at 62,364.
    \277\ This is consistent with our Transmission Pricing Policy 
Statement's allowance of substantial flexibility to pricing 
proposals from RTGs because RTGs are comprised of broad membership 
to facilitate transmission access, develop a comprehensive regional 
plan for transmission expansion, share transmission information and 
provide for dispute resolution. 64 FERC 61,138 (1993). RTOs possess 
these same characteristics.
    \278\ Transmission Pricing Policy Statement, FERC Stats. & Regs. 
at 31,140-44.
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    The Commission intends to be flexible in reviewing pricing 
innovations, and we ask for comments as to what specific requirements, 
if any, may best suit our RTO goals.
3. Performance Based Rate Regulation
    Once RTOs are formed, the Commission is interested in finding ways 
to ensure their satisfactory performance. One way to induce good grid 
operation by an RTO is through performance-based regulation, or PBR. 
PBR may consist of price/revenue caps, price incentives, or performance 
standards.279 Performance-based regulation identifies 
factors of good performance such as efficient congestion management, 
lowering operator costs, and meeting reliability targets. Great care 
must be taken in selecting the performance factors. RTOs should have a 
reasonable chance of meeting or exceeding the performance targets, but 
the targets must not be too easy to meet. We would reward only 
performance that is truly superior to that which individual 
transmission owners could achieve outside an RTO.
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    \279\ See Incentive Ratemaking for Interstate Natural Gas 
Pipelines, Oil Pipelines, and Electric Utilities, Policy Statement 
on Incentive Regulation, 61 FERC para. 61,168 at 61,590-92 (1992), 
and L. Brown, Michael Einhorn, and Ingo Vogelsang, Incentive 
Regulation: A Research Report (1989).
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    The Commission seeks comments on applying PBR to RTOs. Should PBR 
be voluntary or applied to all RTOs? What degree of regulatory scrutiny 
would a PBR regime require? In addition, the Commission seeks comment 
on the specifics of how PBR would be applied

[[Page 31431]]

effectively to an RTO. For productivity incentives, what productivity 
objectives should be adopted and how should productivity be measured? 
How would a revenue cap or a price cap be set? What intermediate 
adjustments to the cap should be allowed? How often should base costs 
be examined?
4. Consideration of Incentive Pricing Proposals
    RTOs would bring extensive benefits to North American electricity 
markets and would further the objectives of sections 202(a), 205 and 
206 of the FPA. We would be willing to consider, on a case by case 
basis, allowing the transmission owners that bring about those benefits 
to share in them through incentive pricing for public utility 
transmission owners that turn over control of their transmission 
facilities to an RTO.280 RTOs would be expected to propose 
and justify specific proposals on a case-by-case basis.
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    \280\ As discussed above in section III-B, there are also a 
number of non-pricing regulatory benefits that could be offered to 
RTO members, such as deference in dispute resolution, reduced or 
eliminated codes of conduct, and streamlined filing and approval 
procedures.
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    One potential treatment that could be considered is allowing 
transmission owners that participate in RTOs to receive a higher return 
on equity (ROE) on transmission plant than under current policy because 
a transmission owner participating in an RTO puts its grid to a higher 
valued use than one operating individually. This relates the incentive 
to the benefit produced by the RTO. The simplest way to create a higher 
ROE is to share the benefits of an RTO between transmission owners and 
customers. Alternatively, a higher ROE could be implemented by either 
allowing an ROE at the high end of the zone of reasonable returns for 
RTO participants and an ROE in the current range for non-participants. 
Is it appropriate to allow a higher ROE as a means of sharing the 
benefits created by RTOs or should higher ROEs be limited only to 
increases in risk? Is the risk of transmission capital recovery 
increased or decreased by transferring transmission facilities to an 
RTO from a vertically integrated firm?
    With improved grid operation and investment in new facilities to 
relieve constraints, RTOs may lower grid operating costs. Another 
incentive that could be considered would be to keep transmission rates 
at current levels and allow participating RTO transmission owners to 
keep the benefits from cost savings over time or to lower transmission 
rates partly while owners keep part of the benefits. Would such 
treatment encourage better performance?
    The Commission could also consider flexibility in cost recovery for 
RTO participation. The capital cost of transmission plant is normally 
recovered over a relatively long time period. RTO participants could be 
allowed accelerated recovery for the costs of transmission expansion. 
Similarly, the recovery of capital start-up costs of RTO participation 
could be accelerated as well. Is it appropriate to allow such 
accelerated recovery as an incentive to transfer transmission 
facilities to an RTO or should capital recovery periods continue to be 
based on the useful life of transmission facilities? Is industry 
restructuring and the potential introduction of distributed generation 
technology likely to affect the risk associated with transmission 
investment recovery periods?
    The Commission may also be willing to consider non-traditional 
methods for valuing transmission assets that are under the control of a 
RTO. The Commission's traditional ratemaking policy values assets at 
original cost, less depreciation. One alternative may be for rate base 
to reflect a higher valuation through some measure of replacement cost. 
Where an RTO or other independent owner purchases transmission assets 
and pay a price that reflects such an enhanced valuation of assets, the 
Commission may want to consider allowing the RTO to include in its 
rates an acquisition premium that reflects the enhanced value.
    The Commission might also consider flexibility in allowing 
levelized or non-levelized rate methods. Both methods can produce 
reasonable results in particular circumstances, especially when one 
method is used consistently throughout the life of a utility's 
facilities. The Commission has, however, been reluctant to allow 
switching from a non-levelized to a levelized rate design during the 
life of a facility. The Commission's current policy is that a utility 
must prove that switching methods is reasonable in light of its past 
recovery of capital.281 The Commission could consider 
granting some latitude for RTO pricing proposals for levelized rate 
cost recovery.
---------------------------------------------------------------------------

    \281\ See Consumers Energy Company, 85 FERC para. 61,100, at 
61,366-367, 1998); Kentucky Utilities Company, 85 FERC para. 61,274, 
at 62,103-105 (1998).
---------------------------------------------------------------------------

    The Commission seeks comments on whether to entertain case-by-case 
proposals of rate incentive treatments for RTO participants. Will 
transmission owners respond to incentives, and will incentives be 
sufficient to achieve our objective of RTO formation? Which incentives 
are most likely to be successful in so doing? Are there specific forms 
of incentive pricing that are inappropriate and problematic? Are 
safeguards needed if the Commission decides to allow incentive 
treatments? In justifying a proposed rate treatment, should an RTO be 
required to demonstrate that its benefits are likely to outweigh the 
pecuniary ``costs'' of the proposal? Would certain incentive pricing 
encourage RTOs to favor capital-based resource decisions (at the 
expense of more efficient alternatives) or to favor transmission 
solutions over alternative ways of relieving particular transmission 
constraints? We also seek comment on whether and how public power 
transmission owners that participate in RTOs could benefit from 
flexible ratemaking and incentive pricing treatments.
    Finally, our willingness to consider incentive pricing proposals is 
conditioned on an RTO meeting all of the proposed minimum 
characteristics and functions. Allowing any incentive pricing to RTO 
participants is based on a sharing of the extensive benefits that an 
RTO brings to electricity markets. Only an RTO that meets the minimum 
characteristics and functions can produce such extensive benefits, and 
it would be inappropriate for the Commission to consider incentive 
pricing to members of an RTO that falls short. We would, however, be 
open to considering other innovative transmission rate treatments, such 
as providing service at non-pancaked rates and regional congestion 
management proposals, for an organization that does not meet all of the 
minimum RTO characteristics and functions.

G. Public Power Participation in RTOs

    The Commission's objective of encouraging all transmission owning 
entities in the Nation to place their transmission facilities under the 
control of an RTO includes transmission owned or controlled by public 
power entities [e.g., municipals, cooperatives, Federal Power Marketing 
Agencies (PMAs), Tennessee Valley Authority (TVA), and other state and 
local entities]. We are aware that some public power entities have 
filed open access tariffs with the Commission and others are 
participating in ISOs and other regional institutions. We also are 
aware, however, that many public power entities may face several 
difficult issues regarding RTO participation. The Commission is 
concerned about any obstacle to public power participation in the 
formation and successful operation of any form of RTO. Accordingly, we 
request comments that identify issues that

[[Page 31432]]

public power entities and others face regarding RTO participation and 
that suggest ways the Commission might facilitate their resolution. We 
expect public power entities to fully participate in the proposed 
collaborative process for forming RTOs after our Final Rule is issued, 
as discussed in section III-I below.
    One issue is the Internal Revenue Service (IRS) Code ``private 
use'' restrictions on the transmission facilities of public power 
entities financed by tax-exempt bonds. 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 they 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.282 In addition, there is uncertainty regarding what 
may happen after the temporary regulations expire on January 22, 2001.
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    \282\ See Uncrossing the Wires, Transmission in a Restructured 
Market, a report by The Large Public Power Council, December 1998, 
at 10.
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    We solicit 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. What impact would IRS Code restrictions have on 
public power participation in other forms of an RTO? While IRS Code 
restrictions might prevent issue of additional tax-exempt bonds for 
transmission expansions made in accordance with RTO participation, are 
non-tax exempt forms of financing a viable option for public power 
participation in selected transmission additions?
    In addition to private use restrictions, are there other 
restrictions on public power institutions that may limit their 
participation in RTOs? For example, to what extent would state or local 
charter limitations, prohibitions on participating in stock-owning 
entities, or the current policies of various local regulatory entities 
affect or impede full public power participation in RTOs? Are there 
some forms of associate membership or participation in RTOs, or other 
special accommodations, that the Commission should consider to make it 
more feasible for public power entities to overcome obstacles to 
participation in RTOs?
    The Commission seeks comment on legal restrictions or other 
considerations regarding the PMAs that prevent their participation in 
RTOs. For example, Bonneville Power Administration and other entities 
in the Pacific Northwest may face unique circumstances that may affect 
RTO formation in that area. These include the design of the power and 
transmission system for the production of hydroelectric energy 
involving the 1961 Columbia River Treaty, the Bonneville Project Act, 
the Federal Columbia River Transmission System Act, the Pacific 
Northwest Electric Power Planning and Conservation Act of 1980, and the 
Northwest Preference Act. There may also be obstacles to TVA 
participation in an RTO. How can the Commission help overcome any such 
limiting factors to full RTO formation?

