[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]]
_______________________________________________________________________
Part III
Department of Energy
_______________________________________________________________________
Federal Energy Regulatory Commission
_______________________________________________________________________
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
[[Page 31390]]
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
[[Page 31392]]
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
[[Page 31393]]
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.
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The transition to new market structures has resulted in new
challenges and circumstances. For example, during the week of June 22-
26, 1998, the wholesale electric market in the Midwest experienced
numerous events that led to unprecedented high spot market prices. Spot
wholesale market prices for energy briefly rose as high as $7,500 per
MWh, compared 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
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\22\ Id. at v.
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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.
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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.
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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
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\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
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\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
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\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
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\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).
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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).
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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).
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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.
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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
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\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.''
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\50\ 63 FR 53889 (1998).
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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
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\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).
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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
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\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
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\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.
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\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.
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* * * 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.
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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.
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\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.
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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.
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\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.
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\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).
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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
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\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.
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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.
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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\
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\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).
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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
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\100\ Comments of Frank Ledoux on behalf of Lafayette Utilities
System, Regional ISO Conference (New Orleans), Transcript at 180.
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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
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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.
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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).
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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).
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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
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\105\ 83 FERC para. 61,198 (1998), order on reh'g, 84 FERC para.
61,120 (1998).
\106\ 83 FERC at 61,860.
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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.
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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.
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\108\ 83 FERC para. 61,204, order granting clarification and
dismissing reh'g, 83 FERC para. 61,299 (1998).
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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
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\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).
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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.
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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.
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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
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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.
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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.
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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.
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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).
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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
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\119\ Id. at 8.
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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.''
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\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).
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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.
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\121\ NERC, Available Transfer Capability Definitions and
Determinations (June 1996), at 14.
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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
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\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).
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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.
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\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
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\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).
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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.
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\129\ Petition at 15.
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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
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\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).
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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.
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\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
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\135\ Comments of Marvin Carraway on behalf of Clarksdale Public
Utilities Commission, Regional ISO Conference (Kansas City),
Transcript at 107.
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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.
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[[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).
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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
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\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.
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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.
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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
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\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.
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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
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\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.
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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.
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\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.
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\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.
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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.
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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
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\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).
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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.
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\156\ Appropriate price regulation of RTOs would still be
needed.
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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
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\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.
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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
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\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..
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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.
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\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.
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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
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\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?
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\162\ See PJM, 81 FERC at 62,269.
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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
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\163\ See Transmission Pricing Policy Statement, FERC Stats. &
Regs. at 31,145, 31,148.
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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.
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\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.
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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.
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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.
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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.
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\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.
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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.
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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.
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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.
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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.
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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.
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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.
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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.
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\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.
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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))
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\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.
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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
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\203\ Midwest ISO, 84 FERC at 62,156-60, 62,181.
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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.
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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.
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\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.
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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
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\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
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\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
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\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.
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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.
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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.
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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
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\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.
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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.
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\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.
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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.
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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?
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\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.
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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.
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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.
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\224\ Order No. 888, FERC Stats. & Regs. at 31,666-67.
\225\ CRT NOPR, FERC Statutes and Regulations at 33,228 (1996).
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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).
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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.
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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.
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\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?
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\229\ See Response of Midwest ISO Participants, May 1, 1998, at
11-13.
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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
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\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.
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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.
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\233\ See, e.g., PJM, FERC 62,252-53.
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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.
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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.
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\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
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\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.
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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
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\239\ See Indiana Michigan, 64 FERC at 62,554.
\240\ NERC, 85 FERC at 62,363-64.
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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.
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\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.
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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.
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\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
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\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).
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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\
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\250\ See Midwest ISO, 84 FERC at 62,159-160.
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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
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\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.
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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.
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\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.
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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.
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\256\ This is the same requirement that the Commission imposed
on the Midwest ISO. See Midwest ISO, 84 FERC at 62,154.
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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.
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\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).
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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?
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\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.
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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
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\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.
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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.
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\263\ See AES Redondo Beach, et al., 85 FERC para. 61,123 at
61,453 and 61,459-460 (1998).
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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?
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\264\ See, e.g., David B. Raskin, ISOs; The New Antitrust
Regulators? The Electricity Journal (April 1998).
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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.
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\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.
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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?
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\267\ Pacific Gas & Electric, 77 FERC para. 61,265 (1996).
NEPOOL, 85 FERC para. 61,379 (1998).
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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.
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\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?
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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.
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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.
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\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.
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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.
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\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).
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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.
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\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).
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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.
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\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?
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\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.
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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).
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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.
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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
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\295\ Of course, there is nothing to prevent an existing entity
from making an RTO filing prior to this date if it so chooses.
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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