H. Other Issues

    The Commission seeks comment on a number of other issues regarding 
RTO participation. These issues are presented in this section.
1. Pre-existing Transmission Contracts
    What is the appropriate treatment of existing transmission 
agreements when an RTO is formed? In Order Nos. 888 and 888-A, we 
specifically chose not to abrogate existing requirements and 
transmission contracts when the utility filed an open access 
tariff.283 However, an RTO represents an entirely different 
context. We must balance the need for a uniform approach for 
transmission pricing and the elimination of pancaked rates--one of the 
principal benefits of an RTO--with the need to recognize the equities 
inherent in existing transmission contracts. The potential financial 
impact of giving up an advantageous transmission arrangement may act as 
a disincentive to joining an RTO.
---------------------------------------------------------------------------

    \283\ See Order No. 888 at 31,664-65; Order No. 88-A at 30,181, 
30,199; clarified, 76 FERC at 61,027; Order No. 888-B, 81 FERC at 
62,072, 62, 090, 62,100.
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    In the ISO filings that we have acted on to date, we have evaluated 
various ``transition plans'' regarding existing contracts on a case-by-
case basis.\284\ At this juncture, we do not intend to resolve this 
issue generically but instead propose to confine our policy to 
addressing this issue on an RTO-by-RTO basis. We solicit comments on 
this approach. How critical is this concern to transmission owners' and 
others' decisions on whether to support RTO formation? Is the financial 
impact of giving up an advantageous transmission arrangement 
significant enough to act as a disincentive to RTO membership?
---------------------------------------------------------------------------

    \284\ See PJM, 81 FERC at 62,280-81; Midwest ISO, 84 FERC at 
62,169-70 and order on reh'g, 85 FERC at 62,418-20 (1998); Pacific 
Gas & Electric, 777 FERC at 61,821, 81 FERC at 61,470-71; NEPOOL, 83 
FERC at 61,241-42; Central Hudson Gas & Electric Co. et al., 86 FERC 
at 61,218-19.
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2. Treatment of Existing Regional Transmission Entities
    We propose to adopt in the Final Rule certain characteristics and 
functions to be required of RTOs. It could turn out that the ISOs and 
any other regional transmission entities that conform to the 
Commission's ISO principles that we have approved to date do not meet 
all of these characteristics and functions. It is our expectation that, 
to the extent this is the case, the existing regional transmission 
entities will over time evolve to be consistent with the 
characteristics and functions adopted in the Final Rule. The Commission 
recognizes that a number of operational, financial and political issues 
will need to be addressed in the course of such an evolution and that 
it cannot be accomplished overnight. We also respect the investment of 
time and other resources made in the existing transmission entities, 
and understand the importance of avoiding change during the critical 
implementation period these institutions are now undergoing. Given 
these considerations, and our policy of regional flexibility, the 
proposed rule does not require major changes to the existing 
transmission entities. However, our objective is to encourage all of 
the Nation's transmission grid to be under the control of RTOs that 
have the minimum characteristics and functions adopted in the Final 
Rule. We therefore propose to require each public utility that is a 
member of an existing regional transmission entity that has been 
approved by the Commission as in conformance with the eleven ISO 
principles set forth in Order No. 888 to make a filing no later than 
January 15, 2001 that explains the extent to which the transmission 
entity in which it participates meets the minimum characteristics and 
functions for an RTO, or proposes to modify the existing institution to 
become an RTO. Alternatively, the public utility may file an 
explanation of efforts, obstacles and plans with respect to conforming 
to these characteristics and functions. 285 The Commission 
is also concerned about impediments to transactions between existing 
transmission entities, as well as any future RTOs. We therefore 
encourage existing transmission entities to consider ways to reduce any 
impediments to transactions among them and direct

[[Page 31433]]

them to provide the Commission with a progress report by January 15, 
2001.
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    \285\ Of course, there is nothing to prevent an existing 
transmission entity from making an RTO filing prior to this date if 
it so chooses.
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    The Commission seeks comment on this issue.
3. Participation by Canadian and Mexican Entities
    Canadian and Mexican involvement in RTO formation would be 
beneficial to both, as well as to the United States. In certain areas, 
``natural'' electricity trading regions already cross national borders. 
Expansion of electricity trade in the North American bulk power market 
requires that regional institutions include all market participants so 
that they may enjoy direct access to market information and the 
benefits of non-pancaked transmission rates. In addition, any 
reliability standards implemented by RTOs must be acceptable to the 
affected nations and consider all resources to avoid wasteful 
duplication of grid facilities.\286\
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    \286\ Historically, Canada and Mexico have participated in North 
American utility organizations such as NERC and Western Systems 
Coordinating Council (WSCC). Maintaining Reliability in a 
Competitive U.S. Electricity Industry, Final Report of the Task 
Force on Electric System Reliability, Secretary of Energy Advisory 
Board, DOE, September 29, 1998 at 9, 58.
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    We encourage electric utilities in Canada and Mexico, and their 
regulatory authorities, to participate in the discussions of the 
rulemaking. Perhaps what may be thought of as a ``dotted line'' RTO 
boundary could be used at international borders to indicate an 
unwillingness to artificially limit an RTO's scope while recognizing 
jurisdictional limits. The Commission emphasizes 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 countries. We invite the 
comments of Canadian and Mexican authorities on these and other issues.
4. Providing Service to Transmission-owning Utilities that do not 
Participate in an RTO
    The transmission owners that turn control of transmission 
facilities over to an RTO will help bring significant operational and 
commercial benefits to a region. To what extent should transmission 
owners who do not participate in their region's RTO share in those 
benefits? Would it 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? The 
Commission seeks comment on the treatment by an RTO of non-
participating transmission owners in the RTO region.
5. RTO Filing Requirements
    Any transfer of control of jurisdictional transmission facilities 
owned, operated, or controlled by public utilities required by RTO 
formation must be approved by the Commission pursuant to its Section 
203 authority under the FPA. The RTO transmission rates, terms, and 
conditions of service must also be approved pursuant to Section 205 of 
the FPA. We request comments on whether the Commission should provide 
for expedited or streamlined processing procedures for Section 203 
transfers of jurisdictional facilities to RTOs that meet the 
characteristics and functions of the Final Rule, and for the related 
Section 205 transmission rates, terms, and conditions. We also welcome 
specific suggestions regarding how we can further expedite or 
streamline our procedures.
6. Power Exchanges (PXs)
    Another important issue is the relationship between RTOs and power 
exchanges. Of the five ISOs approved to date, only the Midwest ISO 
chose not to include a power exchange in the design submitted to 
us.287 However, after the Commission approved this proposal, 
several ISO participants joined with other Midwestern power entities in 
issuing a public request for proposals that would create an independent 
power exchange that would operate in conjunction with the 
ISO.288 This recent Midwest initiative appears to have been 
motivated, at least in part, by the large price spikes that were 
experienced last summer. Our staff's report concluded that one of 
probable causes of the price spikes was the lack of price transparency 
and that ``centralized trading institutions such as power exchanges 
could have provided better price signals in the market and helped to 
reduce price volatility.'' 289
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    \287\ In California, PXs are operated by separate organizations 
that coordinate with the ISO.
    \288\ 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.
    \289\ Staff Report to the Federal Energy Regulatory Commission 
on the Causes of Wholesale Electric Pricing Abnormalities in the 
Midwest During June 1998, September 1998, at 4-4. Centralized power 
exchanges appear to have other benefits. Since most power exchanges 
establish credit and security standards as a condition for 
participation and reserve funds to cover defaults, they create a 
type of insurance by spreading counterparty risks among all 
participants and thereby reducing the likelihood of cascading 
transaction defaults such as those that occurred in the Midwest. In 
addition, it is generally accepted that an organized and transparent 
spot market is a prerequisite for a viable futures market which 
would allow market participants to hedge the risk of future price 
fluctuations. Finally, we note that during our recent consultations 
with state commissions, several state commissioners informed us that 
organized and open spot markets were critical to the success of 
their efforts to introduce retail competition in their respective 
states.
---------------------------------------------------------------------------

    Regions may want to consider establishing a PX that is operated by 
an RTO. However, some oppose RTO-operated PXs, contending that the two 
principal functions of PXs, market making and price discovery, are not 
natural monopoly functions.290 They also contend that power 
exchanges force market participants to buy and sell electricity using 
standardized contracts that may not meet their particular needs. They 
argue that the full benefits of electricity competition can be achieved 
only if there is competition for the market as well as in the market. 
Finally, they assert that if power exchanges are introduced, an RTO 
should be specifically prohibited from operating the exchange because 
this would compromise the RTO's independence in fulfilling its 
principal responsibilities as a transmission service provider and 
system operator.291
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    \290\ See, e.g., comments of Enron in PL98-5, Washington, D.C., 
transcript at 211.
    \291\ See, e.g., comments of Automated Power Exchange, Inc., in 
PL98-5 at 3.
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    In contrast, those who recommend that an RTO should operate a PX 
contend that the two functions of short-term forward or spot market 
operations and system operations are difficult to 
separate.292 It is their view that there will be significant 
inefficiencies unless the two functions are performed simultaneously by 
a single entity.293 In addition, they contend that there is 
no inherent conflict between the RTO as a transmission service provider 
and a spot market operator as long as the RTO has no commercial 
interest in whether prices are high or low in the markets that it 
operates.
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    \292\ See Professor William W. Hogan, ``Enabling The Power Of 
Markets,'' presentation at the EEI Chief Executive Conference, 
Scottsdale, Arizona, January 7, 1999, at 8. A copy of this 
presentation is available on Professor Hogan's website 
(www.ksg.harvard.edu/people.whogan).
    \293\ See Dr. Larry Ruff, ``Competition in Electricity: Where Do 
We Go From Here?'', lecture at the Institute of Economic Affairs, 
London Business School, October 13, 1998. Available through the 
website of the Harvard Electric Policy Group (http://
ksgwww.harvard.edu/hepg/FPpapers.html).
---------------------------------------------------------------------------

    We leave it to each region to decide whether there is a need for a 
PX and whether the RTO should operate the PX. The Commission will 
accept an RTO

[[Page 31434]]

proposal that includes a PX in its design as long as its operation of 
the PX does not compromise its independence as a transmission service 
provider. We request comments on the following questions. Given that a 
power exchange is useful, should it be part of an RTO or otherwise 
associated with an RTO? If an area has more than one PX, should the PXs 
have equal standing before the RTO? Is an organized PX necessary for 
successful retail competition? If an RTO operates congestion markets 
and balancing markets, are there efficiencies to be gained by allowing 
or encouraging the RTO to operate day ahead or hour ahead energy 
markets? Is it feasible for an RTO to operate a spot energy market 
without compromising its ability to provide non-discriminatory 
transmission service to all market participants? If a PX is operated by 
a non-RTO entity, is there a need to require certain specified forms of 
coordination between the two organizations?

I. Implementation of the Rule

    The Commission seeks to support timely RTO formation in every 
region of the country. To that end, the Commission envisions regional 
collaborations soon after issuance of the Final Rule, building on 
progress made to that date. Further, pursuant to our expectation that 
utilities and other participants in the electric industry form RTOs, 
the Commission proposes to require that certain filings be made by 
October 15, 2000 concerning RTO formation. The collaborative process 
and filing requirements are discussed in more detail below.
1. Collaborative Process
    During our consultations with the state commissions, many said that 
Commission leadership is needed to facilitate RTO formation and that 
only we could facilitate broad regional participation. To facilitate 
RTO formation in all regions of the Nation, the Commission proposes a 
collaborative process under section 202(a) to take place in the spring 
of 2000, after adoption of a Final Rule. 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.
    To assist in structuring the regional collaborations and to further 
inform the Commission on activities in each region, we propose that 
regional workshops be held throughout the Nation after the Final Rule 
is issued. The goal of these workshops would be to share information 
about the status of RTOs or RTO proposals in the region, to identify 
any impediments to RTO formation in the area, to explore what process 
could most expeditiously advance agreements on RTO formation, and to 
determine what role, if any, Commission staff should play in advancing 
discussions in the region. These regional workshops would be convened 
by Commission staff in cooperation with the affected state officials. 
The Commission would specifically invite each entity in the Nation that 
owns or operates transmission facilities, and representatives from 
Canada and Mexico as appropriate, to the public workshops. The 
Commission proposes to make staff resources, including settlement 
judges, available through our Dispute Resolution Service to assist in 
designing and possibly facilitating regional collaborations following 
the workshops. Commission technical staff will be made available for 
participation in the regional collaborations.
    Would regional workshops advance RTO formation? Under whose 
auspices should regional workshops be held? Would it be beneficial to 
have the Commission's Dispute Resolution Service staff facilitate 
discussions regarding RTO formation? Should the Commission staff 
convene the regional workshops or should Commission staff be made 
available to attend meetings convened by others? If the Commission 
staff convenes workshops, in how many cities should meetings be 
convened and how should the cities be chosen? Would the three U.S. 
interconnections be appropriate starting points? Would participation of 
Commission staff aid or stifle negotiations on RTO development?
2. Filing Requirement
    The Commission is hopeful that the direction provided by this 
rulemaking, the regional collaborations described above, and the 
possibility of incentive rate treatments will lead to the prompt 
development of RTO proposals. Thus, we propose that all public 
utilities that own, operate or control interstate transmission 
facilities (except those already participating in a regional 
transmission entity in conformance with our eleven ISO principles) 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 timetables for future efforts (see proposed 
Sec. 35.34(c)).294 To the extent possible, RTO proposals 
should include the transmission facilities of public power and other 
non-public utility entities.
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    \294\ A proposal to form a transmission institution that does 
not meet all of the minimum RTO characteristics and functions will 
not be approved as an RTO. This does not necessarily mean that the 
proposal will not otherwise be approved as consistent with the FPA. 
However, the proposal will not qualify as an RTO. For transmission 
organizations that do not meet all of the minimum RTO 
characteristics and functions, however, we would still be open to 
considering, and indeed encourage, regional filings for providing 
service at non-pancaked rates and regional congestion management 
proposals.
---------------------------------------------------------------------------

    The number and type of filings necessary to effectuate an RTO 
proposal necessarily will vary depending upon the type of RTO being 
proposed and the circumstances of each individual public utility 
participant. At a minimum, an RTO proposal must include a basic 
agreement filed under section 205 of the FPA setting out the rules, 
practices and procedures under which an RTO will be governed and 
operated, and requests by the public utility members of the RTO for 
approval under section 203 of the FPA to transfer control of their 
jurisdictional transmission facilities. However, depending upon the 
circumstances, there may need to be additional section 205 or 206 
amendments to existing public utility contracts or rate schedules in 
order to effectuate an RTO proposal.
    For those public utilities that file an RTO proposal on or before 
October 15, 2000, we will permit them to file a petition for 
declaratory order asking whether a proposed transmission entity would 
qualify as an RTO, with a description of the organizational and 
operational structure and 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 section 203, 205 and 206 filing promptly after receiving the 
Commission's determination on the declaratory order petition (see 
proposed Sec. 35.34(d)(3)). This declaratory order petition option thus 
is to be used only in conjunction with the filing of a proposal for an 
RTO that is to begin operation no later than December 15, 2001.
    If a public utility is not able to file an RTO proposal on or 
before October 15, 2000, it must alternatively file by that date a 
description of any efforts made by the public utility to participate in 
an RTO, the reasons it has not participated in an RTO, including 
identifying specific obstacles to RTO participation, and any plans and 
timetables the public

[[Page 31435]]

utility has for further work toward RTO participation (see proposed 
Sec. 35.34(f)). If a public utility makes such an alternative filing, 
the Commission at that time will determine what steps, if any, need to 
be taken.
    The above requirements, however, do not apply to a public utility 
that is a member of an existing transmission entity that the Commission 
has found to be in conformance with the Order No. 888 ISO principles. 
Rather, each such public utility must 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 for an RTO, (2) proposes to modify the existing institution 
to become an RTO, or (3) explains efforts, obstacles and plans with 
respect to conforming to these characteristics and functions (see 
proposed Sec. 35.34(g)).295
---------------------------------------------------------------------------

    \295\ Of course, there is nothing to prevent an existing entity 
from making an RTO filing prior to this date if it so chooses.
---------------------------------------------------------------------------

    The Commission does not propose to mandate RTO participation by 
rule, and instead proposes to induce voluntary participation through a 
combination of guidance on the minimum characteristics and functions of 
an RTO, possible rate incentives, a collaborative process for 
structuring regional dialogues, and filing requirements. The Commission 
seeks comment on whether the filing requirements discussed above are 
inconsistent with or otherwise would inhibit voluntary participation in 
RTOs. The Commission also seeks comment on whether it needs to 
generically mandate RTO participation by all public utilities to remedy 
undue discrimination under sections 205 and 206 of the FPA. We also 
seek comment on whether a performance based system could be designed to 
realign economic interests to remove the motive for discrimination.
    In considering what actions might be appropriate if a utility fails 
to voluntarily join an RTO, the Commission seeks comment on 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 would otherwise be in violation of the 
FPA. Does the possibility of any of these remedial actions for RTO non-
participation undermine or otherwise inhibit voluntary participation in 
RTOs? How should the Commission consider the efficiency, reliability, 
and discrimination implications of RTO non-participation? How should 
the Commission consider non-participation by utilities that constitute 
``holes'' in an RTO region?
    The Commission anticipates that public utilities will file 
proposals for ISOs, transcos, or other types of regional transmission 
institutions prior to the effective date of the Final Rule. We clarify 
that the Commission will continue to apply to these proposals the ISO 
principles contained in Order No. 888 and the case precedent 
established for ISOs. However, a public utility that files such a 
proposal prior to the effective date of the Final Rule would still be 
subject to the October 15, 2000 or January 15, 2001 filing requirement, 
as appropriate, in the Final Rule.

IV. Environmental Statement

    In furtherance of the National Environmental Policy Act of 1969, 
the staff of the Federal Energy Regulatory Commission will prepare an 
environmental assessment (EA) that will consider the environmental 
impacts of the proposed rule. A notice of intent to prepare the EA, 
request comments on the scope of the EA, and notice of a public scoping 
meeting is published elsewhere in this issue of the Federal Register.

V. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA), 5 U.S.C. Secs. 601-612, 
requires rulemakings to contain either a description and analysis of 
the effect that the proposed rule will have on small entities or a 
certification that the rule will not have a significant economic impact 
on a substantial number of small entities. If this proposed rule goes 
into effect, it will establish minimum characteristics and functions 
for RTOs, none of which is likely to meet the SBA's definition of a 
small electric utility, i.e., one that disposes of 4,000,000 MWh per 
year or less. 13 C.F.R. Sec. 121.201. Furthermore, the rule will not 
have the requisite impact upon transmission owners.
    In Mid-Tex Elec. Coop. v. FERC, 773 F.2d 327 (D.C. Cir. 1985), the 
court found that Congress, in passing the RFA, intended agencies to 
limit their consideration ``to small entities that would be directly 
regulated'' by proposed rules. Id. at 342. The court further concluded 
that ``the relevant `economic impact' was the impact of compliance with 
the proposed rule on regulated small entities.'' Id. at 342.
    The proposed rule will not regulate any small entities, nor will it 
impose upon them any significant costs of compliance. Small entities 
will be free to determine for themselves whether to participate in an 
RTO and whether any costs associated with joining an RTO will be 
adequately offset by attendant benefits. The only requirement the rule 
would impose upon a small entity would be the need to file a statement 
explaining its efforts to join an RTO, any barriers it encountered, and 
any future plans to seek to join an RTO. The Commission believes that 
the costs associated with preparing and filing such a statement will be 
minimal. Consequently, the Commission certifies that this proposed rule 
will not have a significant economic impact upon a substantial number 
of small entities.

VI. Public Reporting Burden and Information Collection Statement

    The following collections of information contained in this proposed 
rule are being submitted to the Office of Management and Budget (OMB) 
for review under Section 3507(d) of the Paperwork Reduction Act of 
1995. FERC identifies the information provided under Part 35 as FERC-
516 and under Part 33 as FERC-519.
    Comments are 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. The burden estimates for complying 
with this proposed rule are as follows:
    Public Reporting Burden: Estimated Annual Burden:

[[Page 31436]]



----------------------------------------------------------------------------------------------------------------
                                                     Number of       Number of       Hours per     Total annual
                 Data collection                    respondents      responses       response          hours
----------------------------------------------------------------------------------------------------------------
FERC-516........................................              12               1             300           3,600
FERC-519........................................          \1\ 50               1              80           4,000
                                                 ---------------------------------------------------------------
    Totals......................................  ..............  ..............  ..............           7,600
----------------------------------------------------------------------------------------------------------------
\1\ Includes respondents who make application to form an RTO and the responses of utilities who choose not to
  participate.

    Total Annual Hours for Collection (reporting+record keeping, (if 
appropriate))=7,600.
    Information Collection Costs: The Commission seeks comments on the 
costs to comply with these requirements. It has projected the average 
annualized cost for all respondents to be:
    Annualized Capital/Startup Costs--Annualized Costs (Operations & 
Maintenance) -$401,518 (7,600 hours  2080 hours per year  x  
$109,889 =$401,518). The cost per respondent is equal to $8,030 
(participants and non-participants).
    The OMB regulations require OMB to approve certain information 
collection requirements imposed by agency rule. (Footnote 5 CFR 
1320.11)
    Accordingly, pursuant to OMB regulations, the Commission is 
providing notice of its proposed information collections to OMB.
    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 proposed rule revises the 
requirements contained in 18 CFR part 35. The Commission is seeking to 
establish RTOs nationwide by December 2001. In particular, the 
Commission will establish in this proposed 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 proposed 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 Offices of Electric Power Regulation and Economic Policy 
will use the data included in filings under Section 203 and 205 of the 
Federal Power Act 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.
    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, Capital Planning and Policy Group, Phone: (202) 208-
1415, fax: (202) 208-2425, E-mail: [email protected]].
    For submitting comments concerning the collection of information(s) 
and the associated burden estimate(s), please send your comments to the 
contact listed above and 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. Public Comment Procedures

    The Commission invites interested persons to submit written 
comments on the matters and issues proposed in this notice to be 
adopted, including any related matters or alternative proposals that 
commenters may wish to discuss. Initial comments should not exceed 100 
double-spaced pages and should include an executive summary. The 
original and 14 copies of such comments must be received by the 
Commission before 5:00 p.m. on August 16, 1999.
    The Commission will also permit interested persons to submit reply 
comments in response to the initial comments filed in this proceeding. 
Reply comments should not exceed 50 double-spaced pages and should 
include an executive summary. The original and 14 copies of the reply 
comments must be received by the Commission before 5:00 p.m. on 
September 15, 1999.
    Comments should be submitted to the Office of the Secretary, 
Federal Energy Regulatory Commission, 888 First Street, N.E., 
Washington D.C. 20426 and should refer to Docket No. RM99-2-000.
    In addition to filing paper copies, the Commission encourages the 
filing of comments either on computer diskette or via Internet E-Mail. 
Comments may be filed in the following formats: WordPerfect 8.0 or 
lower version, MS Word Office 97 or lower version, or ASCII format.
    For diskette filing, include the following information on the 
diskette label: Docket No. RM99-2-000; the name of the filing entity; 
the software and version used to create the file; and the name and 
telephone number of a contact person.
    For Internet E-Mail submittal, comments should be submitted to 
``[email protected]'' in the following format. On the subject 
line, specify Docket No. RM99-2-000. In the body of the E-Mail message, 
include the name of the filing entity; the software and version used to 
create the file, and the name and telephone number of the contact 
person. Attach the comments to the E-Mail in one of the formats 
specified above. The Commission will send an automatic acknowledgment 
to the sender's E-Mail address upon receipt. Questions on electronic 
filing should be directed to Brooks Carter at 202-501-8145, E-Mail 
address [email protected].
    Commenters should take note that, until the Commission amends its 
rules and regulations, the paper copy of the filing remains the 
official copy of the document submitted. Therefore, any discrepancies 
between the paper filing and the electronic filing or the diskette will 
be resolved by reference to the paper filing.

[[Page 31437]]

    All written comments will be placed in the Commission's public 
files and will be available for inspection in the Commission's Public 
Reference room at 888 First Street, N.E., Washington D.C. 20426, during 
regular business hours. Additionally, comments may be viewed, printed 
or downloaded remotely via the Internet through FERC's Homepage using 
the RIMS or CIPS link. RIMS contains all comments but only those 
comments submitted in electronic format are available on CIPS. User 
assistance is available at 202-208-2222, or by E-Mail to 
[email protected].

List of Subjects in 18 CFR Part 35

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

    By direction of the Commission.
David P. Boergers,
Secretary.
    In consideration of the foregoing, the Commission proposes to amend 
Part 35, Chapter I, Title 18 of the Code of Federal Regulations, as set 
forth below.

PART 35--FILING OF RATE SCHEDULES

    1. The authority citation for part 35 continues to read as follows:

    Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 
U.S.C. 7101-7352.

    2. Part 35 is amended by adding a new Subpart F consisting of 
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 nondiscrimination 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 (i) of 
this section, performs the functions set forth in paragraph (j) of this 
section, and accommodates the open architecture conditions set forth in 
paragraph (k) of this section.
    (2) Market participant means any entity that buys or sells electric 
energy in the Regional Transmission Organization's region or in any 
neighboring region that might be affected by the Regional Transmission 
Organization's actions, or any affiliate of such an entity.
    (c) General rule. Except for those public utilities subject to the 
requirements of paragraph (g) of this section, every public utility 
that owns, operates or controls facilities used for the transmission of 
electric energy in interstate commerce as of [effective date of the 
final regulation] 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) A submittal consistent with paragraph (f) 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) Necessary filings, made individually or jointly with other 
entities, pursuant to sections 203, 205 and/or 206 of the Federal Power 
Act (16 U.S.C. 824b, 824d, and 824c), as appropriate, to create a new 
Regional Transmission Organization;
    (2) Necessary filings, made individually or jointly with other 
entities, pursuant to sections 203, 205 and/or 206 of the Federal Power 
Act, as appropriate, 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 (i), (j) and (k) of this section;
    (iii) A detailed description of the section 205 rates that will be 
filed for the transmission entity; and
    (iv) A commitment to make necessary filings pursuant to sections 
203, 205 and/or 206 of the Federal Power Act, as appropriate, promptly 
after the Commission issues an order in response to the petition.

    Note to paragraph (d): Under this paragraph (d), the Commission 
would consider a request for incentive rate treatment or another 
form of innovative transmission pricing, such as performance based 
rates. Such a filing must include a detailed explanation of how the 
proposed rate treatment would help achieve each of the minimum 
characteristics and functions and would result in benefits to 
consumers.

    (e) Transfer of operational control. Any public utility's proposal 
to participate in a Regional Transmission Organization filed pursuant 
to paragraph (c)(1) of this section must propose that operational 
control of that public utility's transmission facilities will be 
transferred to the Regional Transmission Organization on a schedule 
that will allow the Regional Transmission Organization to commence 
operating the facilities no later than December 15, 2001.

    Note to paragraph (e): The requirement in this paragraph (e) may be 
satisfied by proposing to transfer to the Regional Transmission 
Organization ownership of the facilities in addition to operational 
control.

    (f) Alternative filing. The submittal referred to in paragraph 
(c)(2) of this section must contain a description of any efforts made 
by that public utility to participate in a Regional Transmission 
Organization; the reasons it has not, to date, participated in a 
Regional Transmission Organization, including identification of any 
existing obstacles to participation in a Regional Transmission 
Organization; and any plans the public utility has for further work 
toward participation in a Regional Transmission Organization.
    (g) 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 [effective date of the final regulation], and that has 
filed with the Commission to transfer operational control of its 
facilities to a transmission entity that has been approved or 
conditionally approved by the Commission as being in conformance with 
the eleven ISO principles set forth in Order No. 888, FERC Stats. & 
Regs. para.31,036 (Final Rule on Open Access and Stranded Costs) on or 
before [effective date of the final regulation], must, individually or 
jointly with other entities, file with the Commission, no later than 
January 15, 2001:

[[Page 31438]]

    (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 (i) and (j) of this section and accommodates the open 
architecture conditions in paragraph (k) 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 (i), (j), and (k) of 
this section, the public utility must file either a proposal to 
participate in a Regional Transmission Organization that meets such 
requirements in accordance with paragraph (d) of this section, a 
proposal to modify the existing transmission entity so that it conforms 
to the requirements of a Regional Transmission Organization, or a 
filing containing the information specified in paragraph (f) of this 
section addressing any efforts, obstacles, and plans with respect to 
conformance with those requirements.
    (h) 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 [effective date of the final regulation], 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 (f) 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 6 months of filing the proposal.
    (i) 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 market participants.
    (i) The Regional Transmission Organization, its employees, and any 
non-stakeholder directors must not have financial interests in any 
market participants.
    (ii) A 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 to file changes to its transmission tariff 
with the Commission under Section 205 of the Federal Power Act.
    (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 effectively perform its required functions and to 
support efficient and non-discriminatory power markets.
    (3) Operational authority. The Regional Transmission Organization 
must have operational responsibility for all transmission facilities 
under its control.
    (i) The Regional Transmission Organization may choose to directly 
operate facilities (direct control), delegate certain tasks to other 
entities (functional control) or use a combination of the two 
approaches. If certain 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 responsibility will not adversely affect 
reliability or provide some market participants 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 responsibilities 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.

    Note to paragraph (i)(3)(ii): The provision in this paragraph 
(i)(3)(ii) requires that the Regional Transmission Organization 
undertake the functions in its region currently assigned to security 
coordinators by NERC in ``NERC Operating Policy 9--Security 
Coordinator Procedures.'' It is recognized that NERC ``security 
coordinators'' are relatively new and that they may not necessarily 
be permanent institutions. However, the functions NERC currently 
assigns to security coordinators are critical ones that should be 
performed by the entity with operational authority for transmission 
facilities within the region.

    (4) Short-term Reliability. The Regional Transmission Organization 
must have exclusive authority for maintaining the short-term 
reliability of the grid that it operates.
    (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.
    (j) 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. The Regional 
Transmission Organization must carry out this function by satisfying 
the standards listed in paragraphs (j)(1)(i) and (ii) of this section, 
or by demonstrating 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

[[Page 31439]]

transmission service. The Regional Transmission Organization must have 
the authority to review and approve requests for new interconnections.
    (ii) The Regional Transmission Organization tariff must not result 
in transmission customers paying multiple access charges to recover 
capital costs for transmission service over facilities that the 
Regional Transmission Organization controls (i.e, no pancaking of 
transmission access charges).
    (2) Congestion management. The Regional Transmission Organization 
must ensure the development and operation of market mechanisms to 
manage transmission congestion. The Regional Transmission Organization 
must carry out this function by satisfying the standards listed in 
paragraph (j)(2)(i) of this section, or by demonstrating 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 this 
requirement no later than one year after it commences initial 
operation.
    (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 supplier of last resort 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. The Regional 
Transmission Organization must carry out this function by satisfying 
the standards listed in paragraphs (j)(4)(i)-(iii) of this section, or 
by demonstrating 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 Stats. & 
Regs. 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 such 
markets 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. The Regional Transmission Organization must 
monitor markets for transmission services, ancillary services and bulk 
power to identify design flaws and market power and propose appropriate 
remedial actions. The Regional Transmission Organization must carry out 
this function by satisfying the standards listed in paragraphs 
(j)(6)(i)-(iv) of this section, or by demonstrating that an alternative 
proposal is consistent with or superior to satisfying such standards.
    (i) The Regional Transmission Organization must monitor markets for 
transmission service and the behavior of transmission owners, if any, 
to determine if their actions hinder the Regional Transmission 
Organization in providing reliable, efficient and nondiscriminatory 
transmission service.
    (ii) The Regional Transmission Organization must monitor markets 
for ancillary services and bulk power. This obligation is limited to 
markets that the Regional Transmission Organization operates.
    (iii) The Regional Transmission Organization must periodically 
assess 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 
conversely how Regional Transmission Organization operations affect the 
performance of power markets operated by others.
    (iv) The Regional Transmission Organization must provide reports on 
market power abuses and market design flaws to the Commission and 
affected regulatory authorities. The reports must contain specific 
recommendations about how observed market power abuses and market flaws 
can be corrected.
    (7) Planning and expansion. The Regional Transmission Organization 
must be responsible for planning necessary transmission 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. The Regional Transmission 
Organization must carry out this function by satisfying the standards 
listed in paragraphs (j)(7)(i) and (ii) of this section, or by 
demonstrating 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 RTGs where necessary.
    (iii) If the Regional Transmission Organization is unable to 
satisfy this requirement 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.
    (k) 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 (i) and (j) of this section.
    (2) Nothing in this regulation precludes an approved Regional 
Transmission Organization from seeking to evolve with respect to its 
organizational design, market design, geographic scope, ownership 
arrangements, methods of operational control and other appropriate ways 
if the changes are consistent with the

[[Page 31440]]

requirements of this section. Any future filing seeking approval of 
such changes must demonstrate that the proposed changes will meet the 
requirements of paragraphs (i) and (j) of this section and this 
paragraph (k).

    Note: The following appendixes will not appear in the Code of 
Federal Regulations.

Appendix A--Staff Summary of FERC-Industry ISO Conferences

[Docket No. PL98-5-000]

    During 1998, the Commission conducted a series of eight public 
conferences with the electric power industry for the purpose of 
examining its ISO policies. The Commission wanted to learn whether 
any changes to its policies that affect the development of ISOs and 
other forms of regional grid management structures are appropriate 
to further promote competition and reliability in bulk power 
markets. The Commission also wanted to learn whether it should also 
be more prescriptive in this area. The Commission also focused on 
the future of ISOs in administering the electric transmission grid 
on a regional basis. 1
---------------------------------------------------------------------------

    \1\ See Inquiry Concerning the Commission's Policy on 
Independent System Operators, Notice of Conference (dated March 13, 
1998), and Notice of Panels for Conference (dated April 7, 1998). 
See also, Inquiry Concerning the Commission's Policy on Independent 
System Operators, Notice of Regional Conferences (dated April 27, 
1998).
---------------------------------------------------------------------------

ISO Trust, Flexibility and Mandate

    Participants largely agreed on the need for improved regional 
organizations to operate the grid and implement reliability rules. 
They emphasized the need for transmission operations to be 
structurally independent, trustworthy, and fair in order for 
competitive generation markets to flourish. There seemed to be a 
consensus that any Commission ISO policy should be flexible to meet 
the needs and characteristics of each region and its state 
commissions, and that the Commission should avoid any one-size-fits-
all approach to ISO structure and functions that might stifle 
innovation. Participants differed, however, on whether the 
Commission should require or merely encourage ISOs.
    Reasons offered as to why the voluntary approach to ISO 
formation has not worked uniformly across the Nation included: (1) 
some states that have not yet decided on retail access believe that 
an ISO inevitably will lead to retail access; (2) some low-cost 
states are concerned that ISOs and retail access will increase their 
electric rates because utilities will be able to use ISOs to sell 
their low-cost power elsewhere; (3) some see ISOs as overly 
expensive, burdensome, and bureaucratic; and (4) some see 
transmission access as having improved enough through the on-going 
implementation of Order Nos. 888 and 889.
    Recommendations on what the Commission should do next ranged 
from wait and see, to act decisively now. Some in the first camp 
claimed that the Commission lacks the authority to mandate 
participation in ISOs. Some counseled that the Commission should 
continue to just nurture the formation of ISOs and allow development 
of organizations that best fit the local needs of a particular 
region and avoid stifling innovation by continuing the case-by-case 
approval of voluntary ISO submittals. Some suggested that the 
Commission merely define its basic objective as the availability of 
efficient and reliable transmission service on a non-discriminatory 
basis, and to encourage hold-outs to join.
    Those conference participants favoring stronger action contended 
that functional unbundling has not worked well enough and that it is 
unrealistic to expect it to do so. Many claimed that some vertically 
integrated utilities are employing preferential reliability 
practices or manipulating postings of ATC and capacity benefit 
margin values to favor their own wholesale merchant functions. They 
further claimed that there is a reluctance to lodge complaints out 
of concern that the Commission may not take strong action or there 
might be reprisals by the utilities. Others contended that some 
utilities are impeding ISO formation by refusing to participate, and 
that, as long as ISO boundaries are drawn by the voluntary decisions 
of the transmission owners to pick and choose the ISO which most 
advances their individual corporate and competitive objectives, the 
result is likely to be ISOs whose shape and composition impede its 
ability to create a true competitive market. Strong action advocates 
also seemed to be looking for clear guidance on transmission 
pricing, operation of energy markets, and the phase-in of certain 
ISO responsibilities.
    Many of those concerned about a patchwork of ISO grid coverage 
suggested that now is the time for the Commission to mandate ISOs 
(possibly tempered with incentives), or at least mandate 
participation in negotiations on ISO formation. Several suggested 
that the Commission work with the states to develop specific 
directives and guidelines as a way to assure that enough momentum on 
ISO formation is achieved. One guideline that was suggested would 
incorporate a standardized ISO tariff and a standardized set of 
rules governing reciprocity among ISOs. It would be coupled with a 
flexible ISO design that could accommodate varying regional needs. 
Others variously recommended (1) specification of minimum ISO 
functions as a basic model and letting the regions justify any 
departure therefrom; (2) ordering the formation of ISOs and allowing 
enough time for each region to develop a proposal that best suits 
its local needs; and (3) exercising all Commission authority to 
monitor and manage comprehensive ISO formation.

ISO Purposes and Functions

    The many notions about what the proper functions of an ISO 
should be seemed to reflect what each participant saw as the 
critical regional objectives (e.g., promotion of retail access; more 
efficient grid operation, planning and expansion; enhanced system 
reliability; elimination of loop flow issues; solution of ``seams'' 
problems between control areas; elimination of rate pancaking; 
improved congestion management; enhanced reserve sharing; 
establishment of one-stop shopping through creation of a regional 
OASIS; enhanced market monitoring, and improved real-time 
communication among all transmission entities). Accordingly, 
suggested ISO functions included: control area responsibilities; 
numerous security coordinator and reliability duties; impartial 
operation of a regional OASIS to improve ATC postings; 
administration of an ISO-wide tariff; generation redispatch duties 
to relieve congestion; and ancillary services markets coordination 
responsibilities.
    Some participants argued, however, that certain functions should 
not be foisted upon ISOs. Some contended that it would be 
detrimental to the markets and the administration of ISOs if ISOs 
become involved with functions that are not natural monopolies such 
as power exchange activities because this would compromise the ISO's 
independence in fulfilling its primary transmission 
responsibilities. Many cautioned that an ISO should not be involved 
in market monitoring beyond data gathering tasks, due to the 
attendant administrative burden and cost, and because enforcement 
should be the sole prerogative of regulatory authorities.

ISO Size

    Most participants agreed that, as a general proposition, bigger 
ISOs can be more effective than smaller ISOs, given the growth in 
unbundled power sales and the lessening of traditional cooperation 
among utilities that have now become competitors. For example, with 
regard to the connection between size and effective reliability 
management, it was pointed out that an excessive number of control 
areas in the Midwest has inhibited communication and coordination, 
and contributed to several of the Midwest's recent reliability 
``near misses.''
    Basically, participants saw the ``proper'' size as depending 
upon a number of factors: (1) The purposes and functions of the ISO 
(such as enhancing reliability or accommodating regional power 
markets); (2) the operating characteristics and make-up of the local 
regional transmission system; (3) being large enough to capture 
scale economies yet not too big to operate without difficulty and 
handle large volumes of next-hour transactions; (4) recognizing 
historic coordination arrangements, trading patterns, and load 
patterns; and (5) remaining responsive to local transmission 
concerns and conventions on such matters as how wide an area over 
which costs associated with transmission construction and generation 
redispatch should be spread.

Alternatives to ISOs

    A number of participants counseled that the Commission should 
seriously consider alternatives to ISOs such as investor-owned 
transcos, and independent grid administrators or schedulers (IGA or 
ISA).
    IGA/ISA supporters were concerned about what could be quickly 
implemented that would avoid the high costs that seem to be 
associated with comprehensive ISO initiatives, yet would provide 
immediate control over the more egregious actions of some 
transmission providers. IGA/ISA structures were described to include 
any of the following: (1) One-stop shopping through an OASIS that 
uniformly calculates ATC

[[Page 31441]]

values; (2) independent coordination of reservations and power flow 
scheduling; and (3) fast-track dispute resolution. It was claimed 
that such structures would avoid cost-shifting controversies and 
congestion management complications because the IGA/ISA members 
would continue to operate their own transmission and set their own 
individual rates. While there was some support for IGA/ISA 
structures as an interim step toward full ISO formation, many 
participants expressed concern about the Commission approving 
``watered-down'' versions of an ISO that fail to address pressing 
needs for grid expansion and pricing reform.
    Transco supporters argued that a transco can offer everything 
that a full ISO can provide, plus the additional efficiency that is 
inherent in combining operation and ownership of transmission assets 
driven by the same corporate and market incentives. Transcos were 
also said to provide more opportunity for shareholders to benefit 
from the strong performance of any facilities placed under an ISO. 
As such, transcos were touted as the natural end-state of 
transmission restructuring. ISO supporters countered that the ISO 
structure need not foreclose passing incentive-rate revenues on to 
transmission owners. They also claimed that, unlike a transco, an 
ISO is not dependent upon the successful transfer of all of the 
transmission assets within a region and, if an ISO is sized wrong, 
it can be more readily corrected than a transco for the same reason.
    Finally, some participants suggested that ISOs and transcos are 
actually complementary forms. Others claimed that who owns the 
transmission is irrelevant as long as the regional grid operator is 
independent; it is big enough to internalize loop flows; it directs 
region-wide transmission planning; and it allows for competitive 
bidding on the installation of new facilities to expand the grid.

ISO Pricing and Cost-shifting Concerns

    Some participants supported differing forms of ISO rate 
structures: flow-based rates, distance-based pricing, average-cost 
based rates, and locational marginal cost-based pricing. Many 
cautioned that a Commission mandate on the use of any particular 
tariff structure would be a major obstacle to the voluntary 
formation of ISOs; therefore, they recommended that the Commission 
provide great deference to the needs of each region as to what 
locally is seen to be fair and reasonable pricing.
    In particular, many participants raised concerns about cost-
shifting within an ISO that might result from membership with 
significantly disparate embedded transmission costs and imposition 
of an ISO-wide access tariff that reflects some composite of such 
costs. These participants counseled that the Commission should allow 
``license plate'' access rates that reflect only the cost of the 
transmission zone within the ISO in which the load to be served is 
located. One participant suggested, however, that even license plate 
rates can raise cost-shifting concerns, if the cost of an upgrade 
that is used primarily for the benefit of external loads is included 
in the cost basis for the affected zone.

Non-jurisdictional Transmission Participation

    Most participants expressed the view that government-owned and 
other regional non-jurisdictional transmission owners need to fully 
participate in an ISO in order for it to be completely successful. 
It was suggested that this is especially true for the West, where 
large amounts of non-jurisdictional transmission is controlled by 
Bonneville Power Administration, Western Area Power Administration, 
Southwestern Power Administration, large municipals, cooperatives, 
public power districts, British Columbia Hydro, and the Alberta 
grid. Some participants wanted the Commission to provide guidance on 
how to bring public power and other non-jurisdictional transmission 
owners into an ISO. In this regard, some suggested that the 
Department of Energy needs to issue guidance to the federal power 
marketing agencies on their active support of any ISO initiatives. 
Public power participants, who strongly supported ISOs, expressed 
concern that any ISO participation on their part could adversely 
affect the financing of their facilities due to Internal Revenue 
Code ``private-use'' restrictions.

Existing Transmission Contracts

    Some participants emphasized the need for ISOs to honor 
(grandfather) existing transmission contract arrangements to 
maintain any benefits that were bargained. Others emphasized the 
need for ISOs to abrogate any existing transmission contracts to 
eliminate any preferential transmission treatment. Those favoring 
grandfathering, however, acknowledged that it could become a very 
complicated administrative matter in the event that there is 
insufficient transmission capacity to serve everyone.

Panelists

    The Commission held conferences in Washington, D.C. and in seven 
cities in different regions of the country.

Washington, D.C.

    In the lead-off two-day conference held on April 15-16, 1998, in 
Washington, D.C., approximately 400 individuals attended each day. 
Panelists represented:

American Electric Power Company
American Public Power Association
California Independent System Operator
California Independent System Operator, Market Surveillance 
Committee (by Stanford University)
California Public Utilities Commission
Cameron McKenna LLP
Cinergy Energy Services, Inc.
Commonwealth Edison Company
Coalition For A Competitive Electric Market (by Enron Corporation)
Economic Analysis Group
Edison Electric Institute
Edison Electric Institute (by NERA)
Electric Power Supply Association.
Entergy Services, Inc.
Harvard University (John F. Kennedy School of Government)
Industrial Consumers (by Electricity Consumers Resource Council)
ISO New England
Members Systems of the New York Power Pool (by Putnam, Hayes & 
Bartlette, Inc.)
Mid-Continent Area Power Pool (by Morgan, Lewis & Bockius)
Montana Power Company
National Association of Regulatory Utility Commissioners (by Iowa 
Utilities Board)
National Rural Electric Cooperative Association
NGC Corporation
Pennsylvania Public Utility Commission
PJM Interconnection, L.L.C.
Public Utilities Commission of Ohio
Public Service Commission of the State of New York
Rhode Island Public Utilities Commission
Secretary of Energy's Task Force on Electric System Reliability
Sithe Energies, Inc. (By Economics Resource Group)
Transmission Access Study Group (by Wisconsin Public Power, Inc.)
Transmission Alliance (by Merrill Lynch)
Transmission Dependent Utility Systems (by Arkansas Electric 
Corporation
U.S. Department of Justice
U.S. Generating Company and PJM Supporting Companies (by Steptoe & 
Johnson LLP)
Wabash Valley Power Association, Inc.
Wisconsin Electric Power Company

Phoenix

    Almost 90 people attended the May 28, 1998, Phoenix conference. 
Panelists represented:

Arizona Corporation Commission
Arizona Public Service Company
Automated Power Exchange, Inc.
California ISO
Desert STAR
K.R. Saline & Associates
Colorado Springs Utilities
Cyprus Climax Metals, BHP Copper, Phelps Dodge, ASARCO and Motorola 
(by Energy Strategies, Inc.)
Goldman Sachs & Co.
Northern California Power Agency.
Salt River Project Agricultural Improvement and Power District
Southwest Power Trading Council (by Enron Corp.)
Tri-State Generation and Transmission Cooperative, Inc.

Kansas City

    About 90 people attended the May 29, 1998, Kansas City 
conference. Panelists represented:

City Utilities of Springfield, Missouri
Clarksdale Public Utilities Commission
Cooperative Power Association
Iowa Utilities Board
Kansas Corporation Commission
Mid-America Regulatory Conference (by Kansas Corporation Commission)
Midwest Coalition for Effective Competition (by MCES and 
Environmental Law and Policy Center)
Midwest ISO Participants (by Wisconsin Electric Power Company and 
Ameren Services)
Minnesota Department of Public Service

[[Page 31442]]

Missouri Office of Public Counsel
Missouri Public Service Commission
Nebraska Public Power District
Northern States Power Company
Public Utility Commission of Texas
Shook, Hardy, Bacon, LLP
Southwest Power Pool

New Orleans

    The June 1, 1998, New Orleans conference panelists represented:

Arkansas Electric Cooperative
Entergy Corporation
Gulf Coast Power Marketers Coalition
Houston Industries Power Corporation, Inc.
Lafayette Utilities System
Louisiana Energy Users Group
Public Service Commission of Yazoo City, Mississippi
Southern Company Services, Inc.
Southwest Power Pool
Southwestern Public Service Company

Indianapolis

    About two hundred people attended the June 4, 1998, Indianapolis 
conference. Among the panelists represented:

AMEREN
American Municipal Power of Ohio
Cinergy Services Inc.
Citizens Action Coalition of Indiana
Consumers Energy Company
Detroit Edison Company
Energy Michigan
FirstEnergy Corporation
Illinois Industrial Energy Consumers
Indiana Municipal Power Agency
Indiana Utility Regulatory Commission
Kentucky Public Service Commission
Madison Gas and Electric Company
Mid-America Regulatory Commissioners (by Michigan Public Service 
Commission)
Midwest Coalition for Effective Competition
Midwest ISO Participants
Michigan Public Power Agency
Minnesota Public Utilities Commission
Public Utilities Commission of Ohio
Wisconsin Electric Power Company

Portland

    About 160 people attended the June 5, 1998, Portland conference. 
Panelists represented:

Automated Power Exchange
Bonneville Power Administration
California ISO
California Municipal Utilities Association
California Public Utilities Commission
Chelen County PUD (on behalf of Independent Grid Scheduler)
CIBC Oppenheimer Corp.
Columbia Falls Aluminum Company, et al.
Idaho Power Company
Idaho Public Utilities Commission
Industrial Customers of Northwest Utilities
Land and Water Fund of the Rockies Energy Project
Montana Department of Environmental Quality
Montana Power Company
Northern California Power Agency.
Oregon Public Utilities Commission
Pacific Northwest Generating Cooperative
PacifiCorp
Platte River Power Authority
Public Power Council
Public Service Company of Colorado
Puget Sound Energy, Inc.
Transmission Agency of Northern California
Turlock Irrigation District
University of California
Washington Utilities and Transportation Commission
Western Power Trading Forum
Western Regional Transmission Association

Richmond

    About 55 people attended the June 8, 1998, Richmond conference. 
Panelists represented:

Blue Ridge Power Agency
LG&E Energy (on behalf of Midwest ISO Participants)
Mid-Atlantic Power Association
North Carolina Electric Membership Corporation
Old Dominion Electric Cooperative
TransEnergie U.S., Ltd.
Virginia State Corporation Commission
Virginia Committee for Fair Utility Rates and Old Dominion Committee 
for Fair Utility Rates
Virginia Electric & Power Company

Orlando

    The June 8, 1998, Orlando conference was attended by about 100 
people. Panelists represented:

Dynergy
Enron Power Marketing (by Basford & Associates)
Florida Municipal Power Agency
Florida Power & Light Company
Florida Power Corporation
Florida Public Service Commission
Florida Reliability Coordinating Council, Inc.
Morgan Stanley & Company
Municipal Electric Authority of Georgia
National Grid Company of England and Wales
Seminole Electric Cooperative, Inc.

Other Commenters

Alabama Electric Cooperative, Inc.
Allegheny Power, et al.
Barbara R. Barkovich
California Department of Water Resources
California Electricity Oversight Board
California Independent Energy Producers Association
Central Illinois Light Company
Citizens Group Responsible Use of Rural & Agricultural Land
Commonwealth of Pennsylvania Utility Commission
Commonwealth of Virginia, Division of Energy Regulations
Commonwealth of Virginia State Corporation Commission
Consumer Counsel Office of the Attorney General of Virginia
Consumers Energy Company
Cooperative Power Association
CSW Operating Companies
CSX Transportation
D. Basford & Associates, Inc.
Dairyland Power Cooperative
Department of Energy, Bonneville Power Administration
Desert Southwest Power Trading Council
Dominion Resources Inc.
Economic Resources Group, Inc.
Electricities of North Carolina, Inc.
Electricity Consumers Resource Council, et al.
Energy Strategies, Inc.
Fiona Woolf
Georgia System Operations Corporation, et al.
Goldman, Sachs & Company
Gregory J. Werden
Gridco Commenters
Houston Industries, Inc.
IES Utilities Inc., et al.
Illinois Commerce Commission
Independent Grid Scheduler Organizing Group
Independent Power Producers of New York, Inc.
Indiana Energy Michigan
Indiana Office of Utility Consumer Counsel
Kentucky Utilities Company
Kentucky Public Service Commission
Large Public Power Council
Marija D. Ilic
Mid-Atlantic Public Service Commissions
Midwest Independent Transmission System Operator, Inc.
Midwest Municipal Intervenors, et al.
Minnesota Power Company
Minnesota Public Utilities Commission
Mississippi Office of Public Counsel
Montana Public Service Commission
Multiple Public Interest Organizations
New York Mercantile Exchange
New Mexico Industrial Energy Consumers
Northern Indiana Public Service Company
Northwest Power Plant Planning Council
Oak Ridge National Laboratory
Office of Ohio Consumers' Counsel
Oklahoma Corporation Commission
Oklahoma Gas and Electric Company
Orange & Rockland Utilities
Oregon Public Utilities Commission
Otter Tail Power Company
Pacific Gas & Electric Company
PECO Energy Company
Pennsylvania Office of Consumers Advocate
PJM Supporting Companies
Portland General Electric Company
Powersmiths International, Inc.
Project For Sustainable FERC Policy
ProLiance Energy, LLC
Public Service Commission of Wisconsin
Public Service Electric & Gas Company
Public Utilities Board of the City of Brownsville, Texas
Public Utility District No. 1 of Chelan County, Washington
Selkirk Cogen Partners, L.P.
Sierra Pacific Power
Southern California Gas Company, et al.
Southwest Transmission Dependent Utility Group
Staff of Bureau of Economics of the Federal Trade Commission
State of California Public Utilities Commission
State of Florida Public Service Commission
State of Idaho & Idaho Public Utilities Commission
State of Kansas Citizens' Utility Ratepayer Board's
State of Minnesota Public Utilities Commission
State of Montana Department of Environmental Quality
State of New York Public Service Commission
State of Rhode Island and Province Plantations

[[Page 31443]]

The Williams Companies Inc.
Transmission Operators of Public Service Company of Colorado
Tucson Electric Power Company
University of Arizona
Virginia Committee for Fair Utility Rates, et al.
Washington Department of Community, Trade and Economic Development 
Energy Policy Group
Western Area Power Administration
Wisconsin Intervenors
Wisconsin Public Power, Inc.
Wisconsin Public Service Corporation

Appendix B--Staff Summary of FERC Consultations With the States

[Docket No. RM99-2-000]

    In Docket No. RM99-2-000, as part of a broader inquiry into its 
RTO policies, the Commission held a series of three regional 
conferences to elicit the views and recommendations of state 
regulatory authorities with respect to the development of 
independent RTOs and whether and how it should use its authority 
under section 202(a) of the Federal Power Act.\1\ The Commission 
also wanted to learn whether the goals of full competition and non-
discriminatory transmission access can be achieved in the absence of 
broad participation by transmission-owning utilities in RTOs. 
Conferences were held in St. Louis, Las Vegas, and Washington, D.C. 
in February 1999.
---------------------------------------------------------------------------

    \1\ See Regional Transmission Organizations, Notice Of Intent To 
Consult Under Section 202(a) dated November 24, 1998, and Notice Of 
Dates And Locations For Consultation Sessions With State Commissions 
(dated January 13, 1999).
---------------------------------------------------------------------------

Need for Commission Mandate

    There was little real dispute by participants over the need for 
independent and impartial regional grid management, whether it be 
for improved grid operation, increased reliability, identifying 
promising new generation locations, broadening markets by reducing 
rate pancaking, or all of these. Most of the states also recognized 
that the Commission is the necessary and appropriate facilitator for 
forming RTOs, due to its broad jurisdiction. However, comments as to 
how best the Commission should proceed next were mixed.
    One state wondered whether the Commission has the authority to 
mandate RTOs. Several Northeastern and Mid-Atlantic states that 
already have strong ISOs were concerned that the Commission might 
disturb their ISOs before an adequate period of time has elapsed to 
reveal their strengths and weaknesses. One state suggested that the 
Commission should look into setting up a joint board of state and 
federal regulators on RTO issues. Some Southeastern states saw no 
need for a Federal policy on RTOs right now. They felt that the grid 
is operated adequately and preferred to let the market sort RTO 
developments.
    States west of the Appalachians generally recognized the need 
for structural independence of transmission through RTOs beyond 
functional unbundling sooner rather than later and saw a need for 
strong Commission leadership on RTO formation. They differed on the 
urgency and the necessary extent of Commission involvement. Many of 
the states advocating a more aggressive role were located in the 
Midwest, which had experienced price spikes during the summer of 
1998.
    One state insisted that Commission action is needed to quicken 
the pace of RTO formation so that development of competitive 
electricity markets is not delayed. One vigorously complained about 
the persistent lack of fuller RTO participation in the Midwest and 
the possible strategic advantage to vertically integrated utilities 
not participating. To counter the fragmentation in the Midwest, it 
recommended that the Commission mandate utility participation or, at 
a minimum, eliminate pancaked transmission rates within each 
regional reliability council. Another suggested that the Commission 
interpret any utility's refusal to join an RTO as an indicator of 
undue discrimination. One recommended that the Commission strongly 
promote fuller participation in RTOs by using a combination of 
``carrots'' and ``sticks'' as incentives.

Flexibility

    A pervasive theme was the need for the Commission to avoid 
taking a one-size-fits-all approach to RTOs. Many states recommended 
that, if the Commission wants to establish RTO policy pursuant to 
its section 202(a) authority, the policy must be implemented in a 
way that adequately recognizes any regional differences in industry 
structures. One Midwestern state counseled that the Commission 
should partner with the states to develop a memorandum of 
understanding (MOU) on regional transmission matters. The MOU would 
outline common desires and objectives, describe the regulatory tools 
to get there, and the circumstances under which the tools would be 
used.
    Other states suggested that the Commission, before it considers 
taking any stronger action, issue guidelines and allow enough time 
for each state to determine which are appropriate for it in forming 
regional RTOs. The guidelines would reflect determinations on such 
issues as how to encourage participation by and otherwise deal with 
non-jurisdictional transmission entities; whether to allow a state 
to opt out of a mandatory RTO policy; and how to ensure that no 
state's economy is harmed by an RTO. Several states suggested that 
cost/benefit analyses be done for each region. Finally, numerous 
states recommended that the Commission not mingle retail competition 
issues with RTO issues, contending that retail choice is a state 
prerogative.

RTO Size

    Several states were concerned about how large is large enough 
for an RTO, and how the Commission expects to set the proper 
regional boundaries. In the East, states served by established ISOs 
expressed concern that their ISOs might have to incur additional 
costs for modifications that might be required to meet a potential 
Commission size criterion before market forces have had the chance 
to suggest an appropriate size. Some suggested that because the 
existing ISOs are so crucial to promoting retail competition in 
states that have already adopted retail choice, the Commission 
should carefully consider any order that would expand, merge, or 
restructure an existing ISO. Some states cautioned that expanding 
their existing ISOs beyond a certain point might also lead to 
reliability problems or inheriting problems from adjacent regions.
    One state recommended that only minimum size criteria be 
established rather than the specific locations of boundaries. Other 
states recommended that, if the Commission insists on establishing 
regional boundaries, that it consider the relative costs and 
benefits of an RTO sized according to each regional boundary set. 
One state suggested that the Commission rely on the existing NERC 
regional councils as the starting point for determining proper RTO 
boundaries. Another state suggested that the Mid-Continent Area 
Power Pool (MAPP) and Mid-American Interconnected Network (MAIN) 
interfaces should be placed within a single RTO. Some western states 
contended that, while only one regional reliability council serves 
the West, many non-jurisdictional cooperative and government 
utilities control such a substantial amount of transmission that 
creating RTOs in the West will be difficult absent clear direction 
from the Commission.

Alternative Forms of RTOs

    While several states argued that competing ISO and transco 
structures could lead to further fragmentation and limited RTO 
operations, others argued that mandating specific forms of RTOs now 
would impede the ability of the states and regions to adopt models 
that are best suited for their particular needs and that the 
Commission should not lock in particular RTO structures but should 
instead retain flexibility to address changing future needs. One 
state favored a non-profit ISO structure, because it doubted that 
the industry would lend itself to the development of any transco 
with sufficient geographic coverage and adequate independence from 
generation interests. It noted, however, that if a for-profit 
transco could meet the size and independence criteria, the transco 
would have advantages over an ISO in the form of a stronger business 
orientation and superior access to capital for grid expansion.

Transmission Cost Shifting and Low Power Cost States

    Many states counseled that the Commission should allow a region 
to opt-out of an average cost based RTO-wide rate, if such a rate 
would shift highly disparate embedded transmission costs among its 
RTO customers and force some to suffer transmission rate increases. 
Many western states suggested that concern over the enhanced ability 
of utilities to export their low cost power to other regions through 
an RTO, as well as concerns about transmission cost shifting, not 
only led to the demise of the IndeGo ISO but has thwarted further 
RTO development in the West.

[[Page 31444]]

Panelists

St. Louis

    About 120 people attended the February 11, 1999, conference in 
St. Louis. Panelists represented commissions in:

    Arkansas
    Florida
    Illinois
    Indiana
    Iowa
    Kansas
    Kentucky
    Michigan
    Minnesota
    Missouri
    Nebraska
    North Dakota
    Ohio
    Oklahoma
    South Dakota
    Tennessee
    Texas
    Wisconsin

Las Vegas

    About 96 people attended the February 12, 1999, conference held 
in Las Vegas. Panelists represented commissions in:
    Arizona
    California
    Colorado
    Idaho
    Montana
    Nevada
    New Mexico
    Oregon
    Utah
    Washington
    Wyoming

Washington, D.C.

    The panelists at the February 17, 1999, conference in 
Washington, D.C. represented commissions in:

    Alabama
    Connecticut
    District of Columbia
    Georgia
    Maryland
    Massachusetts
    Mississippi
    New Jersey
    New York
    North Carolina
    Pennsylvania
    Rhode Island
    West Virginia

Other Commenters

Canadian Electricity Association
ISO New England
Mid-American Regulatory Commissioners
National Association of Regulatory Utility Commissioners
New England Conference of Public Utilities Commissioners, Inc.
Regional Electric Power Cooperation
Virginia State Corporation Commission
Western Interstate Energy Board

Appendix C--Existing Configurations

    This Appendix depicts the three existing configurations 
discussed in Section III.D.2: the three electric interconnections 
within the continental United States, the ten NERC reliability 
councils, and the twenty-three NERC security coordinator areas.

[The attachments to this Appendix are available for public 
inspection and copying during normal business hours in the Public 
Reference Room at 888 First Street, N.E., Room 2A, Washington, D.C. 
20426, and through the Commission's Records and Information 
Management System (RIMS). RIMS is available remotely via Internet 
through FERC's Home page using the RIMS link or the Energy 
Information Online icon.]

[FR Doc. 99-12553 Filed 6-9-99; 8:45 am]
BILLING CODE 6717-01-P